ML20054C100
| ML20054C100 | |
| Person / Time | |
|---|---|
| Site: | 05000470 |
| Issue date: | 03/31/1982 |
| From: | ABB COMBUSTION ENGINEERING NUCLEAR FUEL (FORMERLY |
| To: | |
| Shared Package | |
| ML20054C091 | List: |
| References | |
| NUDOCS 8204200033 | |
| Download: ML20054C100 (700) | |
Text
Insert / Remove Instructions (Sheet 1 of 6)
AMENDMENT NUMBER 7 CESSAR-F C/ Docket STN-50-470F The following sheets of CESSAR-F are to be inserted.
REMOVE THE FOLLOWING INSERT THE FOLLOWING Listing of Amendments Listing of Amendments The following sheets of CESSAR-F Chapter 1 are to be removed and inserted.
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The following sheets of CESSAR-F Chapter 2 are to be inserted.
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Effective Page Listing Appendi x 3.11 A, 3.11B, Effective Page Listing Appendix 3A Table of Contents Table of Contents vi, xii, xiv vi, xii, xiv List of Tables List of Tables xv xv Text Text 3.2-3, 3.9-40 through 3.9-45, 3.2-3, 3.9-40 through 3.9-3.11-1 through 3.11-7 44, 3.9-44a, 3.9 44b, 3.9-44c, 3.9-45, 3.11-1 through 3.11-4, 3.11-4a, 3.11-5, 3.11-6, 3.11-7 Tables Tables 3 . 2- 1 Sheets 1 to 6) 3.2-1 (Sheets 1-20) g\ 3.5-1 Sheet 1), 3.9.3-3 3.5-1 (Sheet 1), 3.9.3-3
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( Appendi x 3.ll A) iii iii Text (Appendix 3.ll A) Text (Appendix 3.llA) 3.11 A-1 through 3.ll A-4 3.11 A-1 through 3.11 A-2 Tables (Appendix 3.llA) Tables ( Appendix 3.11 A) 3.llA-1 (Sheets 1 to 3) 3.ll A -1 through 3.11 A-14 Figures (Appendix 3.ll A) Figures (Appendix 3.11A) 3.11 A-1 through 3.ll A-5 3.11 A-1 A , 3.11 A-1B , 3.11 A-2 through 3.11A-5, 3.11A-6A, 3.11A-6B, 3.llA-7 through 3.11A-10 Tables (Appendix 3.118) Tables (Appendix 3.118) 3.11B-1 (Sheets I through 6) 3.11B-1 (Sheets 1 through 7)
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'xj 4.2-4, 4.2-5,4.2-15 4.2-16,4.2-26,4.2-27,4.2-30 through
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Text Text 6.3-2,6.3-13 6.3-2,6.3-13 Tables Tables 6.2.4-1 (Sheet 4 of 5) 6.2.4-1 (Sheet 4 of 5)
Figures Figures 6.3.2-1A, 6.3.3.2-SP 6.3.2-1 A , 6.3.3.2-5P The following sheets of CESSAR-F Chapter 7 are to be removed and inserted.
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Table of Contents Table of Contents xii,xvi, xvii xii, xvi, xvii Text Text 7.2-4, 7.7-8 7.2-4, 7.7-8, 7.7-8a, 7.7-10a Tables Tables 7.6-1 7.6-1 Figures Figures 7.7-10 The following sheets of CESSAR-F Chapter 8 are to be removed and inserted.
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Figures Figures 9.3-1 9.3-1 The following sheets of CESSAR-F Chapter 10 are to be removed and inserted.
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Appendix 11.1-A Table of Contents Table of Contents i i Text Text 11.1-13 11.1-13 The following sheets of CESSAR-F Chapter 12 are to be removed and inserted.
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Text Text 14 . 2-87 ,14 . 2- 99 a ,14 . 2- 100 14. 2-87 ,14. 2-99a ,14 . 2- 100 The following sheets of CESSAR-F Chapter 15 are to be removed and inserted.
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The following sheet of CESSAR-F Chapter 17 is to be inserted.
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O Amendment No. 7 March 31, 1982
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TABLE OF CONTENTS (Cont'd.)
() CHAPTER 3 V
Section Subject Page No.
3.5.3* BARRIER DESIGN PROCEDURES 3.5-2 3.5.3.1 Missile Barrier Design Interface Requirements 3.5-2 3.6 PROTECTION AGAINST DYNAMIC EFFECTS ASSOCIATED 3.6-1 WITH IHE POSTULAIED RUPTURE OF PIPING 3.6.1 POSTULATED PIPING FAILURES IN FLUID SYSTEMS 3.6-1 OUTSIDE OF CONTAINMENT 3.6.1.1 Design Bases 3.6-1 3.6.1.1.1 High Energy Piping Systems 3.6-1 3.6.1.1.2 Moderate Energy Piping Systems 3.6-2 3.6.1.2 Description 3.6-2 3.6.2 DETERMINATION OF BREAK LOCATIONS AND DYNAMIC 3.6-2 EFFECTS ASSOCIATED WITH THE POSTULATED RUPTURE OF PIPING (3 3.6.2.1 Criteria Used to Define Break and Crack 3.6-2a
(' l6 Location and Configuration 3.6.2.2 Analytical Methods to Define Forcing 3.6-5 Functions and Response Models 3.6.2.3 Dynamic Analysis Methods to Verify Integrity 3.6-5 and Operabi1ity 3.6.2.4 Guard Pipe Assembly Design Criteria 3.6-5 3.6.2.5 Material Submitted for the Operating 3.6-5 License Review 3.7 SEISMIC DESIGN 3.7-1 3.7.1 SEISMIC INPUT 3.7-1 3.7.1.1 Design Response Spectra 3.7-1 3.7.1.2* Design Time History 3.7-1 3.7.1.3 Critical Damping Values 3.7-i
! 3.7.1.4 Supporting Media for Category I Structures 3.7-1 10
'd Amendment No. 6 November 20, 1981
- See Applicant's SAR v
TABLE OF CONTENTS (Cont'd.)
CHAPTER 3 Section Subject Page No.
3.7.2 SEISMIC SYSTEM ANALYSIS 3.7-2 3.7.2.1 Reactor Coolant System 3.7-2 3.7.2.1.1 Introduction 3.7-2 3.7.2.1.2 Mathematical Models 3.7-3 3.7.2.1.3 Calculations 3.7-4 3.7.2.1.4 Results 3.7-9 3.7.2.1.5 Conclusion 3.7-9 3.7.2.2 Natural Frequencies and Response Loads 3.7-9 3.7.2.3 Procedure Used For Modeling 3.7-9 3.7.2.4* Soil / Structure Interaction 3.7-9 3.7.2.5* Development of Floor Response Spectra 3.7-9 3.7.2.6 T_hree Components of Earthquake Motion 3.7-9a 3.7.2.7 Procedure for Combining Modal Responses 3.7-9a 3.7.2.8* Interaction of Non-Category I Structures 3.7-10 with Seismic Category 1 Structures 1 3.7.2.9* Effects of Parameter Variations on Floor 3.7-10 Response Spectra 3.7.2.10 Use of Constant Vertical Static Factors 3.7-10 3.7.2.11 Torsional Effects of Eccentric Masses 3.7-10 3.7.2.12* Comparison of Responses 3.7-10 3.7.2.13 Methods for Seismic Analysis of Dams 3.7-10 3.7.2.14* Detennination of Seismic Category I 3.7-10 St --ture Overturning Moments 3.7.2.15 Analysis Procedure for Damping 3.7-10 3.7.3 SEISMIC SUBSYSTEM ANALYSIS 3.7-11 3.7.3.1 Seismic Analysis Methods 3.7-11 3.7.3.2 Determination of Number of Earthquake Cycles 3.7-11
- See Applicant's SAR Amendment No. 1 vi February 20, 1981
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! 3.9.3.2.2 NSSS Active ASME Code Class 2 and 3 3.9-39 l i Pumps and Class 1, 2, and 3 Valves !
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CHAPTER 3 Section Subject Page No.
3.9.3.2.2.1 Operability Assurance Program 3.9-39 3.9.3.2.2.2 Operability Assurance Program 3.9-40 Results for Active Pumps 3.9.3.2.2.2.1 High-and Low-Pressure 3.9-40 Safety Injection Pumps 3.9.3.2.2.2.2 Charging Pumps 3.9-41 3.9.3.2.2.3 Operability Assurance Program Results 3.9-42 For Active Valves 3.9.3.2.2.3.1 Pneumatically Operated Valves 3.9-44 3.9.3.2.2.3.2 Motor Operated Valves 3.9-44 3.9.3.2.2.3.3 Pressurizer Safety Valves 3.9-44a 7 3.9.3.2.2.3.4 Check Valves 3.9-44b 3.9.3.3* Design and Installation Details For Mounting 3.9-45 of Pressure Relief Devices 3.9.3.4 Component Supports 3.9-45 3.9.4 CONTROL ELEMENT DRIVE MECHANISMS 3.9-47 3.9.4.1 Descriptive Information of CEDM 3.9-47 3.9.4.1.1 Control Element Drive Mechanism Design 3.9-47 Description 3.9.4.1.1.1 CEDM Pressure Housing 3.9-48 3.9.4.1.1.2 Motor Assembly 3.9-48 3.9.4.1.1.3 Coil Stack Assembly 3.9-49 3.9.4.1.1.4 Reed Switch Assembly 3.9-49 3.9.4.1.1.5 Extension Shaft Assembly 3.9-49 3.9.4.1.2 Description of the CEDM Motor Operation 3.9-49 3.9.4.1.2.1 Operating Sequence for the Double 3.9-50 Stepping Mechanism 3.9.4.2 Applicable CEDM Design Specification 3.9-51 3.9.4.3 Design Loads, Stress Limits and Allowable 3.9-51 De forma tions See Applicant's SAR Amendment "o. 7 March 31,1c02 x55
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{ 3.9.5.1.4 In-Core Instrumentation Support 3.9-58 i System 3.9.5.2 Design Loading Conditions 3.9-59 1
3.9.5.3 Design Loading ategories 3.9-59 3.9.5.3.1 Nonnal Operating and Upset 3.9-59 3.9.5.3.2 Faulted 3.9-59 3.9.5.4 Design Bases 3.9-60 3.9.5.4.1 Reactor Internals 3.9-60 3.9.6 INSERVICE TESTING OF PUMPS AND VALVES 3.9-62 3.10 SEISMIC DESIGN OF CATEGORY I INSTRUMENTATION 3.10-1 AND ELECTRICAL EQUIPMENT 3.10.1 SEISMIC QUALIFICATION CRITERIA 3.10-1 3.10.2 f1ETHODS AND PROCEDURES FOR QUALIFYING ELECTRICAL 3.10-1 EQUIPMENT Af1D INSTRUf1ENTATION
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TABLE OF CONTENTS (Cont'd.)
CHAPTER 3 Section Subj ect Page No.
3.10.3 METHODS AND PROCEDURES OF ANALYSIS OR TESTING 3.10-3 0F SUPPORTS OF ELECTRICAL EQUIPMENT AND INSTRUMENTATION 3.10.4 OPERATING LICENSE REVIEW 3.10-5 3.11 ENVIRONMENTAL DESIGN OF MECHANICAL AND 3.11-1 ELECTRICAL EQUIPMENT 3.11.1 EQUIPMENT IDENTIFICATION AND ENVIRONMENTAL 3.11-2 CONDITIONS 3.11.2 QUALIFICATION TESTS AND ANALYSES 3.11-2 3.11.2.1 Component Environmental Design and Qualification 3.11-2 for Normal Operation 3.11.2.2 Component Environmental Design and Qualification 3.11-2 for Operation After a Desian Basis Event 3.11.3 QUALIFICATION TEST RESULTS 3.ll-4a 3.11.3.1 flSSS Instrumentation and Electrical 3. l l - 4a Equipment 7
3.11.3.2 NSSS Mechanical Equipment 3.11 - 4a 3.11.4 CLASS lE INSTRUMENTATION LOSS OF 'IENTILATION 3.11 4a EFFECTS 3.11.5 CHEMICAL SPRAY, RADIATION, HUMIDITY DUST, SUBMERGEf4CE 3.11-5 AND POWER SUPPLY VOLTAGE AND FREQUENCY VARIATION 3.11.5.1 Chemical Environment 3.11-5 3.11.5.2 Radiation Environment 3.11-5 APPENDIX ENVIRONMENTAL QUALIFICATION FOR STRUCTURES 3.11 A-1 3.llA AND COMPONENTS APPENDIX IDENTIFICATION AtlD LOCATION OF MECHANICAL AND 3.ilB-1 3.11B ELECTRICAL SAFETY-RELATED SYSTEMS AND COMPONENTS APPEf4 DIX COMPUTER CODE VERIFICATION 3A-1 3A Amendment No. 7 March 31,1902 xiv
J LIST OF TABLES
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Table Subject 3.2-1 Classification of Structures, Systems, and Components l 3.2-2 Relationship of Safety Class to Code Class i
j 3.5-1 Kinetic Energy of Potential Missiles 1
3.6-1 Pipe Break Summary 3.6-2 Pipe Whip Restraint Parameters l6 3.7.2-1 Damping Ratios Used In Analysis of Category 1 Structures, Systems, and Components t 3.7.2-2 Natural Frequencies and Dominant Degrees of Freedom Reactor
- Coolant System 3.7.2-3 Natural Frequencies and Dominant Degrees of Freedom Pres-surizer and Surge Line 3.9.1-1 Transients Used in Stress Analysis of Code Class 1 Componen'ts 3.9.3-1 Loading Combinations ASME Code Class 1, 2, and 3 NSSS Components l6 l
3.9.3-2 Stress Limits for ASME Code Class 1 NSSS Components, Piping, and Component Supports 16 3.9.3-3 NSSS Seismic I Active Valves 3.9.4-1 Stress Limits for CEDM Pressure Housings 3.9.5-1 Stress Limits for Reactor Internals
- 7 i
l l
Amendment No. 7 March 31, 1982
~
4 O XV 4
,,-----v. -e-.,,-> - ,-.,-.-,m,- . - , , - - - r--.-n- - , ~ . . - - - - - - - - , . - - - - - - - - - - . - - - - - . , . , .
LIST OF FIGURES CHAPTER 3 Figures Subject 3.6-1 Design Basis Pipe Breaks Types and Locations 3.6-2 Main Loop Piping Stress Survey l6 3.7.1-1 Response Spectrum for Upper Reactor Vessel Supports 3.7.1-2 Response Spectrum for Upper Steam Generator Supports 3.7.1-3 Response Spectrum for Upper Reactor Coolant Pump Supports 3.7.1-4 Response Spectrum for Vertical Supports for All Components 3.7.2-1 Typical Reactor Coolant System Seismic Analysis Model 3.7.2-2 Typical Pressurizer Seismic Analysis Model 3.7.2-3 Typical Surge Line Seismic Analysis Model 3.7.3-1 Reactor Internals Horizontal Seismic Model 3.7.3-2 Reactor Internals Linear Horizontal Seismic Model 3.7.3-3 Reactor Internals Linear Vertical Seismic Model 3.7.3-4 Reactor Internals Nonlinear Horizontal Seismic Model 3.7.3-5 System 80 Core Seismic Model - One Row of 17 Fuel Assemblies 3.7.3-6 Core-Support Barrel Upper Flange Finite-Element Model 3.7.3-7 Lower Support Structure Finite-Element Model 3.7.3-8 Reactor Internals Non-Linear Vertical Seismic Model l6 3.9.1-1 Reactor Coolant System Supports Diagram 3.9.1-2 RV Asynnetric Loads Analysis RV Support Loads 3.9.1-3 RV Asymmetric Loads Analysis RV Support Loads 3.9.1-4 RV Asymmetric Loads Analysis RV Support Loads 3.9.1-5 Model of Reactor Internals Amendment No. 6 November 20, 1981 xvi
i l
components, such as piping and strainers are not listed; they may be found O by reference to the P&ID's (Chapters 5.0, 6.0, and 9.0) where the exact
\ / boundaries are indicated.
All pressure containing components in Safety Classes 1, 2, and 3 are designed, manufactured, and tested in accordance with the rules of the ASME Boiler and Pressure Vessel Code,Section III. Components in Safety Class 4 are designed and constructed with appropriate consideration of the intended service using applicable industry codes and standards. The relationship between safety class and code class is shown in Table 3.2-2. A higher code class may be used for component without changing the safety class or affecting the balance of the system in which it is located.
Fracture toughness requirements are imposed on materials for pressure retaining parts of ASME Class 2 and 3 CESSAR system components. Test methods, acceptance, and exemption criteria are in conformance with the ASME Code,Section III.
The safety classification system is also used to identify those components to which the requirements of 10CFR50, Appendix B, are applicable. Components in Safety Classes 1, 2, and some components in Safety Class 3 are designed and manufactured under a rigorous quality assurance program reflecting the requirements of Appendix B, and are designated Quality Class 1. The Quality Class 1 quality assurance program is described in Chapter 17. Components which do not serve a safety related function are designated Quality Class
- 2. Quality Class 2 components will be designed and manufactured in accordance O with the pertinent in Chapter 17. requirements of the Quality Assurance Program as 7give The quality class of major mechanical and electrical components are shown in Table 3.2-1 and Section 3.11, respectively, in conjunction with the safety and seismic classifications.
The use of the above outlined safety and quality classification systems meets the intent of Regulatory Guide 1.26 and the requirements of 10CFR50 Section 50.55a.
n Amendment No. 7 March 31, 1982 3.2-3
i REFERENCES FOR SECTION 3.2
- 1. ANSI N18.2a-1975 (ANS 51.8), " Revision and Addendum to Nuclear Safety Criteria for the Design of Stationary Pressurized WaterReactor Plants,"
- 2. CENPD-182, Seismic Qualification of C-E Instrumentation Equipment, May 1977.
l l
O l
l i
9 3.2-4
TABLE 3.2-1 (Sheet 1 of 20) l7 CLASSIFICATION OF STRUCTURES, SYSTEMS, AND COMPONENTS Sa fety Seismic Quality Class Category. Class Reactor Coolant System
- Reactor Vessel 1 I 1 6
- Steam generators (primary / secondary) 1/2 (1) I 1
- Pressurizer 1 I 1
- Reactor coolant pumps (3) (4) (10) 1 I 1 l7 Piping within reactor coolant pressure boundary (6) 1/2 (5) I 1 Control element drive mechanisms (7) N/A N/A 1 Core support structures (8) N/A I (2) 1 6
Fuel assemblies (9) N/A I 1 Control element assemblies (9) N/A I 1 Closure Head Lift Rig 4 N/A 2 l7 Safety Injection System
- Low pressure safety injection pumps 2 I 1
- High pressure safety injection pumps 2 I 1 6
- Shutdown cooling heat exchangers 2/3 (1) I 1
- Safety injection tanks 2 I 1 Chemical and Volume Control System
- Regenerative heat exchanger 2 I 1
- Letdown heat exchanger 2/3 (1) I 1
- Seal injection heat exchanger 2/3 (1) I 1
- Purification ion exchangers 2 I 1
- Deborating ion exchanger 2 I 1 6
- Volume control tank 2 I 1
- Chemical addition package 4 N/A 2
- Boric acid batching tank 4 N/A 2
- Charging pumps 2 I 1
- Boric acid makeup pumps 3 I 2
- Reactor Makeup water pumps 4 N/A 2
- Boric acid concentrator 4 N/A 2
- Preholdup ion exchanger 3 I 2 N/A is Not Applicable Footnotes to this table are given at the end of the table.
- including component supports down to (but not including) embedments. b Amendment No. 7 March 31,1982
\
l TABLE 3.2-1 (Cont'd.) (Sheet 2 of 20) l7 1
! CLASSIFICATION OF I STRUCTURES, SYSTEMS, AND COMPONENTS Safety Seismic Quality Class Ca tegory Class Chemical and Volume Control System (Cont'd.)
- Boric acid condensate ion exchanger 4 N/A 2
- Reactor drain pumps 3 I 2
- Holdup pumps 4 N/A 2
- Reactor drain tank 4 N/A 2
- Holdup tank 4 N/A 2
- Equipment drain tank 3 I 2
- Refueling water tank 2 I 1
- Reactor makeup water tank 4 N/A 2
- Gas stripper 3 1 2
- Purification filters 2 I 1 6
- Reactor drain filter 3 I 2
- Seal injection filters 2 I 1
- Reactor makeup filter 4 N/A 2
- Boric acid filter 3 1 2 Letdown Strainer 2 1 1 Preholdup Strainer 3 1 1 Boric Acid Condensate Ion 4 N/A 2 Exchanger Strainer lon Exchanger Drain Header Strainer 4 N/A 2 Boric Acid Batching Strainer 4 N/A 2 Chemical Addition Strainer 4 ft/A 2 Fuel Handling System Refueling Machine N/A N/A 2 Fuel Transfer System N/A N/A 2
- 1. Transfer Carriage N/A N/A 2
- 2. Upending Machine N/A N/A 2
- 3. Hydraulic Power Unit N/A N/A 2 Fuel Transfer Tube, Valve N/A N/A 2 CEA Change Platform N/A N/A 2 l
Long and Short Fuel Handling Tools N/A N/A 2 6 Reactor Vessel Head Lif ting Rig 4 N/A 2 Upper Guide Structure Lif ting Rig 2 1 N/A N/A Core Barrel Lifting Rig N/A N/A 2 Spent Fuel Handling Machine N/A N/A 2 l
~
N/A 2 New Fuel Elevator N/A Underwater Television N/A N/A 2 Dry Sipping Equipment N/A N/A 2 Refueling Pool Seal N/A N/A 2 In-Core Instrumentation and CEA Cutter N/A N/A 2 Extension Shaft Uncoupling Tool N/A N/A 2 Fuel Transfer Tube Blind Flange 2 1 2 CEA Handling Tools N/A N/A 2
/clendment No. 7 March 31,1982 l
TABLE 3.2-1 p SAFETY CLASS 1, 2 & 3 VALVES 7 (Sheet 3 of 20)
Component Safety Seismic Quality Identification _
Location / Description Class Category Class Reactor Coolant System (RCS) (12) 7 RC-212 Reactor vessel vent 1 I 1 RC-214 Refueling level indicator 1 I 1 RC-215, 216, 232, 332, RCS drains 1 I 1 233, 333, 234, 334, 235, 335 RC-248, 249, 252, 253, Reactor coolant pump (RCP) 2 I 1 256, 257, 260, 261 i
RC-206, 207, 208, 209 Pressurizer level indicator 2 I 1 RC-204, 205 Pressurizer pressure indicator 2 I 1 RC-239 Pressurizer vent 1 I 1 RC-200, 201, 202, 203 Pressurizer safety 1 I 1 RC-240, 241, 242, 243, Pressurizer spray line 1 I 1 236, 237
. RC-100E , 100F Pressurizer spray line control 1 I 1 RC-244 Pressurizer spray line check 1 I 1 RC-210, 213, 238 Sample System 2 I 1 Reactor Vessel Closure Head Leakoff l ! (d O) RC-211 RC-292, 293, 294, 295, RCS pressure differential 296, 297, 298, 299 2
2 I
I 1
1 RC-752, 753, 754, 755 RCP Seal Housing Drain 1 I 1 RC-712, 713, 714, 715 RCP Vent 1 I 1 RC-446, 447, 448, 449, RCP HP Cooler 1 I 1 450, 451, 452, 453 i RC-772, 773, 774, 775 RCP HP Cooler vent 1 I 1 I RC-868, 869, 870, 871, RCP filter drain 1 I 1 l' 700, 701, 702, 703 RC-724, 725, 726, 727, RCP seal cooler pressure 2 I 1
- 736, 737, 738, 739 l RC-430, 431, 432, 433, RCP controlled bleedoff 2 I 1 344, 345, 346, 347 RC-380, 381, 382, 383 RCP vapor seal pressure indicator 2 I 1 Chemical and Volume Control System (CVCS) (12)
CH-100 VCT Vent Isolation 3 I 1 CH-101 Letdown Check 2 I 1 7 CH-103 VCT Vent Pressure Indicator Isolation 2 1 1 CH-104 VCT Vent Isolation 2 I 1 CH-ll0P Letdown Control 2 I 1 CH-110Q Letdown Control 2 I 1
" CH-ll2 VCT Gas Supply Line Check 2 I 1 CH-ll3 VCT Level Indicator Isolation 2 I 1 Amendment No. 7 March 31, 1982
TABLE 3.2-1 SAFETY CLASS i, 2 & 3 VALVES 7
(Sheet 4 of 20 )
Component Safety Seismic Quality Identification Location / Description Class Category Class CH-ll4 VCT Level Indicator Isolation 2 I 1 CH-115 VCT to EDT Relief 2 I 1 CH-ll6 VCT Local Sample Line Isolation 2 I 1 CH-ll7 CVT to DRDH Isolation 2 I 1 CH-ll8 VCT Check 2 I 1 CH-124 RWT Supply Isolation 2 1 1 CH-126 BABT Line to RWT Isolation 3 I 1 CH-127 BAC Line to RWT Check 3 I 1 CH-128 RWT Level Indicator Isolation 2 I 1 CH-129 RWT Level Indicator Isolation 2 I 1 CH-130 BAMP Recirc Isolation 3 I 1 CH-131 Boric Acid Filter D/P Indicator 3 I 1 Isolation CH-132 BAMP Discharge Filter Vent 3 I 1 CH-134 BAMP to DRDH Isolation 3 I 1 CH-135 RWT Level Indicator Isolation 2 I 1 CH-136 RWT Level Indicator Isolation 2 I 1 CH-137 RWT Level Indicator Isolation 2 I 1 CH-138 RWT Level Indicator Isolation 2 I 1 CH-139 Gas Stripper to VCT Check 2 I 1 CH-143 BAMP Suction Isolation 3 I 1 CH-144 RWT to PCPS Isolation 3 I 1 CH-145 BAMP Suction Isolation 3 I 1 CH-146 RAMP Discharge Pressure Indicator 3 I 1 Isolation 7 CH-147 BAMP Discharge Pressure Indicator 3 I 1 Isolation CH-152 BAMP Discharge Isolation 3 I 1 CH-153 BAMP Discharge Isolation 3 I 1 CH-154 BAMP Discharge Check 3 I 1 CH-155 BAMP Discharge Check 3 I 1 CH-156 RWT Level Indicator Isolation 2 I 1 CH-157 RWT Level Indicator Isolation 2 I 1 CH-158 RWT Level Indicator Isolation 2 I 1 CH-159 RWT Level Indicator Isolation 2 I 1 CH-161 Boric Acid Makeup to VCT Check 3 I 1 CH-164 Boric Acid Filter Bypass 3 I 1 CH-165 Boric Acid Filter D/P Indicator 3 I I Isolation CH-166 Boric Acid Makeup to VCT Isolation 3 I 1 CH-172 Boric Acid Makeup to VCT Isolation 3 I 1 CH-174 Boric Acid Makeup Cross-connect 3 I 1 CH-176 Boric Acid Local Sample Isolation 3 I 1 CH-177 Boric Acid Line to Charging Pump 2 I 1 Suction Check Amendment No. 7 March 31, 1982
LABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES h
N.)
' Y (Sheet 5 of 20)
Component ,
Safety Seismic Quality Identification Location / Description Class Category Class CH-179 RMW Line to Charging Pump Suction 2 I 1 Check CH-184 RMW Line to VCT Check 3 I 1 CH-185 RMW Local Sample Isolation 3 I 1 CH-18d VCT Check 2 I 1 CH-150 RWT Gravity Feed Check 2 I 1 CH-192 BAMP to RWT Recirc 3 I 1 CH-197 Sampling System Check 2 I 1 CH-198 RCP Controlled Bleedoff Isolation 2 I 1 CH-199 RCP Controlled Bleedoff to RDT Relief 2 I 1 CH-20lP '
Letdown Backpressure 2 I 1 CH-201Q Letdown Backpressure 2 I 1 CH-203 Auxiliary Spray 1 I 1 CH-204 'PRM Flow Control 2 I 1 CH-205 Auxiliary Spray 1 I 1 7
CH-210Y Boric Acid Makeup Control 3 I 1 CH-231P Seal Injection Isolation 2 I 1 CH-240 Charging Line Backpressure 1 I 1 CH-241 Seal Injection Flow Control 2 I 1 O CH-242 Seal Injection Flow Control 2 I 1
% / CH-243 Seal Injection Flow Control 2 I 1 V CH-244 Seal Injection Flow Control 2 I 1 CH-255 Seal Injection Containment Isolation 2 I 1 CH-300 RCP Controlled Bleedoff Pressure 2 I 1
, Indicator Isolation CH-305 RWT Gravity Feed Check 2 I 1 CH-306 RWT to SIS Check 2 I 1 CH-314 Hydrostatic Test Pump Isolation 2 I 1 CH-315 Charging Pump to EDT Relief 2 I 1 CH-316 Charging Pump Suction Isolation 2 I 1 CH-317 Charging Pump Suction to DRDH 2 I 1 Isolation CH-318 Charging Pump to EDT Relief 2 I l CH-319 Charging Pump Suction Isolation 2 I 1 CH-320 Charging Pump Suction to DRDH 2 I 1 Isolation CH-321 Charging Pump + fi Re lief 2 I 1 CH-322 Charging Pr ct' a 1 solation 2 I 1 CH-323 Charging F /n, 4 En to DRDH 2 I 1 Isolatior CH-324 Charging Pump Relief 2 I 1 CH-325 Charging Pump Relief 2 I 1 CH-326 Charging Pump Relief 2 I 1 l CH-327 RWT Gravity Feed Isolation 2 I 1 CH-328 Charging Pump Discharge Check 2 I 1
) CH-329 Charging Pump Discharge to DRDH 2 I 1
[
q) Isolation Amendment No. 7 March 31, 1982
TABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES (Sheet 6 of 20) ( l Component Safety Seismic Quality Identification Location / Description Class Category Class CH-330 BAMP Line to HT Isolation 3 I 1 CH-331 Charging Pump Discharge Check 2 I 1 CH-332 Charging Pump Discharge to DRDH 2 I 1 Isolation CH-334 Charging Pump Discharge Check 2 I 1 CH-335 Charging Pump Discharge Isolation 2 I 1 CH-336 Charging Pump Discharge to DRDH 2 I 1 Isolation CH-337 Charging Pump Discharge Isolation 2 I 1 CH-339 Charging Pump Discharge Isolation 2 I 1 CH-340 Letdown Control Valve Isolation 2 I 1 CH-341 Letdown Control Valve Isolation 2 I 1 CH-342 Letdown Control Valve Isolation 2 I 1 CH-343 Letdown Control Valve Isolation 2 I 1 CH-344 Letdown Flow Indicator Isolation 2 I 1 CH-345 Letdown to EDT Relief 2 I 1 7
CH-346 Lerdown Pressure Control Isolation 2 I 1 CH-347 Letdewn Backpressure Valve Isolation 2 I 1 CH-348 Letdown Backpressure Valve Isolation 2 I 1 CH-349 Letdown Backpressure Valve Isolation 2 I 1 { }
CH-350 Letdown Backpressure Vavle Isolation 2 I 1 CH-351 Letdown Flow Indicator Isolation 2 I 1 CH-352 Letdown Pressure indicator Isolation 2 I 1 CH-353 Sampling System Isolation 2 I 1 CH-354 Letdown to EDT Relief 2 I 1 CH-355 Letdown Filter Bypass 2 I 1 CH-356 Letdown Filter D/P Isolation 2 I 1 CH-357 Letdown Filter D/P Isolation 2 I 1 CH-358 Letdown Filter Isolation 2 I 1 CH-359 Letdown Filter Vent 2 I 1 CH-360 Letdown Filter Isolation 2 I 1 CH-361 Letdown to DROH Isolation 2 I 1 CH-362 Shutdown Coolir.g Check 2 I 1 CH-363 Shutdown Cooling Isolation 2 I 1 CH-364 PRM and Boronometer Isolation 2 I 1 CH-366 Letdown Filter Vent 2 I 1 CH-367 PRM Flow Control Valve Isolation 2 I 1 CH-368 PRM Flow Control Valve Isolation 2 I 1 CH-369 IX Isolation 2 I 1 CH-370 IX Check 2 I 1 CH-371 IX Vent to GWMS 2 I 1 CH-372 IX Resin Fill Isolation 2 I 1 CH-373 Letdown Filter Isolation 2 I 1 CH-374 IX Isolation 2 I 1 CH-375 Letdown to DRDH Isolation 2 I 1 Amendment No. 7 March 31, 1982
TABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES (p) v (Sheet 7 of 20)
Component Safety Seismic Quality Identification Location / Description Class Category _ Class CH-376 Letdown Filter Isolation 2 I 1 CH-378 IX Isolation 2 I 1 CH-379 RSSH to IX Isolation 2 I 1 CH-380 IX to SWMS Isolation 2 I 1 CH-381 IX Bypass 2 I 1 CH-382 IX Isolation 2 I 1 CH-383 IX Isolation 2 I 1 CH-384 IX Check 2 I 1 CH-385 IX Bypass 2 I 1 CH-386 IX Vent to GWMS 2 I 1 CH-337 IX Resin Fill Isolation 2 I 1 CH-389 IX Isolation 2 I 1 C!!-00C RSSll to IX Isolation 2 I 1 CH-391 IX to SWMS Isolation 2 I 1 CH-392 IX Isolation 2 I 1 CH-393 RHTX Vent 2 I 1 CH-394 IX Bypass 2 I 1 CH-395 IX Isolation 2 I 1 7
/T
\s_,/
CH-397 CH-398 LPSI Isolation IX Isolation 2
2 I
I 1
1 CH-399 RSSH to IX Isolation 2 I 1 CH-400 IX to SWMS Isolation 2 I 1 CH-401 IX Vent to GWMS 2 I 1 CH-402 IX Resin Fill Isolation 2 I 1 CH-403 IX Check 2 I 1 CH-404 IX Isolation 2 I 1 CH-405 Charging Line Backpressure D/P 2 I 1 Isolation CH-406 Charging Line Backpressure D/P 1 I 1 Isolation CH-407 IX D/P Isolation 2 I 1 CH-408 IX D/P Isolation 2 I 1 CH-413 PRM Bypass 2 I 1 CH-414 Letdown Strainer Bypass 2 I 1 CH-415 IX Isolation 2 I 1 CH-418 Letdown to VCT Isolation 2 I 1 CH-419 Letdewn Strainer to SWMS Isolation 2 I 1 CH-420 IX Effluent Sample Isolation 2 I 1 CH-421 Boronometer Isolation 2 I 1 CH-422 PRM Flow Indicator Isolation 2 I I CH-423 PRM Flow Control Spring Loaded Check 2 I 1 Bypass CH-424 PRM Flow Control Bypass 2 I 1 fsg CH-425 Charging Line Pressure Indicator 2 I l t Isolation
%.]
Amendment No. 7 March 31, 1982
I TABLE 3.2-1 i
SAFETY CLASS 1, 2 & 3 VALVES (Sheet 8 of 20) ;
i Component Safety Seismic Quality '
Identification Location / Description _
Class Ca tegory_ Class CH-426 Letdown Sample Isolation 2 I 1 CH-427 Charging Line Flow Indicator Isolation 2 I 1 CH-428 Charging Line Flow Indicator Isolation 2 I 1 :
C11-429 Charging Line Isolation 2 I 1 ,
CH-431 Auxiliary Spray Check 1 I 1 l
CH-433 Charging Line Check 1 I 1 :
CH-434 Charging Line Backpressure Bypass 1 I 1 CH-435 Charging Line Backpressure Spring 1 I 1 Loaded Bypass Check CH-436 Hydrogen Addition Line Isolation 2 I 1 CH-437 Charging Pump Pressure Switch 2 I 1 Isolation CH-438 Charging Pump Pressure Switch 2 I 1 i Isolation l CH-439 Charging Pump Pressure Switch 2 I 1 Isolation CH-440 Charging to HPSI Check 2 I 1 CH-444 Letdown Heat Exchanger Vent 3 I 1 j CH-445 Letdown Line Vent 2 I 1 i 7
CH-449 PRM and Boronometer Check 2 I 1 CH-450 ,RDH to EDT Check 3 I 1 CH-459 EDT Line to GWMS Pressure Indicator 3 I 1 Isolation CH-460 EDT Level Indicator Isolation 3 I 1 CH-461 EDT Level Indicator Isolation 3 I 1 CH-464 EDT to RDP Check 3 I 1 CH-465 RDP Suction Isolation 3 I 1 CH-466 RDP Suction Isolation 3 I 1 CH-467 Gas Stripper to GWMS Isolation 3 I 1 CH-468 RDP Discharge Pressure Indicator 3 I 1 Isolation CH-469 RDP Discharge Pressure Indicator 3 I 1 Isolation CH-470 RDP Discharge Check 3 I 1 CH-471 RDP Discherge Check 3 I 1 CH-472 RDP Discharge Isolation 3 I 1 CH-462 EDT Drain Isolation 3 I 1 CH-473 RDP Discharge Isolation 3 I 1 CH-474 Reactor Drain Filter Bypass 3 I 1 CH-475 RDP Discharge to RDH Isolation 3 I 1 CH-476 Reactor Drain Filter D/P Isolation 3 I 1 CH-477 Reactor Drain Filter Isolation 3 I 1 CH-478 Reactor Drain Filter Isolation 3 I 1 CH-479 Reactor Drain Filter D/P Isolation 3 I 1 CH-480 IDH to EDT Check 3 I 1 CH-485 Pre-Holdup IX to RSSH Isolation 3 I 1 CH-486 Pre-Holdup IX DiDH Isolation 3 I I Amendment No. 7 March 31, 1982
I TABLE 3.2-1
/ \
\ / SAFETY CLASS 1, 2 & 3 VALVES (Sheet 9 of 20)
Component Safety Seismic Quality Identification Location / Description Class Category Class CH-488 Pre-Holdup IX D/P Isolation 3 I 1 CH-489 Pre-Holdup Strainer to SWMS Isolation 3 I 1 CH-490 Pre-Holdup IX Isolation 3 I 1 CH-491 Pre-Holdup IX Strainer Isolation 3 I 1 CH-492 Pre-Holdup IX D/P Isolation 3 I 1 CH-493 Pre-Holdup IX Effluent Sample 3 I 1 Isolation CH-494 RSSH and RDP to RDH Check 2 I 1 CH-495 Pre-Holdup IX to RWT Isolation 3 I 1 CH-496 Pre-Holdup IX to GS/EDT Isolation 3 I 1 CH-500 VCT Inlet Diverting 2 I 1 CH-501 VCT Discharge Isolation 2 I 1 CH-505 RCP Controlled Bleedoff Containment 2 I 1 Isolation CH-506 RCP Controlled Bleedoff Containment 2 I 1 Isolation p CH-507 RCP Controlled Bleedoff Containment 2 I 1 i j Isolation
'A > CH-510 RWT Recirc 3 I 1 CH-512 VCT Makeup Supply Isolation 3 I 1 CH-513 VCT Vent 2 I 1 7 CH-514 Boric Acid Makeup Bypass to Charging 3 I 1 Pumps CH-515 Letdown Isolation 1 I 1 CH-516 Letdown Isolation 1 I 1 CH-520 Purification and Deborating IX Bypass 2 I 1 CH-521 PRM and Boronometer Bypass 2 I l CH-523 Letdown Isolation 2 I 1 CH-524 Charging Line Isolation 2 I 1 CH-526 Letdown Control Valve Bypass 2 I 1 CH-527 Load Follow Supply 3 I 1 CH-530 RWT Suction to ESFP's Isolation 2 I 1 CH-531 RWT Suction to RSFP's Isolation 2 I 1 CH-532 RWT Suction to RDP's Isolation 2 I 1 CH-536 RWT Gravity Feed to Charging Pumps 3 I 1 Isolation CH-560 RDT Suction Isolation 2 I 1 CH-561 RDT Isolation 2 I 1 CH-562 RDH Isolation 3 I 1 CH-563 EDT Discharge Isolation 3 I 1 CH-564 EDT Vent Isolation 3 I 1 CH-565 Pre-Holdup IX Bypass 3 I I
/ CH-566 Gas Stripper Diversion 3 I 1 CH-567 Diversion to HT from VCT Inlet 3 I 1 Amendment No. 7 March 31, 1982
TABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES (Sheet 10 of 20)
Component Safety Seismic Quality Identification Location / Description Class Category Class CH-580 RMWS to RDT Isolation 2 I 1 CH-612 Seal Injection Line Vent Isolation 2 I 1 CH-613 Seal Injection Line Vent Isolation 2 I 1 CH-614 Seal Injection Vent 3 I 1 CH-639 Charging Line Check 2 I 1 CH-642 Hydrostatic Test Pump Isolation 2 I 1 CH-643 VCT Vent to GWMS Isolation 3 I 1 CH-645 Gas Addition to VCT Isolation 2 I 1 CH-646 RCP Controlled Bleedoff Line Check 2 I 1 CH-647 RWT Recirc Check 2 I 1 CH-648 RWT Recirc Sample Isolation 3 I 1 CH-649 Boric Acid Line to RWT Isolation 3 I 1 CH-653 Boric Acid Line Isolation 3 I 1 CH-654 MSH to Gas Stripper Isolation 3 I 1 CH-655 Pre-Holdup IX to Radiation Monitor 3 I 1 Isolation CH-656 Gas Stripper to HT Isolation 3 I 1 CH-657 EDT Relief to Misc Radioactive Sump 3 I 1 CH-659 Chemical Addition Line Isolation 2 I 1 CH-660 Gas Stripper Inlet Isolation 3 I 1 CH-663 Reactor Drain Filter Vent 3 I 1 CH-665 RDP Discharge Sample Isolation 3 I 1 7 CH-668 BAM Line to VCT Check 3 I 1 CH-686 Holdup Pump Bypass to Reactor Drain 3 I 1 Filter Isolation CH-721 Letdown to Pre-Holdup IX Isolation 3 I 1 CH-722 Letdown to Pre-Holdup IX Check 3 I 1 CH-723 Reactor Drain Line Sample Isolation 3 I 1 CH-724 Pre-Holdup IX Isolation 3 I 1 CH-725 Pre-Holdup IX Check 3 I 1 CH-726 Pre-Holdup IX Resin Fill Isolation 3 I 1 CH-727 Pre-Holdup IX D/P Isolation 3 I 1 CH-728 Pre-Holdup IX Vent Isolation 3 I 1 CH-730 Pre-Holdup IX to SWMS Isolation 3 I 1 CH-740 RCP Controlled Bleedoff Test 2 I 1 Connection Isolation CH-741 RCP Controlled Bleedoff Test 2 I l Connection Isolation CH-742 RCP Controlled Bleedoff Test 2 I 1 Connection Isolation CH-743 RCP Controlled Bleedoff Test 2 I 1 Connection Isolation CH-753 BAMP Recirc Isolation 3 I 1 O
Amendment No. 7 March 31, 1982
TABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES
(~] (Sheet 11 of 20)
U Component Safety Seismic Quality Identification Location / Description Class Category Class CH-755 Gravity Feed to Charging Pump Isolation 2 I 1 CH-756 Gravity Feed to Charging Pump Isolation 2 I 1 CH-757 Gravity Feed to Charging Pump Isolation 2 I 1 Cil-787 Seal Injection Check 1 I 1 CH-789 Seal Injection Flow Indicator Isolation 2 I 1 CH-796 Charging to HPSI Isolation 2 I 1 CH-797 Charging to HPSI Isolation 2 I 1 CH-798 Charging to HPSI Isolation 2 I 1 CH-800 Seal Injection Flow Indication 2 I 1 Isolation CH-802 Seal Injection Check 1 I 1 CH-804 Seal Injection Flow Indicator Isolation 2 I 1 CH-805 Seal Injection Flow Indicator Isolation 2 I 1 CH-807 Seal Injection Check 1 I 1 CH-809 Seal Injection Flow Indicator Isolation 2 I 1 CH-810 Seal Injection Flow Indicator Isoaltion 2 I 1 CH-812 Seal Injection Check l I 1 CH-814 Seal Injection Flow Indicator Isolation 2 I 1 CH-815 Seal Injection Flow Indicator Isolation 2 I 1 CH-816 Seal Injection Filter Isolation 2 I 1
( ;CH-818 Seal Injection Filter Isolation 2 I 1
\~./ CH-819 Seal Injection Filter Isolation 2 I 1 7
Cil-821 Seal Injection Filter Isolation 2 I 1 CH-822 Seal Injection to DRDH Isoaltion 2 I 1 CH-823 Seal Injection to DRDH Isolation 2 I 1 CH-825 Seal Injection Filter D/P Isolation 2 I 1 CH-826 Seal Injection Filter D/P Isolation 2 I l CH-830 Nitrogen Supply to EDT Isolation 3 I 1 CH-831 Nitrogen Supply Pressure Control 3 I 1 CH-833 Seal Injection Test Connection 2 I 1 Isolation CH-834 Seal Injection Test Connection 2 I I Isolation CH-835 Seal Injection Check 2 I 1 CH-836 Seal Injection Isolation 2 I 1 l CH-839 Seal Injection Isolation 2 I 1 CH-843 RHTX Vent Isolation 2 I 1 CH-844 Seal Injection Filter Vent 2 I 1 CH-845 Seal Injection Filter Vent 2 I 1 CH-848 Seal Injection Test Connection 1 I 1 Isolation l CH-849 Seal Injection Test Connection 1 I 1 Isolation CH-853 Letdown Line Test Connection Isolation 1 I 1 CH-854 Charging Line Test Connection Isolation 2 I 1 Letdown Line Test Connection Isolation 2 I 1
,")CH-855 CH-856 8 AMP Suction Line Test Connection 3 I 1 Isolation Amendment No. 7 March 31, 1982
TABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES (Sheet 12 of 20)
Component Safety Seismic Quality Identification Location / Description Class Category Class C51-858 RSSH Line to EDT Check 3 I 1 CH-859 Seai Injection Test Connection 1 I 1 Isolation CH-860 Seal Injection Test Connection 1 I 1 Isolation CH-861 RSSH to EDT Isolation 3 I 1 CH-862 RMWT Supply to RDT Isolation 3 I 1 CH-863 Chemical Addiition Isolation 2 I 1 CH-865 Seal Injection Relief to EDT 2 I 1 CH-866 Seal Injection Check l I l CH-867 Seal Injection Check 1 I 1 CH-868 Seal Injection Check 1 I 1 CH-863 Seal Injection Check 1 I 1 l Safety Injection and Shutdown Cooling Systems (SIS) (SCS) (12)
SI-104 CSP Suction Isolation 2 I 1 SI-105 CSP Suction Isolation 2 I 1 l
}
SI-140 Sump Suction Thermal Relief 2 I 1 l SI-141 PCPS Suction Thermal Relief 2 I 1 l S I-150 PCPS Suction Thermal Relief 2 I 1 l SI-151 Sump Suction Thermal Relief 2 I 1 SI-157 CSP Suction Check 2 I 1 l SI-158 CSP Suction Check 2 I 1 SI-161 PCPS Discharge Thermal Relief 2 I 1 SI-162 PCPS Discharge Thermal Relief 2 I 1 SI-170 SDCHX Vent 2 I 1 SI-172 SDCHX Drain 2 I 1 SI-174 CS Flow Inst Isolation 2 I 1 SI-175 CS Flow Inst Isolation 2 I 1 SI-176 CS Flow Inst Isolation 2 I 1 SI-177 CS Flow Inst Isolation 2 I 1 SI-180 SDCHX Vent 2 I 1 SI-182 SDCHX Drain 2 I 1 SI-184 LPSI-CSP Interconnection 2 I 1 SI-185 LPSI-CSP Interconnection 2 1 1 SI-191 CS Header Relief 2 I 1 SI-192 PCPS Discharge Thermal Relief 2 I 1 SI-193 PCPS Discharge Thermal Relief 2 I 1 SI-194 CS Header Relief 2 I i SI-200 LPSI Suction Check 2 I 1 SI-201 LPSI Suction Check 2 I 1 i SI-202 Sample Line Isolation 2 I 1 l SI-203 Sample Line Isolation 2 I 1 Amendment No. 7 March 31, 1982
- _. . . . _ . . . . . = . - _
1 1
TABLE 3.2-1 4
SAFETY CLASS 1, 2 & 3 VALVES (Sheet 13 of 20)
Component Safety Seismic Quality i Identification Location / Description Class Ca tegory Class SI-204 PCPS Suction Isolation 2 I 1 4 SI-205 Sump Suction Check. 2 I 1 SI-206 Sump Suction Check 2 I 1
{ SI-207 Sump Suction Test 2 I 1 SI-208 Sump Suction Test 2 I 1 S I-218 HPSI Orifice Bypass 2 I 1 SI-219 HPSI Orifice Bypass 2 I 1 S I-256 PCPS Suction Isolation 2 I 1 SI-257 PCPS Sample Isolation 2 I 1 S I-260 SDCHX Vent Isolation 2 I 1 SI-262 SDCHX Drain Isolation 2 I 1 SI-264 SDCHX Vent Isolation . 2 I 1 SI-266 SDCHX Drain Isolation 2 I 1 SI-268 PCPS Sample Isolation 2 I 1 SI-285 RWT Recirc Line Relief 2 I l SI-286 RWT Recirc Line Relief 2 I 1 SI-287 SDCHX Bypass Relief 2 I 1
, S I-288 RWT Return Relief 2 I 1 i \w SI-289 SDCHX Bypass Relief 2 I I SI-298 7 RWT Line Isolation 2 I 1
! S I-306 SCS Bypass Flow Control 2 I 1 l SI-307 SCS Bypass Flow Control 2 I 1 SI-400 RWT Return Line Isolation 2 I 1 l~
SI-402 HPSI Suction Isolation 2 I 1 51-404 HPSI Discharge Check 2 I 1
! SI-405 HPSI Discharge Check 2 I 1 SI-407 RWT Return Line Relief 3 I 1 SI-408 Pressure Gage Isolation 2 I l i SI-409 HP Header Relief 2 I 1 SI-416 Pressure Gage Isolation 2 I 1 SI-417 HPSI Header Relief 2 I 1
, SI-418 Shutdown Purif. Suction Isolation 2 I 1 SI-419 Shutdown Purif. Suction Isolation 2 I 1 SI-420 Shutdown Purif. Isolation 2 I 1 SI-421 Shutdown Purif. Isolation 2 I 1
- SI-424 HPSI Mini-flow Check 2 I 1 SI-426 HPSI Mini-flow Check 2 I 1 SI-427 HPSI Discharge SS Isolatisn 2 I 1 SI-429 Shutdown Cooling Line SS Isolation 2 I l SI-433 LPSI Discharge Pressure Ind. Iso. 2 I I SI-434 LPSI Discharge Check 2 I 1 SI-435 LPSI Discharge Isolation 2 I 1 SI-436 LPSI Discharge Isolation 2 I 1 i
Amendment No. 7
) March 31, 1982
TABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES (Sheet 14 of 20)
Component Safety Seismic Quality Identification Location / Description Class Category Class SI-437 LPSI Flow Inst. Isolation 2 I 1 SI-438 LPSI Flow Inst. Isolation 2 I 1 S I-439 LPSI Discharge Relief to EDT 2 I 1 SI-440 LPSI Flow Inst. Isolation 2 I 1 SI-441 LPSI Flow Inst. Isolation 2 I 1 SI-442 PCPS Suction Isolation 2 I 1 SI-443 PCPS Suction Isolation 2 I 1 SI-445 LPSI Suction SS Isolation 2 I 1 SI-446 LPSI Discharge Check 2 I 1 SI-447 LPSI Discharge Check 2 I 1 SI-448 LPSI Mini-flow Check 2 I 1 SI-449 LPSI Discharge Relief to EDT 2 I 1 SI-450 LPSI Discharge PCPS Isolation 2 I 1 SI-451 LPSI Mini-flow Check 2 I 1 SI-454 LPSI Discharge PCPS Isolation 2 I 1 SI-455 LPSI Discharge PCPS Isolation 2 I 1 SI-458 LPSI Discharge PCPS Isolation 2 I 1 SI-459 RWT Return Line Isolation 2 I 1 SI-460 RWT Return Line Isolation 2 I 1 S I-461 SIT to EDT Isolation 3 I 1 7 SI-462 SIT Local Sample Isolation 3 I 1 SI-463 SIT Isolation 2 I 1 SI-464 RWT Return Line Isolation 2 I 1 SI-465 RWT Return Line SS Isolation 2 I 1 SI-470 HPSI Suction Isolation 2 I 1 SI-473 SIT Relief to RDT 2 I 1 SI-474 SIT Relief to RDT 2 I 1 S I -476 HPSI Discharge Isolation 2 I 1 SI-478 HPSI Discharge Isolation 2 I 1 SI-482 CSP Discharge Pressure Ind. Iso. 2 I 1 SI-483 CSP Discharge Pressure Ind. Iso. 2 I 1 SI-484 CSP Discharge Check 2 I 1 SI-485 CSP Discharge Check 2 I 1 SI-486 CSP Mini-flow Check 2 I 1 SI-487 CSP Mini-flow Check 2 I I SI-508 Charging Pump Isolation 2 I 1 SI-509 Charging Pump Isolation 2 I l SI-550 LPSI Suction Test Isolation 2 I 1 SI-551 CSP Suction Test Isolation 2 I 1 SI-552 HPSI Suction Test Isolation 2 I l SI-553 HPSI Suction Test Isolation 2 I 1 SI-554 CSP Suction Test Isolation 2 I 1 SI-555 LPSI Suction Test Isolation 2 I 1 SI-604 HPSI Hot Leg Injection Isolation 2 I 1 SI-609 HPSI Hot Leg Injection Isolation 2 I 1 Amendment No. 7 March 31, 1982
TABLE 3.2-1
) SAFETY CLASS 1, 2 & 3 VALVES (Sheet 15 of 20)
Component Safety Seismic Quality Identification Location / Description Class Category Class SI-657 SDCHX Discharge Throttle 2 I 1
$1-658 SDCHX Discharge Throttle 2 I 1 ST-659 Mini-flow to RWT Isolation 2 I 1 SI-660 Mini-flow to RWT Isolation 2 I 1 SI-661 RDT Isolation 2 I 1 S I-664 CSP Mini-flow Isolation 2 I 1 SI-665 CSP Mini-flow Isolation 2 I 1 SI-666 HPSI Mini-flow Isolation 2 I 1 SI-667 HPSI Mini-flow Isolation 2 I 1 SI-668 LPSI Mini-flow Isolation 2 I 1 SI-669 LPSI Mini-flow Isolation 2 I 1 SI-671 CSS Isolation 2 I 1 SI-672 CSS Isolation 2 I 1 SI-673 Containment Sump Isolation 2 I 1 SI-674 Containment Sump Isolation 2 I 1 SI-675 Containment Sump Isolation 2 1 1 SI-676 Containment Sump Isolation 2 I l ps s 1 SI-678 SI-679 CSP Flow Control CSP Flow Control 2
2 I
I 1
1
'V SI-682 SIT Fill Line Isolation 2 I 1 SI-683 LPSI Pump Suction Isolation 2 I 1 7
SI-684 CSP Discharge Isolation 2 I 1 SI-685 LPSI Disch. SDCHX Intake Cross Connect 2 I 1 Line Isolation SI-686 SDCHX Disch. LPSI Header Cross Connect 2 I 1 Line Isolation SI-687 SDCHX Disch. Isolation to CSS Header 2 I 1 SI-688 SDCHX Spray Bypass 2 I 1 SI-689 CSP Discharge Isolation 2 I 1 SI-692 LPSi Suction Isolation 2 I 1 SI-693 SDCHX Spray Bypass 2 I 1 SI-694 LPSI Disch. SDCHX Intake Cross Connect 2 I 1 Line Isolation SI-695 SDCHX Disch. Isolation to CSS Header 2 I 1 SI-696 SDCHX Disch. LPSI Header Cross Connect 2 I 1 Line Isc,ation SI-698 HPSIP Orifice Bypass 2 I 1 SI-699 HPSIP Orifice Bypass 2 I 1 S1-113 HP Header Check 1 I 1 SI-lla LP Header Check 1 I 1 S I-ll 5 HP Header Flow Ind. Isolation 2 I 1 SI-ll6 HP Header Flow Ind. Isolation 2 I 1
[s]
(,/
SI-ll7 SI-119 SIT Pressure Ind. Isolation SIT Pressure Ind. Isolation 2
2 I
I 1
1 Amendment No. 7 March 31, 1982
TABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES (Sheet 16 of 20)
Component Safety Seismic Quality Identification Location / Description Class Category Class SI-123 HP Header Check 1 I 1 SI-124 LP Header Check 1 I 1 SI-125 HP Header Flow Ind. Isolation 2 I 1 SI-126 HP Header Flow Ind. Isolation 2 I 1 SI-127 SIT Pressure Ind. Isolation 2 I 1 SI-129 SIT Pressure Ind. Isolation 2 I 1 SI-133 HP Header Check 1 I 1 SI-134 LP Header Check 1 I 1 SI-135 HP Header Flow Ind. Isolation 2 I 1 S!-136 HP Heeder Flow Ind. Isolation 2 I 1 SI-137 SIT Pressure Ind. Isolation 2 I 1 SI-139 SIT Pressure Ind. Isolation 2 I 1 SI-143 HP Header Check 1 I 1 SI-144 LP Header Check 1 I 1 SI-145 HP Header Flow Ind. Isolation 2 I 1 SI-146 HP Header Flow Ind. Isolation 2 I 1 SI-147 SIT Pressure Ind. Isolation 2 I 1 SI-149 SIT Pressure Ind. Isolation 2 I 1 SI-164 CS Header Check 2 I 1 SI-165 CS Header Check 2 I 1 7 SI-166 HP Header Relief to EDT 2 I 1 SI-169 HP Header Relief to EDT 2 I 1 SI-179 HP Header Relief to Cont. Sump 2 I 1 SI-189 HP Header Relief to Cont. Sump 2 I 1 SI-210 SIT Fill & Drain Isolation 2 I 1 S I-211 SIT Relief to Atmosphere 2 I 1 SI "2 SIT Level Ind. Isolation 2 I 1 SI-213 SIT Level Ind. Isolation 2 I 1 SI-214 SIT Local Sample Isolation 2 I 1 SI-215 SIT Check l I 1 SI-216 Injection Line Press. Ind. Iso. 1 I l SI-217 Safety Inj. Line Check 1 I 1 SI-220 SIT Fill & Drain Isolation 2 I 1 SI-221 SIT Relief to Atmosphere 2 I 1 SI-222 SIT Level Ind. Injection 2 I 1 SI-223 SIT Level Ind. Injection 2 I 1 SI-224 SIT Local Sample Isolation 2 I 1 SI-225 SIT Check 1 I 1 SI-226 Inj. Line Pressure Ind. Iso. 1 I 1 SI-227 Safety Inj. Line Check 1 I 1 SI-228 SIT Level Ind. Isolation 2 I 1 SI-229 SIT Level Ind. Isolation 2 I 1 SI-230 SIT Fill & Drain Isolation 2 1 1 SI-231 SIT Relief to Atmosphere 2 I 1 knendment No. 7 March 31, 1982
TABLE 3.2-1 7s s, SAFETY CLASS 1, 2 & 3 VALVES (Sheet 17 of 20)
Component Safety Seismic Quality Identification Location / Description __
Class Category Class SI-232 SIT Level Ind. Isolation 2 I 1 SI-233 SIT Level Ind. Isolation 2 1 SI-234 SIT Local Sample Isolation 2 I 1 SI-235 SIT Check 1 I 1 SI-236 Inj. Line Pressure Ind. Iso. 1 I 1 SI-237 Safety Inj. Line Check 1 I 1 SI-238 SIT Level Ind. Isolation 2 I 1 SI-239 SIT Level Ind. Isolation 2 I 1 SI-240 SIT Fill & Drain Isolation 2 I 1 SI-241 SIT Relief to Atmosphere 2 I 1 SI-242 SIT Level Ind. Isolation 2 I 1 SI-243 SIT Level Ind. Isolation 2 I 1 SI-244 SIT Local Sample Isolation 2 I 1 SI-245 SIT Check 1 I 1 SI-246 Inj. Line Pressure Ind. Iso. 1 I 1 SI-247 Safety Injection Line Check 1 I 1
-s SI-248 SIT Level Ind. Isolation 2 I 1 i SI-249 SIT Level Ind. Isolation 2 I 1
_- SI-258 SIT Level Ind. Isolation 2 I 1 SI-259 SIT Level Ind. Isolation 2 I 1 7
SI-321 HP Hot Leg Injection Isolation 2 I 1 SI-322 Hot Leg Check Leakage Valve 1 I 1 SI-331 HP Hot Leg Injection Isolation 2 I 1 SI-332 Hot Leg Check Leakage Valve 1 I 1 SI-468 HP Header Relief to EDT 2 I 1 SI-469 SDC Line Relief te RDT 1 I 1 SI-500 CSS Test Line Isolation 2 I 1 S I-501 CSS Test Line Isolation 2 I 1 SI-506 HP Header Pressure Ind. Iso. 1 I 1 SI-510 CSS Test Line Isolation 2 I 1 SI-511 CSS Test Line Isolation 2 I 1 SI-516 HP Header Pressure Ind. Iso. 1 I I SI-522 HP Header Check 1 I l SI-523 HP Header Check 1 I 1 SI-525 HP Header Flow Ind. Isolation 2 I 1 SI-526 HP Header Flow Ind. Isolation 2 I 1 SI-532 HP Header Check 1 I 1 SI-533 HP Header Check 1 I 1 51-535 HP Header Flow Ind. Isolation 2 I 1 SI-536 HP Header Flow Ind. Isolation 2 I 1 SI-605 SIT Atmospheric Vent Isolation 2 I 1 SI-606 SIT Atmospheric Vent Isolation 2 I 1 SI-607 SIT Atmospheric Vent Isolation 2 I 1
()N SI-608 SIT Atmospheric Vent Isolation 2 I 1 Amendment No. 7 March 31, 1982
TABLE 3.2-1 SAFETY CLASS 1, 2 & 3 VALVES (Sheet 18 of 20 )
Component Safety Seismic Quality Identification Location / Description Class Category Class SI-611 SIT Fill & Drain Isolation 2 I 1 SI-612 SIT N7 Supply Isolation 2 I 1 SI-613 SIT Atmospheric Vent Isolation 2 I 1 SI-614 SIT Isolation 1 I 1 SI-615 LPSI Header Isolation 2 I 1 SI-616 HPSI Header Isolation 2 I 1 SI-617 HPSI Header Isolation 2 I 1 SI-618 Check Valve Leakage Line Iso. 1 I 1 SI-619 SIT N7 Supply Isolation 2 I 1 SI-621 SIT F111 & Drain Isolation 2 I 1 SI-622 SIT N9 Supply Isolation 2 I l SI-623 SIT Atmospheric Vent Isolation 2 I 1 SI-624 SIT Isolation 1 I 1 SI-625 LPSI Header Isolation 2 I 1 SI-626 HPSI Header Isolation 2 I 1 S I-627 HPSI Header Isolation 2 I 1 SI-628 Check Valve Leakage Line Iso. 1 I 1 SI-629 SIT N7 Supply Isolation 2 I 1 SI-631 SIT FTll & Drain Isolation 2 I 1 SI-632 SIT N3 Supply Isolation 2 I 1 SI-633 SIT Atmospheric Vent Isolation 2 I 1 SI-634 SIT Isolation 1 I 1 SI-635 LPSI Header Isolation 2 I 1 S I-636 HPSI Header Isolation 2 I 1 SI-637 HPSI Header Isolation 2 I 1 SI-638 Check Valve Leakage Line Iso. 1 I 1 SI-639 SIT N, Supply Isolation 2 I 1 S I-641 SIT Fill & Drain Isolation 2 I 1 SI-642 SIT N7 Supply Isolation 2 I 1 SI-643 SIT Atmos. Vent Isolation 2 I 1 SI-644 SIT Isolation 1 I 1 SI-645 LPSI Header Isolation 2 I 1 SI-646 HPSI Header Isolation 2 I l SI-647 HPSI Header Isolation 2 I 1 S I-648 Check Valve Leakage Line Iso. 1 I 1 SI-649 SIT N7 Supply Isolation 2 I 1 SI-651 SCS Suction Line Isolation 1 I 1 SI-652 SCS Suction Line Isolation 1 I 1 SI-653 SCS Suction Line Isolation 1 I 1 SI-664 SCS Suction Line Isolation 1 I 1 SI-655 SCS Suction Line Isolation 2 I 1 SI-656 SCS Suction Line Isolation 2 I 1 SI-690 SCS Warmup Line Isolation 2 I 1 SI-691 SCS Warmup Line Isolation 2 I 1 Amendment No. 7 March 31,1982
TABLE 3.2-1 (Sheet 19 of 20)
NOTES: (1) Two safety classes are used for heat exchangers to distinguish primary and secondary sides where they are different.
(2) Only those core support structures necessary to support and restrain the core and to maintain safe shutdown capability are classified as Seismic Category I.
(3) Loss of cooling water and/or seal water service to the reactor coolant pumps (RCP's) may require stopping the pumps. However, the continuous operation of the pumps is not required during or following an SSE. The auxiliaries are therefore not necessarily Safety Class 3 or Seismic Category I. Provision for cooling water to the pump bearing oil cooler and pump motor air cooler will not comply with the requirements of Regulatory Guide 1.29 (see Subsection 5.4.1.3). l6 (4) Only those structural portions of the RCP's which are necessary to assure the integrity of the reactor coolant pressure boundary are Safety Class 1.
(5) Safety class of piping within the reactor coolant pressure boundary (as defined in 10CFR50) is selected in accordance with the ANSI N18.2 criteria identified in Subsection 3.2.2. For purposes of CESSAR, 6 Safety Class 1, 2, 3, 4 of ANSI-N18.2 are equivalent to Quality Groups A, B, C, D of Regulatory Guide 1.26.
(6) Flow restricting orifices are provided in the nozzles for the RCS sampling lines, the pressurizer level and pressure instruments, the RCP differential pressure instrument lines, the common SI header pressure instrument lines, the RCP seal pressure instrument lines, the charging line differential pressure instrument line, and the SI hot leg injection pressure instrument lines, to limit flow in the event of a break downstream of a nozzle. The orifice size, 7/32 inch diameter x 1 inch long, precludes exceeding fuel design limits while utilizing minimum makeup rates. This permits an orderly shutdown in the event of a downstream break in accordance with General Design Criterion 33 (see Section 3.1.29). A reduction may, therefore, be made in the safety classification of lines downstream of the orifice.
(7) The pressure boundary housing for this component is a reactor vessel appurtenance and is Safety Class 1 and Seismic Category I, as 6 described in 3.9.4.3.
(8) Core Support structures are designed to the criteria described in 3.9.5.4.
(9) CEA and fuel assemblies are designed to the criteria described in 4.2.
(10) Reactor coolant pump auxiliary components required for lubrication 7 and cooling of pump seals and thrust bearings are Quality Class 2.
n v
Amendment No. 7 March 31, 1982
.TA1L E_. 3. 2 _l, (Cont'd)
(Sheet 20 of 20)
(11) Safety-related instrumentation and controls (I & C) described in Sections 7.1 through 7.6 of the FSAR plus safety-related I & C for safety -related fluid systems will be subject to the pertinent 7 requirements of the Quality Assurance Program as given in Chapter 17.
(12) All containment isolation values (and their operators) within C-E's scope of supply - including manual valves, check valves, and relief valves which also serve as isolation valves will be subject to the f pertinent requirements of the Quality Assurance Program as given in i Chapter 17.
l l
l t
9 1
Amendment No. 7 O
March 31, 1982 l
TABLE 3.5-1 n (Sheet 1 of 2)
! \
'\.s' KINETIC ENERGY OF POTENTIAL MISSILES _
Initial Kinetic Weight Item ()) Energy (ft-lb) (1b) Impact Section
- 1. Reactor Vessel Closure Head Nut 1,706 100 Annular Ring, OD = 10-2/16" ID = 6.9" Closure Heat Nut and Stud 5,226 577 Sol id C ircle, 6-3/4" Diameter Control Rod Drive 1.875" dia. solid circle within Assembly 57,600 11 00 a concentric 7" dia, by .109" 7 wall shroud
- 2. Steam Generator Primary Manway Stud and Nut 71 4-1/4 Solid Circle,1-1/2" Diameter Secondary Handhole Stud and Nut 1.15
} 7 Solid Circle, 3/4" Diameter
\' '/
Secondary Manway Stud 7 3.36 Solid Circle,1-1/4" Diameter
- 3. Pressurizer Safety Valve With Flange 89,230 550 Solid Circle, 2" Diameter Safety Valve Flange Bolt 15 3.7 Solid Circle, 1-14" Diameter Lower Temperature Edge of Solid Di sk 2-3/4" Element 288 3 Diameter and 1/2" Thick Manway Stud and Nut 71 4-1/4 Solid Circle, 1-1/2" Diameter
- 4. Main Coolant Pump and Piping Temperature Nozzle Edge of Solid Disk 2-3/4" with RTD Assembly 1,095 8 Diameter and 1/2" Thick Surge and Spray Piping Thermal Wells Edge of Solid Di sc 2-3/4" n with RTD Assembly 277 3-3/4 Diameter and 1/2" Thick
( l N._/
(1) All materials are s teel. (continued) Amendment No. 7 March 31, 1982
TABLE 3.5-1 (Cont'd.) (Sheet 2 of 2)
KINETIC ENERGY OF POTENTIAL MISSILES Initial Kinetic Weight Item Energy (ft-lb) (lb) Impact Section Main Coolant Pump Edge of Solid Disk 2-3/4" Thermal Well with RTD 1,095 8 Diameter and 1/2" Thick 5
O O
Amendment No. 5 October 26, 1981
Ch For Class 2 and 3 pressure retaining parts of active pumps, the primary Q
membrane stress is limited to the allowable stress value S, and primary membrane plus bending stress is limited to 1.55 for each of the loading combinations associated with the upset, emergency and faulted plant operating conditions.
The stress criteria of the ASME Code,Section III are applied in the design of component supports to the same Code Class as the pressure boundary involved within the jurisdictional boundaries defined in the code for the loading conditions defined above. Those steel support structures which are considered to be an extension of the building structure, but supplied with the pump assembly (i.e. bedplates), are designed to the stress criteria of the AISC Manual of Steel Construction.
In addition, the Safeguard Pump assemblies are required to be capable of withstanding the following thermal transients:
a) HPSI and LPSI, suction temperature increases from 40 F to 300 F in 10 seconds. After each temperature change the end point is assumed to hold until temperature equilibrium is attained. Temperature returns to 40 F in several days. This transient would be applied a minimum of 10 times during the design life of the pump.
b) LPSI shutdown cooling operation applied for 500 cycles as follows:
- 1. Suction temperature increases from 70 F to 350 F in about 1 g minute.
- 2. Suction temperature descrease from 350 F to 70 F in several hours.
i 3.9.3.2 Pump and Valve Operability Assurance 1 3.9.3.2.1 Non-NSSS Active ASME Code Class 2 and 3 Pumps and Class 1,
) 2, and 3 Valves l See Applicant's SAR.
3.9.3.2.2 NSSS Active ASME Code Class 2 and 3 Pumps and Class 1, 2 and 3 Valves 3.9.3.2.2.1 Operability Assurance Program l.
Active pumps and valves are defined in Regulatory Guide 1.48 as components that require a mechanical motion in performing a safety function. The operability (i.e. , performance of this mechanical motion) of active components during and after exposure to design bases events is confirmed per the recommendations of Regulatory Guide 1.48 by:
A. Designing each component to be capable of performing all safety func-i tions during and following design bases events. The design specifica-lp tion includes applicable loading combinations, and conservative design 1
3 3.9-39 1
, - , , - - - . . - - - - - - , - , - n- - -- , -- -- - --- - - - - - - - , - - , - --
limits for active components, consistent with the recommendations of Regulatory Guide 1.48. The specification requires that the manufacturer demonstrate operability by analysis or test (footnotes 6 and 11 of 7
Regulatory Guide 1.48). The results are independently reviewed by the NSSS Supplier considering the effects of postulated failure modes on operabil i ty.
B. Analysis and/or test demonstrating the operability of each design under the most severe postulated loadings which are combined in a manner consistent with the recommendations of Regulatory Guide 1.48.
Methods /results cf operability demonstration programs are detailed in 7
Sections 3.9.3.2.2.2 and 3.9.3.2.2.3.
C. Inspection of each component to assure compliance of critical parameters with specifications and drawings. This inspection confirms that specified materials and processes were used, that wall thicknesses met code requirements, and that fits and finishes met the manufacturer's requirements based on design clearance requirements. [7 D. Shop testing of each component to verify "as built" conditions as 7
defined in Sections 3.9.3.2.2.2 and 3.9.3.2.2.3.
E. Startup and periodic inservice testing in accordance with ASME Boiler and Pressure Vessel Code,Section XI to demonstrate that the active 7 pumps and valves are in operating condition throughout the life of the plant.
NSSS active pumps are listed below with a brief description of active safety function of each. NSSS active valves are listed in Table 3.9.3-3.
Active Components Active Safety Function High-pressure safety injection pumps Operate at flowrates to runout Low-pressure safety injection pumps Operate at flowrates to runout Charging pumps Operate 3.9.3.2.2.2 Operability _ Assurance _ Program Results for Active Pumps 3.9.3.2.2.2.1 High- and Low-Pressure Safety _ Injection Pumps. Opera-
~
bility of the high- and low-pressure safety injection (iiPSI and LPSI) pumps under faulted conditions has been demonstrated by analyses of the assemblies and by analyses and tests of the motors in accordance with the recommendations of Regulatory Guide 1.48.
Amendment No. 7 March 31, 1982 3.9-40
. . . - - . - . -. . _ = -. _ .- ..
4 1
i i
4
- For the HPSI pumps, the manufacturer has shown that allowable stresses are not exceeded, that clearances are acceptable and that shaft and pedestal
- bolt deflections do not cause stresses to exceed the normal values indicated by past experience for other pumps of the same type.
j 7
i For the LPSI pumps, the manufacturer has shown that allowable stresses are not exceeded and that clearances remain acceptable under faulted loadings.
Where necessary, lumped mass models are used with the computer programs to determine the natural frequencies and displacements. The models are conser-vative (i.e. , simplifications tend to make them more flexible).
Operability was demonstrated under the following loads; l HPSI Pump LPSI Pump
~
Horizontal seismic, g's 1.1 1.1 Vertical seismic, g's I*I I*I Design pressure, lb/in.2 2050 2050 Suction nozzle max, resultant force,-lb 4000 4000 Suction nozzle max, resultant moment, ft-lb 12000 50000 i Discharge nozzle max, resultant force, lb 2500 6500 l Discharge nozzle max, resultant moment, ft-lb 2500 16000
! To verify "as built" conditions the HPSI and LPSI pumps were hydrostatically j tested in accordance with the ASME Boiler and Pressure Vessel Code,Section III to confirm acceptability of structural integrity of pressure retaining parts, tested for seal leakage, and tested for performance and NPSH charac-i teristics in accordance with the Hydraulic Institute Standard to verify 1
operation within specified parameters. The motors 'were built as Class IE 7 l and were tested in accordance with IEEE Standard ll2A-1964 to verify opera-l tion within specified parameters. Additionally, the motors were qualified to IEEE Standard 323-1974 and IEEE Standard 344-1975 to assure operability i
during and following design basis events.
3.9.3.2.2.2.2 Cha rg i ng__ Pumps..
The charging pumps have a relatively complex geometry, which is difficult to analyze. Therefore, a simplified analysis and type test were used to confirm the charging pump operability i- during and following a DBE.
l t
Amendment No. 7 l\ March 31, 1982 i
3.9-41 i
A sinusoidal test with simultaneous 1.5 g horizontal and vertical accelera-tions was conducted. The test on the pump assembly, including its supports, 17 showed no significant natural frequencies in the 1 to 33 Hz range. The fundamental linear natural frequency of the rotating parts of the pump was shown to be greater than 73 Hz. The base of the test pump had a fundamental natural frequency above 33 Hz. Therefore, the System 80 pumps are rigid to postulated seismic input.
The test pump was vibration tested with 2410 psig internal pressure,1825-pound axial force and 610 ft-lb moment on the suction nozzle, and 1650-pound axial force and 550 ft-lb moment on the discharge nozzle. Simultane-ous 1.59 accelerations is applied to the horizontal and vertical axes by driving the assembly in a 45 degree plane. The test was run with the horizontal input parallel to the motor axis. It was repeated with the l7 horizontal input directed 90,180, and then 270 degrees from the direction for the first test.
The pump was subjected to two sinusoidal sweeps at 1/2 octave per minute in each direction with 1.0g peak accelerations, limited to 12-inch double amplitude, from 1 to 35 Hz. One of the sweeps in each direction was with the pump operating and one with the pump idle. The test shows that no resonances applicable to operability are in the range of concern, and the unit is therefore rigid to the postulated seismic input. The assembly, both operating and nonoperating, was exposed to a 1.5g horizontal and vertical 30-second sinusoidal dwell at 2.5, 10, 12.25, 20, 23.8 and 33 Hz.
The pump was shown to operate normally, and no evidence of damage or deteri- l7 oration to critical parts exists. The 1.5g horizontal and vertical accelera-tions exceed the applicable response spectra. The successful test on these pumps demonstrates that the System 80 pumps operate during and following the postulated seismic event.
To verify "as built" conditions the charging pumps were hydrostatically tested in accordance with the ASME Boiler and Pressure Vessel Code,Section III to confirm acceptability of structural integrity of pressure retaining parts, tested for seal leakage, and tested for performance and NPSH charac-teristics in accordance with the Hydraulic Institute Standards to verify operation within specified parameters. The motors were built as Class IE 7 and were tested in accordance with IEEE Standard ll2A-1964 to verify opera-tion within specified parameters. Additionally, the motors were qualified to IEEE Standard 323-1974 and IEEE Standard 344-1975 to assure operability during and following design basis events.
3.9.3.2.2.3 0_perability_ Assurance Program for Active Valves Safety _related active valves must perform their mechanical motion in times of an accident. The qualification program assures that these valves will operate during a seismic event. Qualification tests and/or analyses are conducted for all active valves. l 7
Class 1, 2 and 3 valves are designed / analyzed according to the rules of the ASME Boiler and Pressure Vessel Code,Section III, Section NB-3500, NC-3500, and ND-3500 respectively.
Amendment No. 7 March 31, 1982 O
l 3.9-42 l
Procurement specifications for safety related active valves stipulate that vendor shall submit either detailed calculations and/or test data to demon-Ci strate operability when subjected to the specification loading and stress criteria (normal through faulted conditions). The decision to accept actual or prototype test data, or analysis for operability assurance is made during the normal design and procurement process. The decision to test is based on (1) whether the component is amenable to analysis, (2) whether proven analytical methods are available, and (3) whether applicable i prototype test data is available. If analysis or prototype test data is not sufficient, testing is conducted to qualify the component or to verify the analytical technique.
Where appropriate, valve stem deflection calculations are performed to determine deflections due to short term seismic and other applicable load-ings. Deflections so determined are compared to allowable clearances. It
- must be noted that seismic events are of short duration; thus, contact (if D it occurs) does not demonstrate that operability is adversely affected.
Cases where contact occurs are reviewed on a case by case basis to deter-mine acceptability.
1 The operability of active Code Class 1, 2 and 3 components is assured
. through an extensive program of design verification, qualification testing and thorough surveillance of the manufacturing, assembly and shop testing of each active component. Each aspect of the design related to pressure boundary integrity and operability is either tested or verified by calcu-lations. Procedures for testing are developed by component manufacturers and reviewed and approved by the NSSS supplier before the tests are con-O ducted. The design analyses of the component take into consideration environmental conditions including loadings developed from seismic, opera-tional effects, and pipe loads. Where necessary and feasible, the con-clusions of these analyses are confirmed by test.
7 On all active valves, an analysis of the extended structure is also per-formed for static equivalent seismic SSE loads supplied at the center of gravity of the extended structure. The maximum stress limits allowed in these analyses show that structural integrity is within the limits devel-i oped and accepted by the ASME Code.
The safety-related valves are subjected to a series of tests prior to service and during the plant life. Prior to installation, the following tests are performed; shell hydrostatic test to ASME Sections III require-t ments, backseat and main seat leakage tests, disc hydrostatic test, func-tional tests to verify that the valve will open and close within the spe-
- cified time limits, operability qualification of motor operators for the environmental conditions over the installed life (i.e., aging, radiation, accident environment simulation, etc.) according to IEEE 382. Cold hydro qualification tests, hot functional qualification tests, periodic in-service inspections, and periodic inservices operation are performed in-I situ to verify and assure the functional ability of the valves. These tests ensure the reliability of the valve for the design life of the plant.
The valves are designed using either stress analyses or the pressure con-
, taining minimum wall thickness requirements.
l\ Amendment No. 7 March 31, 1982 3.9-43 i
All the active valves shall be designed to ave a first natural frequency which is greater than 33 Hz. This is shown by suitable test or analysis.
The above outlines in general the methods used to assure valve operability.
Each vendor's specific program is described in the plant specific FSAR.
In addition to the above, the following specific operability assurances are provided for the various type valves: ,
3.9.3.2.2.3.1 Pneumat_ically_0perated Valves l Pneumatic operated valves are furnished by several vendors in CE System 80 j Nuclear Power Plants. Methods of operability demonstration are discussed in general but will be discussed in detail in the plant specific FSAR subject to the vendor (s) utilized. Spring actuation of the valve is the required active safety function. Loss of electric power or supply air will result in venting of the actuator and return of the valve to the safe position. Each vendor provides their own nothod to demonstrate valve operability. The operability for these valves is demonstrated by analysis, test or by a combination of analysis and test. The vendor considers concurrent loads including seismic, design pressure and pipe loads. !
The three-way solenoid valve was qualified by test to IEEE-382-1972, IEEE- !
323-1974 and IEEE-344-1975. Testing included thermal aging, radiation '
aging, wear aging, vibration endurance, seismic event simulation, and loss of coolant accident. All test results provided satisfactory evidence of air solenoid valve operability.
l7 Limit switches, used to determine valve position, were qualified by testing to IEEE-323-1974, IEEE-344-1975 and IEEE-382-1972. Switches were success-fully performance tested for aging simulation, wear aging, radiation ex-posure, seismic qualification, and design basis event environmental con-ditions. For valves outside of containment and utilizing EA-170 limit switches, the switches were seismically qualifieg to IEEE-344-1975 and were tested to sustain radiation dosages up to 2 x 10 rads.
3.9.3.2.2.3.2 Motor Operated Valves Motor operated valves are qualified by analysis as a minimum as described above. The analysis for each valve assembly considers the effects of seismic loads, design pressure, and piping reaction forces to provide assurance of operabi li ty.
To provide full qualification of the motor operated valve actuator, en-vironmental and seismic qualification tests were conducted to simulate the following conditions:
A. Inside Containment (LOCA)
B. Outside Containment C. Seismic Qualification D. Steam Line Break Accident Amendment No. 7 O
3.9-44
Mid-size valve actuators were subjected to complete environmental qualifi-cation consisting of inside containment and outside containment. Each A qualification exposed the actuator to thermal and mechanical aging, radia-( tion aging, seismic aging, environmental transient profile test, and steam line break. For the steam line break test an actuator was subjected to a very high superheated temperature to demonstrate that the electrical com-ponents of the actuator never exceeded the saturated temperature correspon-ding to the ambient pressure for the short duration of the test. This short term test proves the existing qualification envelopes the steam line break for superheated temperatures as high as 492 F for a few minutes.
The qualification of the mid-size valve actuator was used to generically qualify all sizes of mid-size valve actuator operators for the environ-mental test conditions in accordance with IEEE-382-1972. All sizes are constructed of the same materials with components designed to equivalent stress levels, and to the same clearances and tolerances with the only differnece being in physical size which varies corresponding to the dif-ferences in unit rating.
All the qualifications were conducted per IEEE 382-1972 and meet the re-quirements of IEEE 323-1974 and IEEE 344-1975 as they apply to valve motor actuators. Further, since the actuators performed satisfactorily without maintenance throughout the various qualifications, the valve actuators are fully qualified for use in CE fluclear power Generating Plants.
3.9.3.2.2.3.3 Pressurizer Safety _ Valves f- m Pressurizer Safety valves are 6 x 8 valves. Operability has been successfully demonstrated by a combination of dynamic testing and analysis or by static (v) testing. Operability was successfully demonstrated with a 69 seismic load by one vendor or with a 7.19 seismic load by another vendor. Dynamic testing 7 has demonstrated that the natural frequency of both valves was greater than 33 Hz. A summary of the test programs follows:
A. Vendor A Safety Valves
- 1. Natural Frequency Demonstration Vibration input was in a single, horizontal direction. It was established by previous experience that the horizontal direction Was more significant than the vertical direction, and that there
- was no material difference between teh various horizontal direc-tions. The frequency of vibration was increased from 5 to 75 Hz at a rate of 1 octave per minute. Accelerometers were mounted on the valve assembly. The actual natural frequency under test conditions was 38 Hz.
- 2. Operability _ Demonstration l A series of tests demonstrated that the valve would fully open i and reseat during and after a seismic acceleration. Vibration input ranged from 3 to 6g and 10 to 33 Hz. The tests were O
Amendment No. 7 March 31,1982 3.9- 44a
1 1
performed using saturated steam. In addition, analysis was used to establish the significance of nozzle loading. The results indicated that deformation was significantly less than the inter-nal clearances. This loading was therefore neglected in the seismic operability tests. l B. Vendor B Safety Valves
- 1. Natural Frequency Demonstration A resonance survey was performed along three orthogonal axes with one axis being the centerline of the outlet port. (Valve mounted on inlet port.) No resonant frequencies were detected in the range of 1-50 Hz on any axis.
- 2. Operability Demonstration A series of tests demonstrated that the valve would fully open and reseat during and after applying the following loading com-binations: Static seismic loads up to 7.lg were applied to the valve in the direction of least bending stiffness. In addition the maximum permissable piping loads were applied concurrently.
The tests were performed using saturated steam. Valve operation was satisfactory.
C. EPRI Testing of Safety Valves One manufacturer's valve was tested in the EPRI Test Program under full pressure and full flow conditions. This testing has demonstrated that stable valve operation under these conditions is dependent upon the inlet pipe configuration, built up back pressure range and blow- 7 down setting. Prior to plant startup the inlet pipe configuration and built up back pressure range for each specific plant will be examined by CE and the applicable valve vendor. If necessary, the valves will be adjusted to provide blowdown settings which will result in stable valve operation. These blowdown settings will be recommended by the vendor and approved by CE. These adjustments will be based on the results obtained in the EPRI Test Program. Required adjustments to the valve to assure operability will be documented in the plant spe-cific FSAR.
3.9.3.2.2.3.4 Check Valves. The check valves are characteristically simple in design and their operation will not be affected by seismic accelera-tions or the maximum applied nozzle loads. The check valve design is compact and there are no extended structures or masses whose motion could cause distortions which could restrict operation of the valve. The nozzle loads due to maximum seismic excitation will not affect the functional ability of the valve since the valve disc is designed to be isolated from the casing wall. The clearance supplied by the design around the disc will prevent the disc from becoming bound or restricted due to any casing dis-trotions caused by nozzle load. Therefore, the design of these valves is l Amendment No. 7 March 31, 1982
- 3. 9- 44 b
such that once the structural integrity of the valve is assured using standard design or analysis methods, the ability of the valve to operate is {
assured by the design features. In addition to these design considerations, the valve will also undergo, (1) stress analysis including the SSE loads, (2) in-shop hydrostatic tests, (3) in-shop seat leakage test, and (4) 7 ;
periodic in-situ valve exercising and inspection to assure the functional i ability of the valve.
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Amendment No. 7 March 31, 1982 3.9- 44c
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s 3.9.3.3 Design and Installation Details for Mounting of Pressure Relief ;
1 Devices r
1
- See Applicant's SAR.
3.9.3.4 Component Supports Supports for ASME Section III Code Class I components in the CESSAR scope j are specified for design in accordance with the loads and loading combinations
- discussed in Section 3.9.3.1.
I Amendment No. 7
)1 March 31, 1982
- 1 3.9-45
In addition to the normal operating and seismic supports, component stops are employed to limit displacements for postulated pipe breaks. Where a component stop is designed solely to control movement following a postulated pipe break, only the design loading combination (d) of Section 3.9.3.1 is specified.
Component supports which are loaded during normal operation, seismic and following a pipe break are specified for design for loading combinations (a) through (d) of Section 3.9.3.1. Component stops which are loaded only following a pipe break are specified for design for loading combination (d). Design stress limits applied in evaluating loading combinations (a),
(b), and (c) of Section 3.9.3.1 are consistent with the ASME Code,Section III. The design stress limits applied in evaluating loading combination (d) of Section 3.9.3.1 are in accordance with the ASME Cede,Section III.
Loads in compression members are limited to 2/3 of the critical buckling load.
For design criteria for restraints provided solely to control movement of postulated broken piping, see the Applicants SAR.
To insure that pipe restraints and component stops do function independently of the normal support system, the motions of the intact pipe due to all normal and upset plant conditions and vibratory motion of the SSE are calculated and used to specify a minimum clearance between the pipe and the restraint. Wherever possible, gaps between pipes and restraints are maximized to avoid possible contact during plant operation. Where a parti-cular location requires minimizing a gap, special features are provided to permit adjustment of the gap size during hot functional testing in order to decrease the uncertainty in tha calculated pipe motion in the vicinity of the restraint. See Applicants SAR for details of pipe restraint design.
O 3.9-46
TABLE 3.9.3-3 NSSS SEISMIC I ACTIVE VALVES (q)
(Sheet 1 of 8) 7 xJ ASME VALVE SYSTEM NAME LINE VALVE SECTION III ACTUATOR NO. _(sa fety_ functionj SIZE TYPE CODE CLASS TYPE SI 134 Safety Injection Sys. 12 Swing Check 1 None (Operate)
SI 143 Safety Injection Sys. 4 Swing Check 1 None (0perate)
SI 144 Safety Injection Sys. 12 Swing Check 1 None (0perate)
SI 164 Safety Injection Sys. 10 Swing Check 2 None (Operate)
SI 165 Safety Injection Sys. 10 Swing Check 2 None (Opera te)
SI 179 Shutdown Cooling Suction 6 x 10 Relief 2 None Relief SI 189 (Operate) 6 x 10 Relief 2 None SI 215 Safety Injection Sys. 14 Swing Check 1 None (Operate)
SI 217 Safety Injection Sys. 14 Swing Check 1 None p (Operate) i j SI 225 Safety Injection Sys. 14 Swing Check 1 None
\d (Operate)
SI 227 Safety Injection Sys. 14 Swing Check 1 None (0perate)
SI 235 Safety Injection Sys. 14 Swing Check 1 None (Operate)
SI 237 Safety Injection Sys. 14 Swing Check 1 None 7 (Operate)
SI 245 Safety Injection Sys. 14 Swing Check 1 None (Operate)
SI 247 Safety Injection Sys. 14 Swing Check 1 None (Operate)
SI 321 Safety Injection Sys. 3 Globe 2 Motor (Operate)
SI 322 Safety Injection Sys. 1 Globe 1 Pneui'ia ti c (Close)
SI 331 Safety Injection Sys. 3 Globe 2 Motor (0perate)
SI 332 Safety Injection Sys. 1 Globe 1 Pneumatic (Close)
SI 522 Safety Injection Sys. 3 Swing Check 1 None (Operate)
SI 523 Safety Injection Sys. 3 Swing Check l None (Operate)
SI 532 Safety Injection Sys. 3 Swing Check l None
/]
Q SI 533 (Operate)
Safety Injection Sys. 3 Swing Check 1 None (Operate)
Amendment No. 7 March 31, 1982
TABLE 3.9.3-3 115S5 SEISMIC I ACTIVE VALVES (Sheet 2 of 8) l7 ASME VALVE SYSTEM TIAME LItiE VALVE SECTI0f4 III ACTUATOR fi0. ] safety functionl SIZE TYPE CODE CLASS TYPE SI 605 Safety Injection Tank 1 Globe 2 Solenoid Vent (Operate)
SI 606 Safety Injection Tank 1 Globe 2 Solenoid Vent (Operate)
SI 607 Safety Injection Tank 1 Globe 2 Solenoid Vent (Operate)
SI 608 Safety Injection Tank 1 Globe 2 Solenoid Vent (Operate)
SI 611 Safety Injection Tank 2 Globe 2 Pneumatic Fill Valve (Close)
SI 613 Safety In.jection Tank 1 Globe 2 Solenoid Vent (Operate)
SI 614 Safety Injection Tank 14 Gate 1 Motor Isolation (Operate)
SI 615 LPSI Header Isolation 12 Globe 2 Motor Valve (Operate)
SI 616 HPSI Header Valve 2 Globe 2 Motor (Operate)
SI 617 liPSI Header Valve 2 Globe 2 Motor (Operate)
SI 618 Leakage Return to RtH 1 Globe 1 Pneumatic (Close)
SI 621 Safety Injection Tank 2 Globe 2 Pneumatic Fill Valve (Close)
SI 623 Safety Injection Tank 1 Globe 2 Solenoid 7 Vent (Operate)
SI 624 Safety Injection Tank 14 Gate 1 Motor Isolation (Operate)
SI 625 LPSI Header Isolation 12 Globe 2 Motor Valve (Operate)
SI 626 HPSI Header Valve 2 Globe 2 Motor (Operate)
SI 627 HPSI Header Valve 2 Globe 2 Motor (Operate)
SI 628 Leakage Return to RWT 1 Globe 1 Pneumatic (Close)
SI 631 Safety Injection Tank 2 Globe 1 Pneumatic Fill Valve (Close)
SI 633 Safety Injection Tank 1 Globe 2 Solenoid Vent (Operate)
SI 634 Safety Injection Tank 14 Gate 1 Motor Isolation (Operate)
SI 635 LPSI Header Isolation 12 Globe 2 Motor Valve (Opera te)
Amendment tio. 7 March 31,1982 I
m TABLE 3.9.3-3 NSSS SEISMIC I ACTIVE VALVES (Sheet 3 of 8) l7 ASME VALVE SYSTEM NAME LINE VALVE SECTION III ACTUATOR NO. (safety function) SIZE TYPE CODE CLAS$ TYPE SI 636 HPSI Header Valve 2 Globe 2 Motor (Operate)
SI 637 HPSI Header Valve 2 Globe 2 Motor (Operate)
SI 638 Leakage Return to RWT 1 Globe 1 Pneumatic (Close)
SI 641 Safety injection Tank 2 Globe 2 Pneumatic Fill Valve (Close)
SI 643 Safety Injection Tank 1 Globe 2 Solenoid Vent (Operate)
SI 644 Safety Injection Tank 14 Gate 1 Motor Isolation (Operate)
SI 645 LPSI Header Isolation 12 Globe 2 Motor Valve (0perate)
(nd'I646 HPSI Header (Operate)
Valve 2 Globe 2 Motor SI 647 HPSI Header Valve 2 Globe 2 Motor (Operate)
SI 648 Leakage Return to RWT 1 Globe 1 Pneumatic (Close)
SI 651 Shutdown Cooling Suction 16 Gate 1 Motor (Operate)
SI 652 Shutdown Cooling Suction 16 Gate 1 Motor 7 (Operate)
SI 653 Shutdown Cooling Suction 16 Gate 1 Motor (Operate)
SI 654 Shutdown Cooling Suction 16 Gate 1 Motor (Operate)
SI 655 Shutdown Cooling Suction 16 Gate 2 Motor (0perate)
SI 656 Shutdown Cooling Suction 16 Gate 2 Motor (Operate)
SI 690 Safety Injection Sys. 10 Globe 2 Motor (Operate)
SI 691 Safety Injection Sys. 10 Globe 2 Motor (0pera te)
SI 157 Safety Injection Sys. 18 Swing Check 2 None (Operate)
SI 158 Safety Injection Sys. 18 Swing Check 2 None i N (Operate)
Amendment No. 7 March 31, 1982
TABLE 3.9.3-3 NSSS SEISMI,Q__I ACTIVE VALVES (Sheet 4 of 8) 7 ASME VALVE SYSTEM NAME LINE VALVE SECTION III ACTUATOR NO. .(safety function) SIZE TYPE CODE CLASS TYPE SI 200 Safety Injection Sys. 20 Swing Check 2 None (Operate)
SI 201 Safety Injection Sys. 20 Swing Check 2 None (Operate)
SI 205 Safety Injection Sys. 24 Swing Check 2 None (Operate)
SI 206 Safety Injection Sys. 24 Swing Check 2 None (Opera te)
SI 306 Safety Injection Sys. 10 Globe 2 Motor (Opera te)
SI 307 Shutdown Cooling Sys. 10 Globe 2 Motor (Operate)
SI 404 Safety Injection Sys. 4 Swing Check 2 None (Operate)
SI 405 Safety Injection Sys. 4 Swing Check 2 None (Opera te)
SI 424 Safety Injection Sys. 2 Lift Check 2 None (Operate)
SI 426 Safety Injection Sys. 2 Lift Check 2 None (0perate)
SI 434 Safety Injection Sys. 10 Swing Check 2 None (Opera te)
SI 446 Safety Injection Sys. 10 Swing Check 2 None (Operate) 7 SI 448 Safety Injection Sys. 2 Lift Check 2 None (Operate)
SI 451 Safety Injection Sys. 2 Lift Check 2 None (Opera te)
SI 484 Safety Injection Sys. 10 Swing Check 2 None (Operate)
SI 485 Safety Injection Sys. 10 Swing Check 2 None (Opera te)
SI 486 Safety Injection Sys. 2 Lift Check 2 None (Operate)
SI 487 Safety Injection Sys. 2 Lift Check 2 None (Operate)
SI 604 HPSI Hot Leg Isolation 3 Gate 2 Motor (Operate)
SI 609 HPSI Hot Leg Isolation 3 Gate 2 Motor (Opera te)
SI 657 Shutdown Cooling 16 Butterfly 2 Motor (Operate)
SI 658 Shutdown Cooling 16 Butterfly 2 Motor (Operate)
Amendment No. 7 March 31, 1982
/^N TABLE 3.9.3-_3
(' !
NSSS SEISMIC _I ACTIVE VALVES (Sheet 5 of 8)
ASME VALVE SYSTEM NAME LINE VALVE SECTION III ACTUATOR NO. [ safety function 1 SIZE TYPE CODE CLASS TYPE SI 659 Mini Flow Isolation 4 Globe 2 Solenoid (Operate)
SI 660 Mini Flow Isolation 4 Globe 2 Solenoid (Operate)
SI 664 CSP Mini Flow Isolation 2 Globe 2 Motor (Operate)
SI 665 CSP Mini Flow Isolation 2 Globe 2 Motor (Operate)
SI 666 HPSI Pump Mini Flow 2 Globe 2 Motor Isolation (0perate)
SI 667 HPSI Pump Mini Flow 2 Globe 2 Motor Isolation (Operate)
SI 668 LPSI Pump Mini Flow 2 Globe 2 Motor Isolation (Operate)
SI 669 LPSI Pump Mini Flow 2 Globe 2 Motor Isolation (Operate)
Containment Spray Isolation 8 Gate 2 Motor h SI 671 valve (Operate)
SI 672 Containment Spray Isolation 8 Gate 2 Motor Valve (Operate)
SI 673 Sump Suction Isolation 24 Butterfly 2 Motor (Operate)
SI 674 Sump Suction Isolation 24 Butterfly 2 Motor (Operate)
SI 675 Sump Suction Isolation 24 Butterfly 2 Motor (Opera te)
SI 676 Sump Suction : solation 24 Butterfly 2 Motor 7
(Operate)
SI 678 CSP Flow Control Valve 10 Butterfly 2 Motor (Operate)
SI 679 CSP Flow Control Valve 10 Butterfly 2 Motor (Operate)
SI 682 SIT Fill Line 2 Globe 2 Pneumatic (Close)
SI 683 LPSI Pump Suction 20 Gate 2 Motor (Opera te)
SI 684 CSP Discharge 10 Gate 2 Motor (Operate)
SI 685 LPSI Discharge 10 Gate 2 Motor (Operate)
SDCHX Discharge 20 Gate 2 Motor (n SI
) 686 (Operate)
V SI 687 SDCHX Discharge 10 Gate 2 Motor j (Operate)
Amendment No. 7 March 31, 1982
TABLE 3.9.3-3 NSSS SEISMIC I ACTIVE VALVES (Sheet 6 of 8)
ASME VALVE SYSTEM NAME LINE VALVE SECTION III ACTUATOR NO. _(safety function 1 SIZE TYPE CODE CLASS TYPE SI 688 SDCHX Spray Bypass 10 Gate 2 Motor (Operate)
SI 689 CSP Discharge 10 Gate 2 Motor (Operate)
SI 692 LPSI Pump Suction 20 Gate 2 Motor (Operate)
SI 693 SDCHX Spray Bypass 10 Gate 2 Motor (Operate)
SI 694 LPSI Discharge 10 Gate 2 Motor (Operate)
SI 695 SDCHX Discharge 10 Gate 2 Motnr (Operate)
SI 696 SDCHX Discharge 20 Gate 2 Motor (Operate)
SI 698 HPSI Pump Orifice Bypass 4 Gate 2 Motor (0perate)
SI 699 HPSI Pump Orifice Bypass 4 Gate 2 Motor (Operate)
SI 113 Safety Injection Sys. 4 Check 1 None (Operate)
Si 114 Safety Injection Sys. la Check 1 None (Operate)
SI 123 Safety Injection Sys. 4 Check 1 None (Operate)
SI 124 Safety Injection Sys. 12 Check 1 None 7 (Operate)
SI 133 Safety Injection Sys. 4 Check l None (Operate)
CH 118 VCT Outlet Check 4 Swing Check 2 None (Opera te)
CH 190 Gravity Feedline Check 3 Swing Check 2 None (Operate)
CH 203 Auxiliary Spray 2 Globe 1 Solenoid '
(Operate)
CH 205 Auxiliary Spray 2 Globe 1 Solenoid (Operate)
CH 240 Charping Line Backpressure 2-1/2 Globe 1 Pneumatic b'ose)
CH 255 Seal Inj. Containment 1-1/2 Globe 2 Motor Isolation (0 pen)
CH 305 RWT Suction Check 20 Swing Check 2 None (Operate)
CH 306 RWT Suction Check 20 Swing Check 2 None (Operate)
Amendment No. 7 March 31, 1982
-s TABLE 3.9.3-3
( '\
G/ NSSS SEISMIC I ACTIVE VALVES (Sheet 7 of 8)
ASME VALVE SYSTEM NAME LINE VALVE SECTION III ACTUATOR NO. ] safety _ function) SIZE TYPE CODE CLASS TYPE Cli 328 Charging Line Check 2 Lift Check 2 None (Operate)
CH 331 Charging Line Check 2 Lift Check 2 None (Operate)
CH 334 Charging Line Check 2 Lift Check 2 None (Operate)
CH 431 Auxiliary Spray Check 2 Lift Check 1 None (0perate)
Cil 433 Charging Line Check 2-1/2 Lift Check l None (Operate)
Cll 440 HPSI Header Check 2 Lif t Check 2 None (Opera te)
CH 494 RMW Supply Line to RDT l-1/2 Lift Check 2 None Check (Operate)
CH 505 RCP Controlled Bleed-0ff 1 Globe 2 Pneuma tic n Containment Isolation
( ) CH 506 (Close) 1 Globe 2 Pneumatic
'%./
CH 515 2 Globe 1 Pneumatic Letdown Isolation Valve CH 516 (Close) 2 Globe 1 Pneumatic Cll 523 2 Globe 2 Pneumatic CH 524 Charging Line Isolation 2-1/2 Globe 2 Motor Valve (0 pen) 7 CH 530 20 Gate 2 Motor RWT Suction Isolation CH 531 (Operate) 20 Gate 2 Motor Cll 560 RDT Suction Isolation 3 Globe 2 Pneumatic (Close)
CH 561 RDT Suction Isolation 3 Globe 2 Pneuma tic (Close)
CH 580 RMW Supply Isolation to 1-1/2 Globe 2 Pneumatic RDT Iso. (Close)
CH 639 Charging Line Check Valve 2-1/2 Lift Check 2 None (Operate)
CH 787 Seal Injection Check 1 Lif t Check 1 None (Operate)
CH 802 Seal Injection Check 1 Lift Check l None
./ (Operate)
(' ]j CH 807 Seal Injection Check 1 Lift Check 1 None (Operate)
Amendment No. 7 March 31, 1982
TABLE 3.9.3-3 flSSS SEISMIC I ACTIVE VALVES (Sheet 8 of 8)
ASME VALVE SYSTEM f4AME LIflE VALVE SECTION III ACTUATOR fl0._ isafety function 1 SI_ZE TYPE CODE CLASS TYPE CH 812 Seal Injection Check 1 Lift Check 1 None (Operate)
CH 835 Seal Injection Check 1-1/2 Lift Check 2 None (Operate)
CH 866 Seal Injection Check 1 Lift Check 1 None (Operate)
CH 867 Seal Injection Check 1 Lift Check l flone (0perate)
CH 868 Seal Injection Check 1 Lift Check 1 None (Operate)
CH-869 Seal Injection Check 1 Lift Check 1 None (Operate)
RC 200 RCS (Opera te) 6x8 Safety 1 None RC 201 RCS (Operate) 6x8 Sa fety 1 None RC 202 RCS (Operate) 6x8 Safety 1 None RC 203 RCS (Operate) 6x8 Safety 1 None RC 244 RCS (Operate) 4 Check 1 None IR 100 Iodine Removal Sys. 1 Vacuum Breaker 2 None (Operate)
IR 118 Iodine Removal Sys. 1 Vacuum Breaker 2 None (Operate) 7 IR 120 Iodine Removal Sys. 1/2 Check 2 None (Operate)
IR 130 Iodine Removal Sys. 1/2 Check 2 None (Opera te)
IR 680 Iodine Removal Sys. 1/2 Globe 2 Solenoid (0perate)
IR 681 Iodine Removal Sys. 1/2 Globe 2 Solenoid (Operate)
IR 682 Iodine Removal Sys. 1/2 Globe 2 Solenoid (Operate)
IR 683 Iodine Removal Sys. 1/2 Globe 2 Solenoid (Opera te)
NOTE: 1. (Operate) is defined as valve being capable of both opening and closing.
- 2. (Close) is defined as valve being capable of moving to or maintaining a closed position.
- 3. (0 pen is defined as valve being capable of moving to or maintaining an open position.
Amendment No. 7 March 31, 1982
3.11 EflVIR0flMENTAL _0_ESIGfl 0F MECHAflICAL ATID ELECTRICAL EQUIPMEf4T i
The design criteria with respect to environmental effects on tbn electrical gd and mechanical equipment of the Reactor Protective System and the Engineered Safety Features System to ensure acceptable performance in all environments (normal and accident) depend upon equipment location and function. Such equipment is qualified to meet its performance requirements under the environmental and operating conditions in which it will be required to function and for the length of time for which its function is required. As far as practical, equipment for these systems is located outside the Containment Building or other areas where adverse environmental conditions could exist.
Compatability of mechanical and electrical equipment with environmental conditions is provided within the following design criteria:
A. For operation under normal conditions the systems are designed and qualified to remain functional after exposures within the following ranges of environmental conditions:
- 1. Design temperatures maintained at the equipment location during normal operation by the ventilating and cooling system described in Section 9.4. Temperature ranges are given in Appendix 3.llA, Table 3.llA-1 thru 3.11A-14. l7
- 2. Relative humidity ranges are given in Appendix 3.llA, Table 3.ll A-1 thru 3.llA-14. l7 n 3. Pressure ranges are given in Appendix 3.ll A, Table 3.ll A-1 thru
/ 3.llA-14.
V) 4. Maximum expected integrated radiation exposures for 40 years at l7 the equipment location during normal operation are given in Appendix 3.ll A, Table 3.ll A-1 thru 3. ll A-14. l7 B. In addition to the normal operation environmental requirements given in listing A above, the mechanical and electrical components required to mitigate the consequences of a design basis event (DBE) or to attain a safe shutdown of the reactor are designed to remain functional l7 after exposure to the environmental conditions anticipated following the specific DBE which they are intended to mitigate. Anticipated environmental conditions and requirements are listed below.
- 1. The temperature, pressure, and humidity ranges following the design bases accidents such as the loss of coolant accident (LOCA), the main steam line break (MSLB), control element assembly ejection, or feedwater line break (FWLB), " Worst Case" combined 7 (LOCA & MSLB) are indicated in Appendix 3.ll A.
- 2. The time integrated post accident radiation doses are indicated in Appendix 3.llA. Equipment will be designed for the types and levels of radiation associated with normal operation plus the radiation associated with the limiting design basis accident (DBA). 7 If more than one type of radiation is significant each type may be p considered separately.
N) Amendment tio. 7 March 31, 1982 3-11-1
3.11.1 EQUIPMENT IDErlTIFICATION AND EriVIRONMENTAL CONDITIONS Appendix 3.11B lists and categorizes systems required to mitigate a DBE or to attain a safe shutdown. Specific equipment and components for each system are discussed in the appropriate section of the safety analysis report as referenced in Appendix 3.llB. The major component categories, such as motor-operated valves, pump motors, instrumentation and pressure boundary equipment in each system, and the location of the components by area are also provided.
3.11.2 QUALIFICATION TESTS AND ANALYSES Qualification tests and analyses performed in accordance with the methodologies defined in CENPD 255 Rev. 03 on NSSS instrumentation and electrical equipment (including pump and valve motors and electrical accessories) fulfill the requirements of IEEE Standard 323-1974, and " Category 1" of NUREG 0588. For mechanical equipment, environmental qualification is based on engineering, 7 evaluation, and material selection where sufficiently reliable data is available.
3.11.2.1 Compo_nent Environmental Desijn and Qualification for N_o rma_1_ Opera ti on Equipment listed in Appendix 3.11B is designed for 40 years of continuous operation in the temperature, pressure, humidity, and radiation environment that exists at the equipment location during normal operation, assuming proper routine preventive maintenance is performed, such a periodic replace-ment of seals and packing.
Appendix 3.llA provides the ranges of the design temperatures, pressure, and humidities, as well as the exposures to chemical spray and radiation for each area in which safety-related equipment listed in Appendix 3.llB is loca ted.
7 3.11.2.2 Component Environmental Design and _ Qualification for Operation After a DesiE Bas _is_ Event.
Equipment listed in Appendix 3.llB is designed to remain functional in the temperature, pressure, hunidity, and chemical spray environment conditions that exist at the equipment location after the design basis LOCA. This equipment is also designed for the maximum calculated integrated radiation Amendment No. 7 March 31, 1982 3.11-2
. _ . _ _ . - - . _ . ._ ~ . ._. . -_ - - - - . --._
l 1^
r exposure after the design basis LOCA, as discussed in Section 3.11.5. The temperature, pressure, and humidity environment inside the containment after a LOCA is discussed in detail in Section 6.2.1.3. The containment spray characteristics are given in Section 6.2.2.1. The integrated post-accident radiation dose for those a,eas at which equipment is located is
, given in Appendix 3.llA. The temperature, pressure, and humidity environment
- inside the containment after a MSLB is discussed in detail in Section i 6.2.1.4.
- The requirenents of the General Design Criteria, Appendix A to 10CFR50, are 1 met as follows
1 j -
Criterion 1 - Quality Standards and Records, refer to Section 3.1.1.
Criterion 4 - Environmental and Missile Design Basis, refer to
, Subsection 3.1.4.
Criterion 23 - Protection System Failure Modes, refer to Section 3.1.19.
Criterion 50 - Containment Design Basis, refer to Sections 3.1.43 and 6.2.1.
i The requirenents of the Quality Assurance Criterion III, Appendix B to 10CFR50 are met as discussed in the Design and Procurement Q.A. Program (See Chapter 17).
The recommendations contained in the documents discussed below, listings A i
through D, and other applicable Regulatory Guides and Standards have also been utilized.
. A. Regulatory Guide 1.30, Quality Assurance Requiranents for the Installa-i tion, Inspection, and Testing of Instrumentation and Electric Equipment.
B. Regulatory Guide 1.73, Qualification Tests of Electric Valve Operators Installed Inside the Containment of Nuclear Power Plants. A descripiton i
of the tests and analysis by which active NSSS valves are qualified is provided in Section 3.9.2.2.
C. The qualification methods and documentation requirements of IEEE i' Standard 323-1974 IEEE Standard for Qualifying Class IE Equipment for Nuclear Power Generating Stations and " Category 1" of NUREG 0588, are discussed in CENPD-255 Rev. 3 (Reference 1). l7
- D. Pressure boundary components inside the containment are designed for l 1 the appropriate temperature and pressure environment in accordance with the applicable code to which the component is constructed. l7 l
l Qualification testing is not considered necessar) for such components.
Amendment No. 7 March 31, 1982 i
3.11-3 i
--v- .- -- - - - .-- ,.----
RADIATION IN HARSH AND fiON-HARSH ENVIRONMENT Electrical Equipment will be designed for the types and levels of radiation associated with normal operation plus the radiation associated with the limiting Design Basis Accident (DBA). These levels are defined in Appendix 3.11A. If more than one type of radiation is significant, each type may be applied separately.
4 Electrical Equipment which is exposed to radiation above 10 Rads will be irradiated to its anticipated Total Integrated Dose (TID) prior to type testing unless determined by analysis that radiation does not effect its ability to perform its required function. Where the application of the accident dose is planned during DBA testing, it need not be included during the aging process.
4 Electrical Equipment which will be exposed to radiation levels 10 Rads or below will be analyzed to be determined whether low level radiation could impact its ability to perform its required function.
Electrical Equipment will be qualified to the typical radiation environments defined in Appendix 3.llA, as required.
Gamma Cobalt-60 is considered an acceptable gamma radiation source. Other sources may be found acceptable, and will be justified. Electrical Equipment will be tested to typical gamma radiation levels defined in Appendix 3.llA. 7 Beta Electrical Equipment exposed to beta radiation will be identified and an analysis will be performed to determine if the operability of the equipment is affected by beta radiation ionization and heating effects. Qualification will be performed by test unless analysis demonstrates that the safety function will not be degraded by Beta exposure. Equipment will be tested and/or analyzed to the beta radiation levels defined in Appendix 3.11A. Where testing is recommended, gamma equivalent radiation source will be used.
Neutron Electrical Equipment exposed to neutron radiation will be identified and neutron radiation levels defined. When actual neutron dose qualification testing is not performed, an equivalent gamma radiation dose will be used for qualification testing to simulate neutron exposure. The basis for establishing an equivalent gamma radiation dose will be provided.
Paints / Radiation Effects Electrical Equipment; an analysis will be performed addressing paint exposure to beta and gamma radiation, if required. Qualification of painted equipment will be by test if analysis indicates that the safety function of the equipment could be impaired by paint failure due to radiation.
Amendment No. 7 March 31, 1982 3.11-4
Chemical Spray After a postulated accident, such as the LOCA or MSLB, components located in the Containment Building may be exposed to a chemical spray from a solution used to remove iodine from the containment building atmosphere. Equipment will be environmentally tested to these conditions and performance requirements demonstrated during and after the test. The most severe spray composition will be determined by single failure analysis of the spray system. Corrosion effects due to long term exposure will be addressed, as appropriate.
Where qualification for chemical spray environment is required, the simulated spray will be initiated at the time shown in Appendix 3.llA.
Typical values of chemical spray composition, concentration and pH are defined in Appendix 3.llA, Tables 3.11A-1, 3.11A-2 and 3.11A-13.
3.11.3 QUALIFICATION TEST RESULTS 3.11.3.1 NSSS Instrumentation and Electrical Equipment Qualification testing and analyses of NSSS Instrumentation and Electrical Equipment are discussed in Reference 1.
3.11.3.2 NSSS Mechanical Equipment Qualification tests results and analyses of NSSS Mechanical Equipment are provided in Section 3.9.2.2 .
3.11.4 CLASS lE INSTRUMENTATION LOSS OF VENTILATION EFFECTS s
Loss of ventilation is discussed in the Applicant's SAR. Interface criteria are presented in Chapter 7. 7 Class lE equipment which is located in the control room or similar areas includes the following:
Plant Protection System Cabinet (PPS)
Auxiliary Relay Cabinet (ARC)
Auxiliary Protective Cabinet (APC)
Main Control Panels Process Instrument Cabinet Other instrumentation, such as process transmitters and signal converters and i the reactor trip switchgear system circuit breakers, are located in the l Auxiliary Building or Containment Building. Equipment in these areas is j
qualified for the maximum expected temperature, radiation, humidity, and pressure under which the equipment is expected to operate.
The following are the normal and abnormal environmental conditions for which C
O se-Ervice ClasslocationlEof safety-related equipment the equipment and the is qualified expected environmental to operate acco condition.
Amendment No. 7 3.ll-4a March 31, 1982
Appendix 3.ll A, Tables 3. ll A-1 thru 3.ll A-14 which define typical environmental conditions and associated environmental test profiles are defined in Figures 3.llA-6A thru 3.llA-10.
3.11.5 CHEMICAL SPRAY, RADIATIO", HUMIDITY, DUST, SUBMERGENCE, AND POWERSUPPLY VOLTAGE AND FREQUENCY VARIATION 3.11.5.1 Chemical Environment Engineered Safety Feature Systems are designed to perform their safety-related functions in the temperature, pressure, and humidity conditions described in Section 3.11.1 and Sections 6.2 and 6.3. In addition, components of ESF systems inside the containment are designed to perform their safety-related functions in the presence of the existing chemical environment, resulting from the boric acid and hydrazine solutions recirculated through the Safety Injection System (SIS) and Containment Spray Systems (CSS). The SIS is designed for both the maximum and long-term boric concentration and pH. These chemical environment conditions are given in Appendix 3.llA.
3.11.5.2 Radiati_on Environment The components in the Engineered Safety Feature and Reactor Protection Systems are designed to meet their performance requirements under the environmental and operating conditions in which they will be required to function and for the length of time for which their function is required. The components are designed to ensure acceptable performance under normal operational radiation exposure in addition to the single most adverse post accident environment. The normal operational exposures are based on the design source terms provided in 7 Section 11.1 and Section 12.2. Radiation environments for those components for which the most adverse accident conditions are post LOCA are based on the source term assumptions consistent with Regulatory Guides 1.4 and 1.7.
Radiation environments for those components for which the most adverse accident condition is other than the LOCA (such as the main steam line break, feedwater line break or CEA ejection) are based on conservative estimates of the fuel assembly gas gap activities and maximum Reactor Coolant specific activities as discussed in Section 11.1.
HUMIDITY Equipment not subjected to steam environments during DBE testing will be environmentally tested to short tenn high humidity levels prior to operation and performance requirements demonstrated during and after the test. Equipment that is subjected to steam environments will be subjected to the appropriate test profiles in Appendix 3.llA.
.DUS T_
Dust environments will be considered when establishing service conditions and qualification requirements. The potential effects of dust exposure will be evaluated relative to effects upon equipment safety function performance.
Amendment No. 7 March 31, 1982 3.11-5
Where dust could have a degrading effect on equipment safety function performance, it will be addressed in the qualification program through the
[7.s'g development of a maintenance program and/or an upgrading of equipment interface
\ / requirements.
S_UBMERGENCE_
Equipment locations and operability requirements will be reviewed to establish whether or not specific equipment could be subject to submergency during its required operating time. Flood levels both inside and outside containment will be reviewed and potential impacts on equipment qualification appropriately addressed. Where operability during submergency is required, qualification will be demonstrated by type test and/or analysis supported by partial type 7 test data.
Power Supply Voltage and frequency Variation Power supply voltage and frequency variation is addressed in several areas throughout the equipment design and verification process. During the design process interface requirements dictate the acceptable range of power supply variation. Equipment specifications incorporate these interface requirements into the design to ensure acceptable operation within the defined range of power supply voltage and frequency variation. Upon equipment fabrication and completion, design verification tests are performed to demonstrate design adequacy. I V
Amendment No. 7 March 31, 1982 p
b 3.11-6
REFERENCES
- 1. " Qualification of Combustion Engineering Class lE Instrumentation",
CEtiPD-255 Rev. 3, c.ombustion Engineering, Inc., Windsor, Connecticut. l7
- 2. Griess, J. C. and Bacarella, A. L., " Design Considerations of Reactor Containment Spray Solutions", CRNL-TM-2412, Part III, Oak Ridge National Laboratory, Oak Ridge, Tennessee, December, 1969.
- 3. Kircher, J. F. , and Bowman, R. E. , " Effects of Radiation on Materials and Components", Van Nostrand Reinhold, New York,1964.
i O
9 Amendment No. 7 March 31, 1982 3.11-7
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j 1 APPENDIX 3.11 A TYPICAL ENVIRONMENTAL CONDITIONS AND TEST PROFILES 4
1 l7 FOR a
STRUCTURES AND COMPNENTS
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TYPICAL ENVIRONMENTAL CONDITIONS AND TEST PROFILES l7 !
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STRUCTURES AND COMPONENTS 1
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1 l This appendix defines the generic environmental qualification requirements for !
CESSAR scope structures and components. The requirements are given in (
l t categories which combine various locations and conditions of design for P
environmental qualification purposes.
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APPENDIX 3.llA I l Table of Contents j
- Page Amendment Scope Statement 7 j i 7
- ii 7 j iii 7 l
Text I
l Page Amendment l l
, 3.llA-1 7 i 3.llA-2 7 i
Table Amendment i 3.11 A-1 through 3.ll . A-14 7 i
Figures }
Amendment l 3.11A-1A l l' 7 i
! 3.llA-1B 7 l 3.llA-2 7
!' 3.11A-3 7 r 3.llA-4 7 '
3.llA-5 7 3.11A-6A 7 l 3.11A-6B 7 i 3.11A-7 7 l
3.llA-8 7 3.11A-9 7 3.llA-10 7 l
l 1
Amendment No. 7 March 31,1982 i
1 i TABLE OF CONTENTS CHAPTER 3 i l r
- l I APPENDIX 3.11 A l l
l Section Sub.iect Pace No. l 3.11A.1 DEFINITION OF ENVIRONMENTAL CONDITIONS AND PROFILES 3.11A.1
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l Amendment No. 7 l
i March 31, 1982 i
LIST OF TABLES CH APTER 3 APPENDIX 3.11 A Table Subject 3.11A-1 Category "A-i" Environmental Conditions (LOCA: In-Containment) 3.11A-2 Category "A-2" Environmental Conditions (MSLB: I n-Containroent) 3.11A-3 Category "B" Environmental Conditions (Normal in-Containment) 3.11A-4 Category "C" Environmental Conditions 3.11A-5 Ca teaory "0" Environmental Conditions 3.11A-6 Cateoory "E" Environmental Conditions 3.11A-7 Category "F" Environmental Conditions 3.11A-8 Category "G" Environmental Conditions 7
3.11A 4 Category "H" Environmental Conditions 3.11A-10 Category "I" Environmental Conditions (Outside Plant Buildings) 3.11A-11 Category "J" Environmental Conditions 3.11A-12 Category "K" Environmental Conditions (Outside Plant Buildings) 3.11A-13 Cateaory "V-1" Environmental Conditions (Worst Case: In Containment) 3.11 A-14 Category "V-2" Environmental Conditions (Worst Case: Outside Containment)
Amendment No. 7 March 31, 1982 ii
i p LIST OF FIGURES
$ CHAPTER 3 l APPENDIX 3.11 A i
Figure Subject i
~
3.11A-1A Typical Containment Atmosphere Temperature Condition following t
(LOCA) i i 3.11A-1B Typical Containment Atmosphere Pressure Condition following (LOCA) r l 3.11A-2 Typical Annulus Atmosphere Temperature Condition following j (LOCA/MSLB) 3.11A-3 Typical Containment Atmosphere Temocrature Condition following (MSLB) 3.11A-4 Typical Containment Radiation Dose following (LOCA) 3.11A-5 Typical Containment Gamma Dose Rate following (LOCA) 3.11A-6A Typical Containment Building Environmental Test Profile for Category "A-1" "A-?" and "V-1" Environmental Conditions 3.11 A- 6B Typical Containment Building Environmental Test Profile for 7 Category "A-1" "A-2" and "V-1" Environmental Conditions 3.11A-7 Typical Environmental Test Profile for Category "C" Environmental Conditions 1
3.11A-8 Typical Inside Cabinet Envi'ronmental Test Profile for Category "C" Environmental Conditions 3.11A-9 Typical Environmental Test Profile for Category "H" and "J" Environmental Conditions 3.11A-10 Typical Inside Cabinet Environmental Test Profile for Categories "H" and "J" Environmental Conditions i
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Amendment No. 7 March 31, 1982 iii i
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- 3.11A-1 DEFINITION OF ENVIRONMENTAL CONDITIONS AND PROFILES 4
The purpose of this appendix is to define typical environmental conditions and associated environmental test profiles.
SUMMARY
i Figures 3.11A-1A through 3.11A-5 provide typical post accident environmental [
! conditions. These figures are not " test" profiles and therefore do not include l ma rgin.
! Tables 3.llA-1 through 3.11A-14 provide a series of tables titled " Category
- "XX"" Environmental Conditions". These tables were developed for the purpose
- of defining a limited set of clearly established environmental conditions I; that could be associated with specific equipment and/or locations. Appendix 3.11A utilizes and illustrates this approach by correlating a generic piece
]
of equipment with its corresponding environmental category designator, q These tables also do not define actual test conditions or parameters and therefore do not include margin.
Figure 3.11 A-6A and 3.11 A-68 are the in-containment test profiles that
- correspond to the post accident environmental conditions defined in Figures
- 3.11A-1 A through 3.11 A-5 and Tables 3.11 A-1, 3.11 A-2 and 3.11 A-13. Both i
Figure 3.11A-6A and 3.11A-6B incorporate and illustrate required margin.
For an explanation of the use of these nrofiles see Section 3.4.1 of CENPD 2
g 255, Rev. 03. 7 Figures 3.11A-7 through 3.11A-10 are test profiles for equipment located outside containment. These test profiles also do not incorporate margin.
. The test profiles included herein represent " typical" examples of qualifica-tion test profiles and are not intended to represent the complete set of all test profiles utilized.
EtWIRONMENTAL CONDITIONS
} A. Tables 3.llA-11 and 3.11A-2 list typical parameters for design basis i accident conditions inside containment (Environmental Categories i
"A-1" and "A-2").
B. Table 3.llA-3 lists typical parameters for normal environmental conditions inside containment (Environment Category "B").
j C. Tables 3.ll A-4, 3.11 A-ll and 3.11A-12 list typical parameters for normal
- environment conditions outside containment (Environment Categories "C",
"J" and "K").
D. Tables 3.11A-5 through 3.11A-10 list typical parameters for abnormal environment conditons outside containment (Environment Categories "D",
- "E", "F", "G", "H" and "I").
Amendment No.7 U March 31,1982 i
) 3.11A-1 1
_ . _ - _ _ _ . . _ _ _ . .- - - , .__ _ = . - , . . . _ . _,. - - --
E. Table 3.llA-13 lists typical " Worst Case" parameters for valves inside containment (Environment Category V-1).
F. Table 3.ll A-14 lists typical " Worst Case" parameters for valves outside containment (Environment Category V-2).
G. Figures 3.llA-1A through 3.llA-5 provide profiles for typical post accident environment conditions.
H. Figures 3.11 A-6A and 3.11 A-6B represent simulated environmental profiles for equipment located inside containment, as appropriate (Environment Categories "A-1", "A-2" and "V-1").
- 1. Figures 3.ll A-7 and 3.ll A-8 represent simulated environmental conditions for equipment located outside containment, as appropriate (Environment Category "C") .
J. Figures 3.ll A-9 and 3.ll A-10 will be used to simulate environment conditions for equipment located outside containment, as appropriate (Environment Categories "H" and "J").
O l
9 Amendment No. 7 3.llA-2 March 31, 1982
i I
i TABLE 3.11A-1 4
CATEGORY "A-1" ENVIRONMENTAL CONDITIONS (LOCA: IN-CONTAINMENT) 1 i ENVIRONMENTAL PARAMETERS RANGE AND DURATION l
TEMPERATURE, F FIGURE 3.llA-lA l
I PRESSURE, PSIG FIGURE 3.llA-1B HUMIDITY SUPERHEATED STEAM /
AIR MIXTURE 7
4 RADIATION, RADS FIGURES 3.llA-4 AND 3.llA-5 i CHEMICALS NOTE 'l' I
4 l
NOTE 1 - 4400 PPM BORON AS H B0 , 50-100 PPM HYDRAZINE AS N H AND PU4
' 3 3 24 TO 10.
l Amendment No. 7 l
- March 31, 1982 i i
- I l
TABLE 3.11p.g CATEGORY "A-2" ENVIRONMENTAL CONDITIONS (MSLB: IN-CONTAINMENT)
ENVIRONMENTAL PARAMETERS RANGE DURATION
, FIGURE 3.llA-3 0-12 MIN.
TEMPERATURE, F , _ _ _
l FIGURE 3.ll-1A(AFTER12 MIN.) _ _ _ .
PRESSURE, PSIG l FIGURE 3.llA-18 ,
_ _ _ . j
{
SH STEAM / AIR j MIXTURE 0-12 MIN. 7 HUMIDITY !
i SAT. STEAM / AIR MIXTURE (AFTER 12 MIN.)
RADIATION, RADS 4.5 X 104 y (TID)
CHEMICALS NOTE 'l' l
NOTE 1 - 4400 PPM BORON AS H B0 , 50-100 PPM HYDRAZINE AS N H AND [4 3 3 24 TO 10.
O Amendment No. 7 March 31, 1982
?
i TABLE 3.11A-3 l CATEGORY "B" ENVIRONMENTAL CONDITIONS (NORMAL: IN-CONTAINMENT)
ENVIRONMENTAL PARAMETERS RANGE DURATION S
TEMPERATURE, F 55 TO 122 CONTINU0US PRESSURE, PSIG 0-5 CONTINU0US HUMIDITY, % 20-90 CONTINU0US 7 RADIATION, RADS NOTE 'l' (TID) 4 I
i i i !
l CHEMICALS NOT APPLICABLE }
4 1 l
4 i
I a
NOTE 1 - DOSE VARIES WITH COMPONENT (SEE CESSAR-F, TABLE 3.118-2) 4 1
d
, Amendment No. 7 March 31, 1982
t TABLE 3.llA-4 CATEGORY "C" ENVIRONMENTAL CONDITIONS ENVIRONMENTAL PARAMETERS RANGE DURATION TEMPERATURE, F 55 T0 104 CONTINU0US PRESSURE, PSIG 0 CONTINU0US HUMIDITY, % 20-90 CONTINUOUS NOTE 'l' -
RADIATION, RADS (TID) NOTE '2' CHE'1ICALS i NOT APPLICABLE 7
NOTE 1 - AT OR AB0VE 80 F, THE M0ISTURE CONTENT IS THAT WHICH PRODUCES 90%
RELATIVE HUMIDITY AT 80 F (DEWPOINT OF 77 F).
NOTE 2 - DOSE VARIES WITH COMPONENT (SEE CESSAR-F, TABLE 3.118-2).
O Amendment No. 7 March 31, 1982
f')i TABLE 3.llA-5 CATEGORY "D" ENVIRONMENTAL CONDITIONS ENVIRONMENTAL RANGE OR PARAMETERS MAXIMUM DURATION
! 104-120 4 HR.
TEMPERATURE, F i
i
\
l - 104 TO 55 I ,
AFTER 4 HR.
PRESSURE, PSIG 0 ALL
'V / i DURATION
, HUMIDITY, % 20-90
, ! NOTE 'l' NOTE '2' RADIATION, RADS 6 4 X 10 Y (TID)
CHEMICALS NOT APPLICABLE NOTE 1 - AT OR ABOVE 80'F, THE MOISTURE CONTENT IS THAT WilICH PRODUCES 90%
RELATIVE HUMIDITY AT 80 F (DEWPOINT OF 77 F). AT OR AB0VE 120'F, THE MOISTURE CONTENT IS THAT WHICH PRODUCES 99% RELATIVE HUMIDITY AT 120 F (DEWPOINT OF 116 F).
NOTE 2 - LIMITED TO 8 HOURS OUTSIDE THE NORMAL RANGE OF CATEGORY "C" UNLESS OTHERWISE SPECIFIED.
(
' w ,.l Amendment No. 7 March 31, 1982
TABLE 3.llA-6 CATEGORY "E" ENVIRONMENTAL CONDITIONS ,
i ENVIRONMENTAL RANGE OR !
MAXIMUM DURATION PARAMETERS l
! '55 TO 330 0 - 3 MIN. (
l !
TEMPERATURE, F
,104-55 AFTER 3 MIN.
I l
3 0-3 MIN.
PRESSURE, PSIG ,
O AFTER 3 MIN.
I l 100 0-3 MIN.
HUMIDITY, %
! NOTE '2' AFTER 3 MIN.
l (NOTE 'l') l RADIATION, RADS <103 (TID)
! CHEMICALS NOT APPLICABLE
! l 1
NOTE 1 - LIMITED TO 8 HOURS OUTSIDE THE NORMAL RANGE OF CATEGORY "C" UNLESS j
OTHERWISE SPECIFIED.
NOTE 2 - AT OR AB0VE 80 F, THE MOISTURE CONTENT IS THAT WHICH PRODUCES 90%
RELATIVE HUMIDITY AT 80 F (DEWPOINT OF 77 F).
O Amendment No. 7 March 31, 1982
TABLE 3.11 A-7 CATEGORY "F" ENVIRONMENTAL CONDITIONS ENVIRONMENTAL PARAMETERS RANGE DURATION l
- TEMPERATURE, F FIGURE 3.llA-2 (NOTE '2')
i PRESSURE, PSIG 0 ALL DURATION i i I HUMIDITY j SAT. STEAM / AIR NOTE '2' ;
MIXTURE _ _;
l !
RADIATION, RADS ! NOTE 'l' !
! i NOT APPLICABLE 9; CHEMICALS 7 4
NOTE 1 - FORUNCONTROLLEDACQESSAREAS1X10 y (TID) AND FOR CONTROLLED ACCESS AREAS 4 X 10 y (TID).
NOTE 2 - LIMITED TO 8 HOURS OUTSIDE THE NORMAL RANGE OF CATEGORY "C" UNLESS OTHERWISE SPECIFIED.
O Amendment No. 7 March 31, 1982
TABLE 3.11A-8 CATEGORY "G" ENVIRONMENTAL CONDITIONS ENVIRONMENTAL PARAMETERS RANGE DURATION I
TEMPERATURE, F FIGURE 3.llA-2 (NOTE 'l') l PRESSURE, PSIG 0 ALL DURATION l
HUMIDITY l SAT. STEAM / AIR NOTE 'l'
y l
l i
e NOTE 1 - LIMITED TO 8 HOURS OUTSIDE THE NORMAL RANGE OF CATEGORY "C" UNLESS 4 OTHERWISE SPECIFIED. ,
i O
Amendment No. 7 March 31, 1982
l 4
TABLE 3.llA-9 i
i CATEGORY "H" ENVIRONMENTAL CONDITIONS '
i l ENVIRONMENTAL PARAMETERS RANGE DURATION 1
, TEMPERATURE, F 55 T0104 NOTE '2' l t - ;
i '
l j
PRESSURE, PSIG 0 ALL DURATION i,
i
- HUMIDITY, % l 20-90 l NOTE '2' NOTE 'l' 1 RADIATION, RADS !
<103 (TID) l I
l OCHEMICALS .
NOT APPLICABLE 7 NOTE 1 - AT OR AB0VE 80 F, THE MOISTURE CONTENT IS THAT WHICH PRODUCES 90%
RELATIVE HUMIDITY AT 80 F (DEWPOINT OF 77 F).
i NOTE 2 - LIMITED TO 8 HOURS OUTSIDE THE NORMAL RANGE OF CATEGORY "J" UNLESS i OTHERWISE SPECIFIED.
O Amendment No. 7 March 31, 1982
TABLE 3.llA-10 .'
CATEGORY "I" ENVIRONMENTAL CONDITIONS l
(0UTSIDE PLANT BUILDINGS) l ENVIRONMENTAL PARAMETERS RANGE DURATION 6 TEMPERATURE, F -30 TO 122 ; NOTE 'l' I !
i . . _ _ _ _ , . _ _ _ _ _ . _ . _ .
PRESSURE, PSIG ! O ALL DURATION ,
f
_ _ _ _ _ _ _ _ ._ .. _ _ 3 I '
HUMIDITY, % l 100 NOTE 'l'
. i RADIATION, RADS <103 (TID)
_ _ _ _ _ _ _ _ _ _ _ . .__ _ __. J CHEMICALS l NOT APPLICABLE l7 '
i I
i l
l l
l l
l l l NOTE 1 - LIMITED TO 8 HOURS OUTSIDE THE NORMAL RANGE OF CATEGORY "K" UNLESS OTHERWISE SPECIFIED. )
l
)
l Amendment No. 7 l March 31, 1982 l
l
(v) TABLE 3.llA-ll CATEGORY "J" ENVIRONMENTAL CONDITIONS ENVIRONMENTAL PARAMETERS RANGE DURATION TEMPERATURE, F 65 T0 85 CONTINU0US 7
PRESSURE, PSIG 0 CONTINU0US HUMIDITY, % 40-60 CONTINU0US l
. CHEMICALS NOT APPLICABLE ss -
i
{
Amendment No. 7 March 31, 1982
(}
O TABLE 3.llA-12 CATEGORY "X" ENVIRONMENTAL CONDITIONS (0UTSIDE PLANT BUILDINGS)
ENVIRONMENTAL PARAMETERS RANGE DURATION TEMPERATURE, F -30 TO 120 CONTINU0US PRESSURE, PSIG 0 CONTINU0US HUMIDITY, % 20-90 CONTINUOUS NOTE 'l' 7
CHEMICALS NOT APPLICABLE L
NOTE 1 - AT OR AB0VE 80 F, THE MOISTURE CONTENT IS THAT WHICH PRODUCES 90%
RELATIVE HUMIDITY AT 80 F (DEWPOINT OF 77 F). AT OR AB0VE 120 F, THE MOISTURE CONTENT IS THAT WHICH PRODUCES 90% RELATIVE HUMIDITY I
AT 120"F (DEWPOINT OF 116 F).
O 1 1
Amendment No. 7 March 31, 1982
! TABLE 3.ll A-13 CATEGORY "V-1" ENVIRONMENTAL CONDITIONS (WORST CASE: IN-CONTAINMENT): NOTE 3 ENVIRONMENTAL PARAMETERS RANGE DURATION NORMAL 60 - 122 CONTINU0US LOCA FIGURE 3.ll A-1 A
-, TEMPERATURE, F
? FIGURE 3.llA-3 0-12 MIN.
MSLB ,
FIGURE 3.llA-1A AFTER 12 MIN.
l NORMAL 0-5 ! CONTINU0US
. PRESSURE, PSIG LOCA FIGURE 3.ll A-1B MSLB FIGURE 3.llA-1B NORMAL NOTE 'l' 7 SAT. STEAM / AIR
. LOCA ALL DURATION t MIXTURE 1
i HUMIDITY, % SH. STEAM / AIR i MSLB MIXTURE 0-12 MIN.
j SAT. STEAM / AIR AFTER 12 MIN.
q MIXTURE i i RADIATION, RADS 1 X 108 (TID) i j CHEMICALS NOTE '2' l _ l i
NOTE 1 - 95% RELATIVE HUMIDITY (RH) AT 60 TO 80 F. FOR 80 F TO MAXIMUM i
TEMPERATURE FIXED M0ISTURE CONTENT IS EQUIVALENT TO 95% RH AT 80 F.
i N
i NOTE 2 - 4400 PPM BORON AS H3B03 ' 50-100 PPM HYDRAZINE AS N24 H AND P 4 TO 10.
j pg NOTE 3 - COMBINED " WORST CASE" CONDITION FOR NORMAL /LOCA/MSLB ENVIRONMENTS.
V Amendment No. 7 March 31, 1982 1
~ _ .-....- . - _.. ..- ..-._, __ . . _ , . _ _ _ . . _ _ _ _ _ _ _ . . _ . _ . . _ _ , . . _ . _ _ . _ _ _ . . . _ . _ _ _ . ~ . . - . - _ . . _
TABLE 3.11A-14 CATEGORY "V-2" ENVIRONMENTAL CONDITIONS (WORST CASE: OUTSIDE CONTAINMENT): NOTE 2 ENVIRONMENTAL PARAMETERS RANGE DURATION NORMAL 60-104 CONTINUOUS LOCA FIGURE 3.llA-2 TEMPERATURE, F 60-330 0-3 MIN.
MSLB FIGURE 3.llA-2 AFTER 3 MIN.
NORMAL 0 CONTINUOUS PRESSURE, PSIG LOCA 0 ALL DURATION 3 0-3 MIN. 7 MSLB 0 AFTER 3 MIN.
NORMAL NOTE 'l' HUMIDITY, % SAT. STEAM / AIR LOCA l MIXTURE j ALL DURATION j
SAT. STEAM / AIR MSLB ; MIXTURE ALL DURATION RADIATION, RADS 5 X 107 (TID)
CHEMICALS NOT APPLICABLE NOTE 1 - 95% RELATIVE HUMIDITY (RH) AT 60 TO 80 F. FOR 80 F TO MAXIMUM TEMPERATURE FIXED MOISTURE CONTENT IS EQUIVALENT TO 95% RH AT 80'F.
NOTE 2 - COMBINED " WORST CASE" CONDITION FOR NORMAL /LOCA/MSLB ENVIRONMENTS.
%nendment No. 7 March 31, 1982
O O O ho 0
500 i i i i
-4 I
s f 400 -
8 0!
Og y' 300 -
1 _
dE D Om H 2 -1 2 <
m m ON 200 - -
oh W RAMP TEMPERATURE FROM INITIAL
@5@ AMBIENT CONDITION (120 F) TO PEAK 2I TEMPERATURE (350 F) OVER 10 SECONDS O@ 100 - _
{m o -i
- Y 0
100 10 1 10 2 10 3 10 4 105 10 6 M
C y TIME, MINUTES wN a2 we y W3
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> 50 -
r-8 0z 0 o -t
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r->i cc r- E c.
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EI RAMP PRESSURE FROM INITIAL AMBIENT ag 20 -
CONDITION (O PSIG) TO PEAK PRESSURE 8m (60 PSIG) OVER 10 SECONDS o
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a y RAMP TEMPERATURE FROM INITIAL AMBIENT
/ 2
$ CONDITION (120'F) TO PEAK TEMPER ATURE (370*F) OVER 10 SECONDS 200 - -
150 -
100 I ' ' ' '
0 2 4 6 8 10 12 TIME, MINUTES Amendment No. 7 March 31, 1982 O ~
I
/ TYPICAL CONTAINMENT ATMOSPHERE TEMPERATURE 9"*
[Qg / / CONDITION FOLLOWING MSLB 3.11 A 3
I m
- O
/ \ air i s i i s itsi i i i s lu i i e i i s i i i - c-li s s i i O l 8
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11i t i f i 1 11i f I f f i 11i f I f f f ItI. i 1 l C
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co o e O O O SOVU'3SOG Amendment No. 7 March 31, 1982 C_E f , Figure
/ TYPICAL CONTAINMENT R ADIATION DOSE FOLLOWING LOCA 3.11 A-4
e J'8 I8 3 3 1 I 6 I i l 3 l l _h l6ii l lli s l _
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\") C-E
/ TYPICAL CONTAINMENT GAMMA DOSE RATE Figure p / FOLLOWING LOCA 3.11 A 5
'N N.
Cs bn ,
k,m 800 ADDITIONAL PEAK
' ' I 3 3 3 e 1
' ' DESIGN BASIS EVENT TRANSIENT > ,
TRANSIENT 4 TEST TIME LIMITED BY-*4 TEST TIME LIMITED BY SAFETY-RELATED >
700 SAFETY-R ELATED '
55PSIG 66 PSIG I r3 FUNCTION I I
l
\
\
REQUIREMENT r--------------------'s I
160 PSIG PRESSUR E s l
j j 600 \ SUPERHEATED N -
60 60
[ PSIG g STEAM / AIR \\
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\
\ -
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hb ul
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$ \ STEAM / AIR SATURATED 5 C
l l
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\ r-s h' -
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\ -m l 5 s \
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0 N \ 370*F 350'F \ 315'F TEMPER ATU RE 5
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TEMP.d \
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\ XTEMP. STABILIZE AT NORMAL O' z -
STABILIZE AT \ ENVIRONMENT HP5 100 _ NORMAL \ - 10 09o ENVIRONMENT '\ INITI ATE CHEMICAL SPRAY 0
/\ PRESSURE N"
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- S g f5, -- -- - TEST LEVEL j h'
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f- 75 PSIG SATURATION PRESSURE FOR 305 F
/ 7'i PSIG / STEAM / AIR MIXTURE A
l
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\ 60 PSIG Or \ p-PRESSURE "g
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--- TEST LEVEL
- 10 1r qf ENVIRONMENT 4 INITIATE CHEMICAL SPRAY m > I I I I f m 3 I I d H ; io 2 10 102' 10 102 103 104 TIME, MINUTES TIME, MINUTES Sh w
_, n S8
.n W2 dn 8 $P w %
O O O E5t3 Eo 58;
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~
RH < 90%
~
l (NO HUMIDITY CONTROL) 150 NOTE 4 NOTES:
RH = 90% l
- 1. T3 = TIME TO STABILIZE TEST TEMPERATURE -
- lT 3 EXTERNAL TO TEST ITEM l
135 F l 2. NO CONDENSATION SHALL FORM ON THE QH y$ 130 -
T1 I l 8 HOURS TEST ITEM DURING ANY PHASE OF THE 3 TESTING -
h F 120'F / 3. TEST TEMPERATURE EXTREME INCLUDES m -
15 F MARGIN -
I2 "
- 4. RH CORRESPONDS TO A DEWPOINT OF 116 F q$ g 110 -
m' 5 3 zz y _
se m m e
w 2
g 90 -
O,?
n "
~
~
rF AMBIENT 75 F AMBIENT NH 70 __
88 gm -
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zo cn I T3 40'F _
8 HOURS 5N ng 30 ya DURATION cam
~
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>% 8?
4* ~
y
Q f O L}J G(h om bn I rn 170 l I l NOTE 4 RH < 90%
I I S, l, RH = 90y, I ! (NO HUMIDITY CONTROL) ~
153'F 150 I g _.
g 8 HOURS NOTES: _
.< I
- 1. T3= TIME TO STABILIZE TEST n2 ~ i I TEMPERATURE EXTERNAL TO '
O$ l I TEST ITEM O I
- - 130 -
1 2. NO CONDENSATION SHALL FORM _
w$ Tg I ON THE TEST ITEM DURING ANY gg 120'F PHASE OF THE TESTING ~
Oo 8 HOURS 3. TEST TEMPERATURE EXTREME
<g ,u. 1jo _ INCLUDES 15 F MARGIN _
dE g 4. RH CORRESPONDS TO A DEWPOINT yQ g _ OF 11G F _
Ez ti 5< c: 90 -
y O5 2o g hk
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- 1. T3 = TIME TO STABILIZE TEST
- 1 I TEMPERATURE EXTERNAL TO i
NOTE 4 _
I l TESTITEM gj 130 -
l RH = 90% l T3 I 2. NO CONDENSATION SHALL FORM -
-t 2 I i I ON THE TEST ITEM DURING ANY 110 F gQ _
l I l PHASE OF THE TESTING _
go[ o' ,
l 8 HOURS 3. TEST TEMPERATURE EXTREME
$ ;- 2 ul 110 - l l INCLUDES 15 F MARGIN _
o *6 5 l I 4. RH CORRESPONDS TO A DEWPOINT 2o m g _
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3 I rom 4 H 80'F I yQ g 8 HOURS 9$ 70 - AMBIENT -
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- 1 137 F i TEMPERATURE EXTERNAL TO -
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--i 2 130 _
l 2. NO CONDENSATION SHALL FORM -
3 ; RH = 90% I ON THE TEST ITEM DURING ANY E @ [f> '
l l PHASE OF THE TESTING -
5F 2 o I 3. TEST TEMPERATURE EXTREME
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INCLUDES 15 F MARGIN -
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% 50 - -
ir-T' 3
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@ 3" 8 HOURS S1 30 co w2 DURATION N[ .~ 5 55
~
I i i t j EFFECTIVE PAGE LISTING j l
CHAPTER 3 i
! APPENDIX 3.llB l Table of Contents j Page Amendment l !
i i
- 11 l
- i. !
i i
Text I
j Page Amendment j f 3.11B-1 I
t l
i
- Tables Amendment l
3.11B-1 (Sheets 1-7) 7 j 3.-11B-2 (Sheets 1-12) f l
I x --
l l i 1
l
! ' l t
t I $
t I
i 4
i
!O i
j ~ Amendment No. 7
.' March 31,1982 I
- - _ . _ _ _ _ - - . _ _ _ _ _ . . ~ . _ _ _
6e O O O TABLE 3.118-1 g7 (Sheet 1 'or 7 ) I
~
MECHANICAL'EQUIFMENT QUALIFICATION REQUIREMENTS SPECIFIED ENVIRON-REQUIRED DURATION OF MENTAL CONDITIONS OPERATION FOR + LOCATION DESIGN BASIS ACCIDENT (SEE App. 3.11 A DISCUSSED IN SYSTEM LOCA MSLB FOR LEGEND) EQUIPMENT AND COMP 0NENTS REMARKS FSAR SECTION I. Chemical Passive Passive C CH-110P, CH-1100 Letdown 9.3.4
+ Volume Cor. trol Valves Control System Passive Passive C CH-20lP,.CH-201Q Letdown 9.3.4 Backpressure Valves
! Continuous Continuous A-1 CH-203, CH-205 9.3.4 A-2, B Auxiliary Spray Valves Passive Passive C CH-204 PRM Flow Control Valve 9.3.4 Passive Passive C CH-20lY Boric Acid Control 9.3.4 Valve Passive Passive C CH-231P Seal Injection Iso- 9.3.4 7 lation Valve Continuous Continuous A-1 CH-240 Charging Line Back- 9.3.4 A-2, B pressure Valve Passive Passive B CH-241, CH-242, CH-243, CH-244 9.3.4 Seal Injection Flow Control Valves Continuous Continuous C CH-255 Seal Injection Con- C, F, G required if valve 9.3.4 taintnent Isolation Valve is in annulus building Passive Passive C CH-500 VCT Inlet Diversion _ 9.3.4 Valve Amendment No. 7 March 31, 1982 l
.. - . . - - . - _ . - - - _ - - _ _ -._-__a
l 4
}
i I
TABLE 3.11B-1 i
(Sheet 2 of 7 ) fI MECHANICAL EQUIPMENT QUALIFICATION REQUIREEfiTS ,
SPECIFIED ENVIRON-REQUIRED DUMTION OF MENTAL CONDITIONS
~-~ OPERATION FOR~
~ -
+ LOCATICN CESI& FEASTS AtCIDPiT (SEE App. 3.11 A DISCUSSED IN '
SYSTEM LOCA MSLB FOR LEGEND) EQUIP"ENT AND COMFCNENTS REMARKS FSAR SECTION I. Chemical Passive Passive C CH-501 VCT Discharge Isolation 9.3.4 ,
+ Volu e Valve I Control ,
Systen Continuous Continuous C CH-505 RCP Controlled Bleedoff C, F, G required if valve 4.3.4 I (cont'd) Contairment Isolation Valve is in annulus building Centinuous Continuous A-1 CH-506, RCP Centrolled 9.3.4 l A-2, B Bleedoff Containrent Isolation t Valve l
Continuous Continuous B CH-507 RCP Centrolled Bleedoff 9.3.4 I Header Isolation Passive Passive C CH-510 RWT Recirculation Valve 9.3.4 Passive Passive C CH-512 VCT Makeup Supply Iso- 9.3.4 lation Valve 7 Passive Passive C CH-514 Eoric Acid Makeup Bypass 9.3.4 ,
to Charging Purp Valve ;
Continuous Continuous A-1, CH-515, CH-516, Letdown Isolation 9.3.4 A-2, B Valves t
Passive Passive C CH-250 Purification and Deborating 9.3.4 ;
IX Bypass Valve Passive Pac C CH-521 PRM and Boronoreter Bypass 9.3.4 Valve i Amendmont fio. 7l Marcn 31, 19 U i L
O __
O _ _ __ _ _ _ _ _ _ _ _ _
O
TABLE 3.11B-1 (Sheet 3 of 7 ) l7 MECHANICAL EQUIPMENT QUALIFICATION REQUIREMENTS SPECIFIED ENVIRON-REQUIRED DURATION OF MENTAL CONDITIONS OPERATION FOR + LOCATION DESIGN BASIS ACCIDENT (SEE App. 3.llA DISCUSSED IN LOCA FOR LEGEND) EQUIPMENT AND COMPONENTS REMARKS FSAR SECTION SYSTEM _ MSLB
- 1. Chemical Continuous Continuous C CH-523 Letdown Isolation Valve C, F, G required if valve 9.3.4
+ Volume is in annulus building Control System Continuous Continuous C CH-524 Charging Line Isolation C, F, G required if valve 9.3.4
,. (Cont'd) Valve is in annulus building a
l Passive Passive C CH-526 Letdown Control Bypass 9.3.4 i Valve I
Passive Passive C CH-527 Load Follow Supply Valve 9.3.4 Continuous Continuous C, D CH-530 CH-531 RWT Suction to C, F, G required if valve 9.3.4 ESFP's Isolation Valve is in annulus building Passive Passive CH-532 RWT Suction to RDP's 9.3.4
( C Isolation Valve 7
Continuous Continuous A-1. CH-560 RDT Suction Containment 9.3.4 A-2, 8 Isolation Valve Continuous Continuous C CH-561 RDT Suction Containment C, F, G required if valve 9.3.4 Isolation Valve is in annulus building l
Passive Passive C CH-562 Pecycle Drain Header 9.3.4 Isolation Valve Passive Passive C CH-563 EDT Discharge Isolation 9.3.4 Valve Pass ve Passive C CH-564 EDT Vent Isolation Valve 9.3.4 Amend *ent No. 7 March 31,19f2
1 l
)
i l
TABLE 3.118-1 '
(Sket4of[) f7
.i i MECHANIC *L EQUIPMENT QUALIFICATION REQUIREPENTS !
l l' SPECIFIED ENVIR0'4-j REQUIRED DURATION OF PENTAL CONDITIO*45 OPERATION FOR + LOCATIO'd DESIGN BASIS ACCIDENT (SEE App. 3.!1A DISCUSSED IN SYSTEM ~ TifCA~ MS'LB~~ FOR LEGEND) _ EQUIPMENT AND COMPONENTS REMARKS FSAR SECTION l
I. Chemical Passive Passive C CH-565 Pre-Holdup IX Bypass Valve 9.3.4
. + Volume !
t i
Control Passive Passive C CH-566 Gas Stripper Diversion Valve 9.3.4 !
! System I j (Cont'd) Passive Passive C CH-567 Diversion to HT from VCT 9.3.4 L Inlet Valve l Continuous Contiruous C CH-SSO RMWS to RDT Isolation Valve C F, G required if valve 9.3.4 is in annulus building i Passive Passive 7
! C CH-686 Holdup Pump Bypass to 9.3.4 i j Reactor Drain Filter Isolation Valve 1
l Continuous Continuous C Charging Pumps, 1, 2, 3 C, F, G required if pumps are 9.3.4 k in annulus building l
P3ssive Passive C CH-536 RWT Gravity Feed to Charging 9.3.4 l
I Pump Isolation Valve 1
j II. Safety Continuous Continuous C, D HPSI Isolation Valves SI-616, 626, See Footnote (1) 6.3.3 Injection 636, 646
)
i i System j Continuous Continuous C, D HPSI Isolation Valves SI-617, 627, See Footnote (1) 6.3.3
] 637, 647
] Continuous Continuous C, D LPSI Isolation Valves SI-615, 625, See Footnote (1) 6.3.3 635, 645 l
j; Continuous Continuous A-1, A-2, B SIT Isolation Valves51-614, 624, 6.3.3 l 634, 644 1 Amendment No. 7 l March 31, 1982 l 3
I e G 9
I e e e TABLE 3.118-1 (Sheet 5 of 7 ) l MECHANICAL EQUIPMENT QUALIFICATION REQUIREMENTS SPECIFIED ENVIRON- ,
REQUIRED DURATION OF MENTAL CONDITIONS :
OPERATION FOR + LOCATION DESIGN BASIS ACCIDENT (SEE App. 3.llA DISCUSSED IN t SYSTEM LOCA MSLB FOR LEGEND) EQUIPMENT AND COMPONENTS REMARKS FSAR SECTION I I
II. Sa fety Continuous Continuous A-1, A-2, 8 SIT Vent Valves, SI-605, 606, 6.3.3 Injection 607, 608, 613, 623, 633, 643 System (Cont'd) Continuous Continuous A-1, A-2, 8 SIT Sample Valves SI-611, 621, 6.3.3 631, 641 Continuous Continuous A-1, A-2, B SIT Return Line Isolation Valve 6.3.3 SI-682 Continuous Continuous A-1, A-2, B Check Valve Leakoff Isolation 6.3.3 Valves SI-618, 628, 638, 648, SI-322, 332 Continuous Not Required A-1, B Containment Sump Suction Valves 6.3.3 SI-673, 675 Continuous Not Required C, D Containment Sump Suction Valves See Footnote (1) 6.3.3 SI-674, 676 Continuous Continuous C, D HPSI Min. Flow Isolation Valves See Footnote (1) 6.3.3 SI-666, 661 Continuous Continuous A-1, A-2, B SDC Suction Valves SI-651, 652 6.3.3 653, 654 '
Continuous Continuous C, D SDC Suction Valves SI-655, 656 See Footnote (1) 6.3.3 Continuous Continuous CD SDC Warmup Valves SI-690, 691 See Footnote (1) 6.3.3 i
Amendment No. 7 March 31, 1982 I
l l
l L_ __ _ __ _ _ . _ _ _ _ _ _ _ _ _ _ _ ._-.-.-.___ ...____ _.._ _ _ a
l
)
l i
TABLE 3.11B-1 I
l (Sheet 6 of 7 )
f MECHANICAL EQUIPMENT QUALIFICATION REQUIREMENTS l
1 i
SPECIFIED ENVIRON-I REQUIRED DURATION OF MENTAL CONDITIONS
! OPERATION FOR + LOCATION l DESIGN BASIS ACCIDENT (SEE App. 3.llA DISCUSSED IN l SYSTEM LOCA MSLB FORLEGEND)_ _ EQUIPMENT AND COMPONENTS REMARKS FSAR SECTION 1 II. Safety Continuous Continuous C, D SDCHX Cross Connect Isolation See Footnote (1) 6.3.3 l Injection Valves SI-685, 686, 694, 696
! System l (Cont'd) Continuous Continuous C, D LPSI Purp Inlet Valves SI-683, See Footnote (1) 6.3.3
{ 692 l
' Continuous Not Required C, D Hot Leg Injection Isolation Valves See Footnote (1) 6.3.3 51-321, 331, 604, 609 Continuous Continuous C, D LPSI Punp Min. Flow Line Isolation See Footnote (1) 6.3.3
! Valves SI-669, 668 Continuous Continuous C, D Miniflow Line Isolation Valves See Footnote (1) 6.3.3 ,
to RWT SI-659, 660 '
Conti nuous Not Required C, D HPSI Orifice Bypass Valves SI-698, See Footnote (1) 6.3.3 7 699 Continuous Continuous C, D HPSI Pumps 1 and 2 See Footnnte (1) 6.3.3 '
i l Continuous Continuous C, D LPSI Pumps 1 and 2 See Footnote (1) 6.3.3
! Continuous Continuous C, D Shutdown Cooling Heat Exchangers See Footnote (1) 6.3.3 1 and 2 1
i Continuous Continuous C, D SCS Bypass Flow Control SI-306,307 See Footnote (1) 6.3.3 Continuous Continuous C, D SDCHX Discharge Throttle SI-657,658 See Footnote (1) 6.3.3 l 7 Not Required Not Required B RDT Isola tion SI-661 i Amendment Nn. 7 '
March 31, 1982 i
)
! 9 -_
9 9
t O O O TABLE 3.118-1 (Sheet 7 of 7 ) t MECHANICAL EQUIPMENT QUALIFICATION REQUIREMENTS l l
SPECIFIED ENVIRON-REQUIRED DURATION OF MENTAL CONDITIONS OPERATION FOR + LOCATION DTSVKliXY15"AttlbtNT (SEE App. 3.llA DISCUSSED IN SYSTEM LOCA MSLB FOR LEGEND) EQUIPMENT AND COMPONENTS REMARKS FSAR SECTION f i
II. Safety Continuous Continuous C, D CSP Mini Flow Isolation SI-664,665 See Footnote (1) 6.3.3 l Injection !
System Continuous Continuous C, D CSS Isolation SI-671, 672 See Footnote (1) 6.3.3 I (Cont'd)
Continuous Continuous CD CSP Flow Control SI-678, 679 See Footnote (1) 6.3.3 Continuous Continuous C, D CSP Discharge Isolation SI-684,689 See Footnote (1) 6.3.3 Continuous Continuous C, D SDCHX Discharge Isolation to CS See Footnote (1) 6.3.3 Header SI-687, 695 7
Continuous Continuous C, D SDCHX Spray Bypass SI-688, 693 See Footnote (1) 6.3.3.
Not Required Not Required B SIT N., Supply Isolation SI-612, 619 622, 529, 632, 639, 642, 649 l t III. Reactor Intermittent Intermittent B Pressurizer Spray Control Valves 5.5.13 l Coolant RC-100E, 100F System l j i
I l IV. Main Steam Continuous Continuous CE Main Steam Isolation Valves SG-170, i j and Feed- 171, 180, 181
, water Sys- l l tem Continuous Continuous C, E MSIV Bypass Valve, SG-183
{ Continuous Continuous CE Feedwater Isolation Valves SG-130,
! 132, 135, 137, 172, 174, 175, 177 i
Continuous Continuous C, E Atmospheric Dump Valves SG-178,179, 184, 185 67 Footnote (1): Applicable to cylindrical shaped containments only. If spherical containment is used, See Applicant's SAR.
Amendment No. 7 March 31, 1982
O THIS PAGE INTENT 1014 ALLY BLAtlK.
O
i l' EFFECTIVE PAGE LISTIf1G
, CHAPTER 3 j APPEr1 DIX 3A l i (
- Table of Contents (
Page Amendment r
i !
l 11 [
, iii 1
! 1931 l Page Amendment
3A-6 i
! 3A-7 '
' 3A-11 i l l l
Tables '
I l Amendment i
1 3A-1 I i'
3A-2 3A-3(a) 3A-3(b) l Figures Amendment 3A-1 3A-2 3A-3 3A-4 3A-5 3A-6 3A-7 9 3A-8 Amendment flo. 7 March 31,1982
l 3
(Sheet 1 of 7) i j EFFECTIVE PAGE LISTING CHAPTER 4 O
I i Table of Contents i
- Page Amendment
! i ii iii 7
, iV l v 3 i vi 3
! vii 3 viii ix x
xi xii 3 xiii 3 xiv 3 xv 3 xvi xvii 3 xviii 3 xix Text
! Page Amendment i
(
j 4.1-1 l l 4.1-2 l 4.2-1 4.2-2 4.2-3 4.2-4 7 i 4.2-4a 7 i 4.2-5 7 t 4.2-6 l 4.2-7 l 4.2-8 J 4.2-9 i 4.2-10 !
4.2-11 4.2-12 .
4.2-13 '
4.2-14 ,
4.2-15 7 i 4.2-16 7 4.2-17 4.2-18 9 4.2-19 4.2-20 '
Amendment No. 7 !
March 31,1982 l
l (Sheet 2 of 7)
EFFECTIVE PAGE LISTING (Cont'd)
CHAPTER 4 Text (Cont'd)
Page Amendment 4.2-21 4.2-22 4.2-23 4.2-24 )
4.2-25 l
, 4.2-26 7 l 4.2-27 7 !
4.2-28 4.2-29 ,
4.2-30 i 7 4.2-31 7 4.2-32 7 4.2-33 l 4.2-34 7 4.2-35 4.2-36 7 4.2-37 4.2-37a 7 4.2-38 4.2-39 4.2-40 4.2-41 4.2-42 4.2-43 1 4.2-44 i 4.2-45 l 4.2-46 4.2-47 4.2-48 4.2-49 4.2-50 l 4.2-51 l 4.2-52 4.2-53 1 4.2-54 l 4.2-55 )
4.2-56 i
, 4.2-57 )
4.2-58 4.2-59 4.2-60 4.2-61 4.2-62 4.2-63 ,
4.2-64 i 4.2-65 7 l 4.2-66 5 i
Amendment No. 7 March 31,1982 i
i l l i (Sheet 3 of 7) i I L
EFFECTIVE PAGE LISTING (Cont'd) l CHAPTER 4 Text (Con t' d) !
. Page Amendment i 1
} 4.2-67
} 4.2-68 !
) 4.2-69 i 4.2-70 7
! 4.2-71 j 4.3-1 3 i
! 4.3-2 3 l 1 4.3-3 3 i 4.3-4 3 l 4.3-5 3 4.3-6 3 !
4.3-7 3 I i 4.3-8 3 I I
4.3-9 3 l 4.3-10 3 1 4.3-11 3
! 4.3-12 3 -
! 4.3-13 3 l 3 i 94.3-14 4.3-15 4.3-16 3
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G4.4-3 4.4-4 4.4-5 4.4-6 4.4-7 l Amendrrent No. 7 March 31,1982
1 (Sheet 4 of 7)
EFFECTIVE PAGE LISTli;G. (Cont'd)
CHAPTER 4 ,
Text (Cont'd) s Page Amendment 4.4-8 5 4.4-9 4.4-10 4.4-11 6 4.4-12 4.4-13 4.4-14 4 a 1C 4.4-16 4.4-17 4.4-18 4.4-19 4.4-20 4.4-21 4.4-22 4.4-23 5 4.4-24 4.4-25 4.4-26 5 4.4-27 4.4-28 4.4-29 4.4-30 4.4-31 4.4-32 4.5-1 4.5-2 4.5-3 4.E-4 4.5-5 4.5-6 4.5-7 4.5-8 4.5-9 4.5-10 4.6-1 4.6-2 Tables Amendment 7
4.2-1 (Sheets 1-4) 4.2-2 4.2-3 4.3-1 (Sheets 1 and 2) 3 4.3-2 3 Amendment tio. 7 March 31,1982
(Sheet 5 of 7) l 1
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CHAPTER 4 I
! Tables (Cont'd) l Amendment 4.3-3 3 4.3-4 3 l
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Ag_endment 4.3-3 3 l 4.3-4 3 4.3-5 3 4.3-6 3 l 4.3-7 3 4.3-8 3 4.3-9 3 l
4.3-10 3 4.3-11 3 l 4.3-12 3 4.3-13 3 4.3-14 3 l 4.3-15 3 4.3-16 3 l 4.3-17 3 4.3-18 3 4.3-19 3 4.3-20 3 4.3-21 3 4.3-22 3 4.3-23 3 4.3-24 3 4.3-25 3 4.3-26 3 4.3-27 3 4.3-28 3 4.3-29 3 4.3-30 3 4.3-31 3 4.3-32 3 4.3-33 3 4.3-34 3 4.3-35 3 4.3-36 3 4.3-37 3 4.3-38 3 4.3-39 3 4.3-40 3 4.3-41 3 4.3-42 3 4.3-43 3 4.3-44 3 4.3-45 3 4.3-46 3 4.3-47 3 4.3-48 3 4.3-49 3 Amendment tio. 7 March 31,1982
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CHAPTER 4 ,
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lO Amendment No. 7 j March 31, 1982 l
TABLE OF CONTENTS (Cont'd.)
CHAPTER 4 l
Os Subject Section Page No.
4.2.3 DESIGN EVALUATION 4.2-36 4.2.3.1 Fuel Assembly 4.2-36 4.2.3.1.1 Vibration Analyses 4.2-36 4.2.3.1.2 CEA Guide Tube 4.2-36 4.2.3.1.2.1 Operating Basis Earthquake (0BE) 4.2-37 4.2.3.1.2.2 Safe Shutdown Earthquake (SSE) 4.2-37 4.2.3.1.2.3 Loss-of-Coolant Accident (LOCA) 4.2-37 J
4.2.3.1.2.4 Combined SSE and LOCA 4.2-37 7 4.2.3.1.3 Spacer Grid Evaluation 4.2-38 4.2.3.1.4 Dimensional Stability of Zircaloy 4.2-39 4.2.3.1.5 Fuel Handling ard Shipping Design Loads 4.2-39 4.2.3.2 Fuel Rod Design Evaluation 4.2-40 i
4.2.3.2.1 Results of Vibration Analyses 4.2-40 4.2.3.2.2 Fuel Rod Internal Pressure and Stress 4.2-41 Analysis
[N/ T 4.2.3.2.3 Potential for Ctemical Reaction 4.2-41 s 4.2.3.2.4 Fretting Corrosion 4.2-43 4.2.3.2.5 Fuel Rod Bowing 4.2-43 4.2.3.2.6 Irradiation Stability of Fuel Rod Cladding 4.2-43 4.2.3.2.7 Cladding Collapse Analysis 4.2-44 4.2.3.2.8 Fuel Dimensional Stability 4.2-44 4.2.3.2.9 Potential for Waterlogging Rupture and 4.2-46 Chemical Interaction 4.2.3.2.10 Fuel Burnup Experience 4.2-46 4.2.3.2.11 Temperature Transient Effects Analysis 4.2-52
- 4.2.3.2.11.1 Waterlogged Fuel 4.2-52 4.2.3.2.11.2 Intack Fuel 4.2-53 4.2.3.2.12 Energy Release During Fuel Element Burnout 4.2-53 1 4.2.3.2.13 Energy Release on Rupture of Waterlogged 4.2-53 Fuel Elements 4.2.3.2.14 Fuel Rod Behavior Effects from Coolant 4.2-53 Flow Blockage 4.2.3.2.15 Fuel Temneratures 4.2-54 4.2.3.3 Burnable Poison Rod 4.2-55 4.2.3.3.1 Burnable Poison Rod Internal Pressure and 4.2-55 Cladding Stress 4.2.3.3.2 Potential for Chemical Reaction 4.2-55
... Amendment No. 7 III March 31, 1982
TABLE OF CONTENTS (Cont'd. )
CHAPTER 4 Section Subject Page No.
4.2.3.4 Control Element Assembly 4.2-55 4.2.4 TESTING AND INSPECTION PLAN 4.2-57 4.2.4.1 Fuel Assembly 4.2-57 4.2.4.1.1 Weld Quality Assurance Measures 4.2-58 4.2.4.1.2 Other Quality Assurance Measures 4.2-59 4.2.4.2 Fuel Rod 4.2-59 4.2.4.2.1 Fuel Pellets 4.2-59 4.2.4.2.2 Cladding 4.2-60 4.2.4.2.3 Fuel Rod Assembly 4.2-60 4.2.4.2.3.1 Stack Length Gage 4.2-61 4.2.4.2.3.2 Fluoroscopy 4.2-61 4.2.4.3 Burnable Poison Rod 4.2-62 4.2.4.3.1 Burnable Poison Pellets 4.2-62 4.2.4.3.2 Cladding 4.2-62 4.2.4.4 Control Element Assemblies 4.2-62 4.2.5 REACTOR INTERFACE REQUIREMENTS 4.2-63 4.3 NUCLEAR DESIGN 4.3-1 4.3.1 DESIGN BASES 4.3-1 4.3.1.1 Excess Reactivity and Fuel Burnup 4.3-1
- 4. 3.1. 2 Core Design Lifetime and Fuel Replacement 4.3-1 Program
- 4. 3.1. 3 Negative Reactivity Feedback 4.3-1 4.3.1.4 Reactivity Coefficients 4.3-1
- 4. 3.1. 5 Burnable Poison Requirements 4.3-1
- 4. 3.1. 6 Stability Criteria 4.3-1
- 4. 3.1. 7 Maximum Controlled Reactivity Insertion Rate 4.3-2 O
iv
s D. Faulted Conditions t
Condition IV incidents are postulated events whose consequences are such that integrity and operability of the nuclear energy system may be impaired.
Mechanical fuel failures are permitted, but they must not impair the operation of the engineered safety features (ESF) systems to mitigate the consequences of the postulated event. Condition IV incidents are listed below:
- 2. Loss-of-coolant accident (LOCA)
- 4. Locked coolant pump rotor
- 5. Major secondary system pipe rupture
! 6. CEA ejection
- 7. Major fuel handling accident (fuel assembly and grapple are disengaged) 4.2.1. .1 Fuel Assembly Structural Integrity Criteria For each of the design conditions, there are criteria which apply to the fuel assembly and components with the exception of fuel rods. These criteria O are listed below and give the allowable stresses and functional requirements for each design condition. Criteria for fuel rods are discussed separately in Section 4.2.1.2.
A. Design Conditions I and II P, 5 S, P, + Pb 5Fb sm Under cyclic loading conditions, stresses must be such that the cumulative fatigue damage factor does not exceed 0.8. Cumulative damage factor is defined as the sum of the ratios of the number of cycles at a given cyclic stress (or strain) condition to the maximum number permitted for that condi-tion. The selected limit of 0.8 is used iq place of 1.0 (which would correspond j to the absolute maximum damage factor permitted) to provide additional margin in the design.
- Deflections must be such that the allowable trip time of the control element assemblies is not exceeded.
- B. Design Condition III P, $ 1.5 S, P, + Pb $ 1.5 F3 5, f
4.2-3
Deflections are limited to a value allowing the CEAs to trip, but not neces-sarily within the prescribed time.
C. Design Condition IV P
mi Sb P
m
+P b 5 Fbsm whereSy=smallervalueof2.4Sm or 0.7 Su '
- l. If the equivalent diameter pipe break in the LOCA does not exceed 0.5 square foot, the fuel assembly deformation shall be limited to a value not exceeding the deformation which would preclude satisfac-tory insertion of the CEAs.
- 2. For pipe break sizes greater than 0.5 square foot, deformation of structural components is limited to maintain the fuel in a coolable a rray. CEA insertion is not required for these events as the appropriate safety analyses do not take credit for CEA insertion.
- 3. For the upper and fitting springs, calculated shear stress must not exceed the minimum yield stress in shear.
- 4. For the spacer grids, the predicted impact loads must be less than the tested grid capability, ad defined in Reference 50.
D. Nomenclature The symbols used in defining the allowable stress levels are as follows:
P = Calculated general primary membrane stress (a) m Pb = Calculated primary bending stress S
m = Design stress intensity g ue as defined by Section III, ASME Boiler and Pressure Vessel Code Su = Minimum unirradiated ultimate tensile strength Fs = Shape fagr corresponding to the particular crosss section being analyzed Sy = Design stress intensity value for faulted conditions The definition of S' as the lesser value of 2.4 S and 0.7 S " is contained l7 in the ASME Boiler "dnd Pressure Vessel Code, SectTon III.
- a. P m
nd Pb are defined by Section III, ASME Boiler and Pressure Vessel C6de.
Amendment No. 7 March 31,1982 4.2-4
l 1
I
- b. With the exception of zirconium base alloys, the design stress intensity values, S , of materials not tabulated by the Code are determined in G thesameBannerastheCode. The design stress intensity of zirconium base alloys shall not exceed two-thirds of the unirradiated minimum yield strength at temperature. Basing the design stress intensity on I
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] Amendment No. 7 (
March 31, 1982 (
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O THIS PAGE INTENTIONALLY BLAHK.
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the unirradiated yield strength is conservative because the yield I
strength of zircaloy increases with irradiation. The use of the two-thirds factor ensures 50% margin to component yielding in response to M primary stresses. This 50% margin together with its application to the minimum unirradiated properties and the general conservatism applied in the establishment of design conditions is sufficient to ensure an adequate design.
- c. The shape factor, F3 , is defined as the ratio of the " plastic" moment (all fibers just at the yield stress) to the initial yield amount (extreme fiber at the yield stress and all other fibers stressed in proportion to their distance from the neutral axis). The capability of cross sections loaded in bending to sustain moments considerably in excess of t Timoshenko.g required to yield the outermost fibers is discussed in 4.2.1.1.2 Material Selection The fuel assembly grid cage structure consists of 10 Zircaloy-4 soacer grids,1 Inconel 625 spacer grid (at the lower end), 5 Zircaloy-4 guide 7 tubes, 2 stainless steel end fittings, and 4 Inconel X-750 coil springs.
Zircaloy-4, selected for fuel rod cladding, guide tubes and spacer grids, has a low neutron absorption cross section, and high corrosion resistance to reactor water environment. Also there is little reaction between the cladding and fuel or fission products. As described in Section 4.2.3, Zircaloy-4 has demonstrated its ability as a cladding, CEA guide tube, and spacer grid s material.
U) The bottom spacer grid is of Inconel 625 and is welded to the lower end fitting. In this region of local inlet turbulence, Inconel 625 was selected rather than Zircaloy-4 to provide additional strength and relaxation resist-ance. Inconel 625 is a very strong material with good ductility, corrosion resistance and stability under irradiation at temperatures below 1000F.
The fuel assembly lower end fitting is of cast 304 stainless steel (Grade CF-8) and the upper end fitting assembly consists of two cast stainless steel plates and five Type 304 stainless steel machines alignment posts.
This material was selected based on considerations of adequate strength and high-corrosion resistance. Also, Type 304 stainless steel has been used successfully in almost all pressurized water reactor environments, including all currently operating C-E reactors.
4.2.1.1.3 Control Element Assembly Guide Tubes All CEA guide tubes are manufactured in accordance with Grade RA-2, ASTM B353-71, Wrought Zirconium and Zirconium Alloy Seamless and Welded Tubes for Nuclear Serivce, with the following exceptions and/or additions:
A. Chemical Properties Additional limits are placed on oxygen.
C'J Amendment No. 7 March 31, 1982 4.2-5
B. Mechanical Properties
- 1. Flare A section of annealei tube, between 2 and 4 inches in length, shall be flared with a tool having a 60-degree included angle until the outside diameter has increased by 15%. The flared tube shall show no cracking when examined with the unaided eye.
C. Dimensional Requirements Permissible Tolerance Dimension (in.)
OD +0.003 ID 10.005 4.2.1.1.4 Zircaloy-4 Bar Stock All Zircaloy-4 bar stock is fabricated in accordance with Grade RA-2, ASTM B351, Hot-Rolled and Cold-Finished Zirconium and Zirconium Alloy Bars, Rod and Wire for Nuclear Application, with the following exceptions and/or additions:
A. Chemical Properties Additional limits are placed on oxygen and silicon content, B. Metallurgical Properties
- 1. Grain Size The maximum average grain size is restricted.
- 4. 2.1.1. 5 Zircaloy-4 Strip Stock All Zircaloy-4 strip stock is fabricated in accordance with Grade RA-2, ASTM B352, Zirconium and Zirconium Alloy Sheet, Strip and Plate for Nuclear Application, with the following exceptions and/or additions:
A. Chemical Properties Additional limits are placed on oxygen and silicon content.
B. Metallurgical Properties
- 1. Grain Size The maximum average grain size is restricted.
O 4.2-6
1 D. Specific Heat of UO 2
The specif is described by the following temperature dependent equations.fE0geat of UO 2 T < 2240F C = 49.67 + 2.2784 x 10-3T 3.2432 x 10 6 E
(T + 460)'
T > 2440 F Cp = -126.07 + 0.2621T - 1.399 x 10 -4T2 + 3.1786 x 10-8T3 y
- 2.483 X 10-12T4 where:
Cp = specific heat, BTV/ft3 , op T = temperature, F
- 4. 2.1. 2. 4. 5 Mechanical Properties CN A. Young's Modulus of Elasticity The static modulus of elasticity undar a strain rate of 0.097 hr ;of unirradiated fuel of 97%21).
is given by (Reference TD and deformed 6
E = 14.22 (1.6715 x 10 - 924.4T) where; E = modulus of elasticity in psi, T = tenperature in C in the range of 1000 to 1700'C.
B. Poisson's Ratio The Poisson's Ratio of polycrystalline U0, has a value of 0.32 at 25 C based on Reference 66. The same reference notes a 10% decrease in value over the range of 25 to 1800*C. Assuming the decrease is linear, the temperature dependence of the Poisson's Ratio is given by v = 0.32 - 1.8 x 10-5(T-25) where; v = Poisson's Ratio T = temperature in C in the range of 25 to 1800*C.
At temperature above 1800 C, a constant value of 0.29 is used for Poisson's (w Ratio.
Amendment No. 7 4.2-15
C. Yield Stress (not applicable)
D. Ultimate Stress (not applicable)
E. Uniform Ultimate Strain (not applicable) 4.2.1.2.5 Fuel Rod Pressurization Fuel rods are initially pressurized with helium for two reasons:
A. Preclude clad collapse during the design life af the fuel. The internal pressurization, by reducing stresses from differential pressure, extends the time required to produce creep collapse beyond the required service life of the fuel.
B. Improve the thermal conductivity of the pellet-to-clad gap within the fuel rod. Helium has a higher coefficient of thermal conductivity than the gaseous fission products.
In unpressurized fuel, the initially good helium conductivity is eventually degraded through the addition of the fission product gases released from the pellets. The initial helium pressurization results in a high helium to fission products ratio over the design life of the fuel with a corresponding increase in the gap conductivity and heat transfer. The effect of fuel rod power level and pin burnup on fuel rod internal pressure has been studied parametrically.
The initial helium fill pressure will be 380 PSIG. This initial fill <
pressure will be sufficient to prevenc clad collapse dis assed in Section 4.2.3.2.8 and will produce a maximum E0L internal pressure consistent with the criteria of Section 4.2.1.2.1. The calculational methods employed to generate internal pressure histories are discussed in Reference 14.
4.2.1.2.5.1 Capa_ city for Fission Gas Inventory _.
~
The greater portion of the gaseous fission products remain either within the lattice or the microporosity of the UO 7 fuel pellets and do not contribute to the fuel rod internal pressure. However, a fraction of the fission gas is released from the pellets by diffusion and pore migration and thereafter contributes to the internal pressure.
The determination of the effect of fission gas generated in and released from the pellet column is discussed in Section 4.2.3.2.2. The rod pressure increase which results from the release of a given quantity of gas from the fuel pellets depends upon the amount of open void volume available within the fuel rod and the temperatures associated with the various void volumes.
In the fuel rod design, the void volumes considered in computing internal pressure are:
. Fuel rod upper end plenum Fuel-clad annulus Amendment No. 7 March 31, 1982 4.2-16
i Inconel Alloy 625 (Ni-Cr-Fe)
C.
Configuration (as absorber) Cylindrical bar Outside diameter, inches 0.816 +0.002 Inside diameter, inches Solid Length of cylinder, inches 74.375 (Part length CEA) l Density, lb/in.3 0.305 t
i Ultimate tensile l Strength, 1b/in.2 120-150 Specified minimum yield l strength @ 650F, ksi 65 l Elongation in 2 inches,
% 30 Young's modulus, 1b/in.2 at 70F 29.7 x 10 6 l 's at 650F 27.0 x 10 6 Thermal conductivity (Btu /h-ft- F):
70F 5.7 600F 8.2 Linear *.hermal expansion 7.4 x 10 -6 (in./in.- F) (70 to 600F) 4.2.1.4.2 Compatibility of Absorber and Cladding Materials The cladding material used for the control elements is Inconel Alloy 625.
The selection of this material for use as cladding is based on consideration of strength, creep resistance, corrosion resistance, and dimensional stability l under irradiation and also upon the acceptable performance of this material for this application in other C-E reactors currently in operation.
A. 84C/Inconel 625 Compatibility Studies have been conducted by HEDL(38) on the compatibility of Type 316 stainless steel with B 4C under irradiation for thousands of hours at tempera-tures between 1300 and 1600F. Carbide formation to a depth of about 0.004 i
I 1
4.2-25
.l
inch in the 316 stainless steel was measured after 4400 hours0.0509 days <br />1.222 hours <br />0.00728 weeks <br />0.00167 months <br /> at 1300F.
Similar compound formation depths were observed after ex-reactor bench testing. After testing at 1000F, only 0.001 in./yr of penetration was measured. Since Inconel 625 is more resistant to carbide formation than 316 stainless steel, and the expected pellet / clad interfacial temperature in the standard design i', below 800F, it is concluded that B4C is compatible with Inconel 625.
4.2.1.4.3 Cladding 5 tress-Strain Limits The stress limits for the Inconel Alloy 625 cladding are as follows:
Design conditions of Non-Operation, Normal Operation, and Urset Conditions:
b Pm1m P
m
+P b i Fbsm The net unrecoverable circumferential strain shall not exceed 1% on the cladding 7 diameter, considering the effects of pellet swelling and cladding creep.
Design conditions of Emergency Conditions:
Pm5 1. 5 S m P
m
+P b 1 1.5 F sm S
Design conditions of Faulted Conditions: O P
m1 b m P
m
+P b 1 I sb'm where niS is the smaller of 2.4 S m r 0.7S u P S S and F , see Section 4.2.1.1.1. For For definition the Inconel 625 of CEAP*clabdin3,, S'th3,vaYu,eofS s is two-thirds of the minimum specified yield strength at temperature.
For Inconel 625, the specified minimum yield strength is 65,000 lb/in.2 at 650F.
F = Mp/My where Mp is the bending moment required to produce a fully plastic sbetionandMyisthebendingmomemtwhichfirstproducesyieldingatthe extreme fibers of the cross-section. The capability of cross-sections loaded in bending to sustain moments considerably in excess of that required to yield the outermost fiber is discussed in Reference 1. For the CEA cladding dimensions, T s = 1.33.
Amendment No. 7 March 31, 1982 4.2-26
o 4
The values of uniform and total elongation of Inconel Alicy 625 cladding are
- estimated to be as follows
22
\ Fluence (E >l MeV), nyt .1 x 10 3 x 10 22
- Uniform elongation, % 3 1 i Total elongation, % 6 3 4.2.1.4.4 ' Irradiation Behavior of Absorber Materials A. Boron Carbide' Properties ,
- 41. Swelling. The linear swelling of B C 4 increases with burnup according to the relationship:
10
%AL = (0.1) B Burnup, a/o This relationship was obtainef3h{ m experimental irradiations on high density (>90% TD) wafers (38)ah0yellets with densities ranging between 71 and 98% TD. Dimensional changes were measured as a function of burnup, _ after irradiating at temperature expected in the design.
1 -
- 2. Thermal Conductivity. The thermal conductivity of unirradiated 73% dense 4B C decreases linearly with temperatures from 300 to 1
1600 F, according to the relationship:
1 cal /cm- K-s
. y , _2.17 (6.87 + 0.017 TT Thisrelationshipwasobtainedfro7479asurementsperformedon pellets ranging from 70 to 98% TD.
i The relationship between the thermal conductivity of irradiated 73%TDBCpellgy)andtemperaturegivenbelowwasderivedfrom 4
measuredvalug on higher density pellets irradiated to fluences out to 3 x 10 nyt (E >l MeV).
, _ 1 cal /cm- K-s 7 l 2.17 (38 + 0.025 T) where T = temperature, K Thermal conductivity measurements of 17 BgG specimens with densities ranging from 83 to 98% TD, irradiated at temperatures from 930 to 1600F showed that thermal conductivity decreased significantly
, ~
after irradiation. The rate of decrease is high at the lower
! irradiation temperatures, but saturates rapidly with exposure.
- 3. Helium Release. Helium is formed in B C as B 10 burnup progresses.
] The fraction of helium released from the pellets is important for 4
determining rod internal gas pressure. The relationship between i
I Amendment No. 7 March 31, 1982 4
4.2-27
}
, = , . . . .
helium {ggaseandirradiationtemperaturegivenbelowwasdeveloped at ORNL to fit experimental data obtained from thermal reactor irradiations.
%He release = e(C-1.85D)e where:
C = Constant, 6.69 for pellets D = Fractional density, 0.73 for C-E pellets Q = Activation energy contant, 3600 cal / mole R = Gas constant, 1.98 cal / mole - K T = Pellet temperature, K This expression becomes
-1820
% He release = 208 e T +5 when the above parameters are substituted. In this form, design values for helium release as a function of temperature are generated.
The 5% helium release allowance (the last term in the expression) was added to ensure that design values lie above all reported helium release data. Calculated values of helium release obtained fromtherecgngg)dgnexpressionlieaboveallexperimental data points obtained on B C pellet specimens irradi-4 ated in thermal reactors.
- 4. Pellet Porosity. Experimental evidence is available ) which shows that for pellet densities below 90%, essentially all porosity is open at beginning-of-life. Irradiation-induced swelling does not change the characteristics of the porosity, but only changes the bulk volume of the specimens. Therefore, the amount of porosity available at end-of-life is the same as that present at beginning-of-life.
B. Inconel 625
- 1. Swelling. Available information indicates that Inconel 625 is highlyresistanttoragjationswelling. Exposure of Inconel 625 to a fluence of 3 x 10 nvt(E>0.1MeV)atatemperatureof400h48)
(725F) showed no visible cavities in metallographic examinations so that swelling, if any, would be very minor. Direct ge 2 surements made after exposure of Inconel 625 to a fluence 5 x 10 nvt (E>0.1MeV)asLMFBRconditjgnsshowednoevidenceofswelling.(49)
Further exposure to 6 to 10 nvt (E>0.1 MeV) at 500 C (932 F) showed essentially no swelling as measured by immersion density, butdig2show small cavities. Thus, Inconel 625 after fluences of 3 x 10 nvt (E>l MeV) is not expected to swell.
O 4.2-28
I p 2. Ductility. The ductility of Inconel 625 decreases after irradia-tion. Extrapolation of lower fluence data on Inconel 625 and 500 indicates that the value52 f unif rm and total elongation of
- Inconel 625 after 1 x 10 nyt (E >1 MeV) are 3 and 6%, respectively.
- 3. Strength. The value of yield strength of Inconel 625 increases af ter irradiation in the manner typical for metals. However, no credit is taken for increases in yield strength in the design analyses above the value initially specified.
4.2.1.5 Surveillance Program 4.2.1.5.1 Requirements for Surveillance and Testing of Irradiated Fuel Rods i
High burnup performance experience, as described in Section 4.2.3 has provided evidence that the fuel will perform satisfactorily under the design condi-i tions. The current core design bases do not include a specific requirement for surveillance and testing of irradiated fuel rods. C-E, however, has instituted a fuel surveillance program on each reactor core produced. Under this program, selected fuel assemblies are characterized during the fabrication
, process. Detailed measurements of important fuel pellet and cladding attri-butes, as well as dimensional characteristics of the fuel assembly structure, are made and recorded. In addition, special examination equipment is available to repeat the measurements of these characterized fuel assemblies in refueling pools. The fuel assembly design allows disassembly and reassembly to facilitate such inspections. Thus, should the need arise, irradiated V fuel rod examination can be accomplished.
A fuel rod irradiation program has been developed to evaluate the performance of fuel rods designed for use in the 16 x 16 fuel assembly. The program includes the irradiation of six standard 16 x 16 assemblies, two each for 1,
- 2, and 3 cycles, respectively, in the Arkansas Nuclear One-Unit 2 reactor.
Each assembly will contain a minimum of 50 precharacterized, removable rods distributed within the assembly to obatin a spectrum of exposure levels for evaluation purposes in interim and terminal examinations. Interim examination of all six assemblies is planned during refueling shutdowns af ter each cycle.
The ANO-2 fuel rods and specific components of the fuel rods have recieved a detailed pre-characterization. The program calls for substantial cladding characterization to include mechanical properties, texture, hydride orientation and out-of-reactor low strain rate behavior. In addition to the ID and OD dimensional data normally obtained on the clad tubing material, a minimum of 300 fuel rods will be measured to obtain as-loaded dimensions. Sufficient fuel rods will be profiled to obtain diameter and ovality measurements such that changes in these parameters can be tracked by similar measurements during interim inspections. Also, a random selection of approximately 100 007 pellets from each lot per batch used will be characterized dimensionally anc the density distribution will be determined. About one-half of these pellets will be placed in known axial locations in selected fuel rods while the remainder will be set aside as archives.
4.2-29
A poolside non-destructive examination will be made during each of the first three refuelings at ANO-2. The six 16 x 16 assemblies with characterized rods will be removed from the reactor at each refueling and moved to the spent fuel pool for leak testing (if failed fuel is in the core) and for visual inspection. The length of the assembly and peripheral rods will be measured. During the shutdown, a target of 20 pre-characterized rods per batch will be scheduled for examination and measurement. At some time after the refueling outage, pre-characterized rods retained in discharged assemblies will be measured. A target of 100 rods will be eddy current tested after each shutdown.
4.
2.2 DESCRIPTION
AND DESIGN DRAWINGS l
This subsection summarizes the mechanical design characteristics of the fuel system and discusses the design parameters which are of significance to the performance of the reactor. A sungnary of mechanical design parameters is presented in Table 4.2-1. These data are intended to be descriptive of the design; limiting values of these and other parameters will be discussed in the appropriate sections.
4.2.2.1 Fuel Assembly _
The fuel assembly (Figure 4.2-6) consists of 236 fuel and poison rods, 5 guide tubes,11 fuel rod spacer grids, upper and lower end fittings, and a 7 holddown device. The outer guide tubes, spacer grids, and end fittings form the structural frame of the assembly.
The fuel spar.er grids (Figure 4.2-7) maintain the fuel rod array by providing positive lateral restraint to the fuel rod but only frictional restraint to axial fuel rod motion. The grids are fabricated from preformed Zircaloy or Inconel strips (the bottom spacer grid material is Inconel) interlocked in an egg crate fashion and welded together. Each cell of the spacer grid contains two leaf springs and four arches. The leaf springs press the rod against the arches to restrict relative motion between the grids and the fuel rods. The perimeter strips contain features designed to prevent hangup of grids during a refueling operation.
The ten Zircaloy-4 spacer grids are fastened to the Zircaloy-4 guide tubes l7 by welding, and each grid is welded to each guide tube at eight locations, four on the upper face of the grid and four on the lower face of the grid, where the spacer strips contact the guide tube surface. The lowest spacer grid (Inconel) is not welded to the guide tubes due to material differences.
It is supported by an Inconel 625 skirt which is welded to the spacer grid and to the perimeter of the lower end fitting.
Amendment No. 7 March 31, 1982 0
4.2-30
The upper end fitting is an assembly consisting of two cast 304 stainless 7
[n steel plates, five machined posts and four helical Inconel X-750 springs.
\. The end fitting attaches to the guide tubes to serve as an alignment and locating device for each fuel assembly and has features to permit lifting of the fuel assembly. The lower cast plate locates the top ends of the guide tubes and is designed to prevent excessive axial motion of the fuel rods.
The Inconel X-750 springs are of conventional coil design having a mean diameter of 1.856 in. , a wire diameter of 0.316 in. , and 16 active coils.
Inconel X-750 was selected for this application because of its previous use for coil springs and good resistance to relaxation during operation.
The upper cast plate of the assembly, called the holddown plate, together with the helical compression springs, comprise the holddown device. The holddown plate is movable, acts on the underside of the tube sheet tubes and is loaded by the compression springs. Since the springs are located at the upper end of the assembly, the spring load combines with the fuel assembly weight to counteract upward hydraulic forces. The determination of upward hydraulic forces includes factors accounting for flow maldistribu-tion, fuel assembly component tolerances, crud buildup, drag coefficient, and bypass flow. The springs are sized and the spring preload selected such that a net downward force will be maintained for all normal and anticipated transiet flow and temperature conditions. The design criteria limit the maximum stress under the most adverse tolerance conditions to below yield strength of the spring material. The maximum stress occurs during cold conditions and decreases as the reactor heats up. The reduction in stress in due to a decrease in spring deflection resulting from differential thermal O expansion between the Zircaloy fuel bundles and the stainless steel interna During normal operation, a spring will never be compressed to its solid i height. However, if the fuel assembly were loaded in an abnormal manner such that a spring were compressed to its solid height, the spring would continue to serve its function when the loading condition returned to normal.
1 The lower end fitting assembly is a simple stainless steel casting consisting l7 of a plate with flow holes and a support leg at each corner (total of four legs) that aligns the lower end of the fuel assembly with the core support structures alignment pins. Each alignment pin is required to position the corners of four lower end fittings. A center post is threaded into the central portion of 7 the flow plate and crimped into position.
! The four outer guide tubes have a widened region at the upper end which I
contains an internal thread. Connection with the upper end fitting is made by passing the externally threaded end of the guide posts through holes in the lower cast flow plate and into the guide tubes. When assembled, the fiow plate is secured between flanges on the guide tubes and on the guide posts. The connection with the upper end fitting is locked with a mechanical crimp. Each outer guide tube has, at its lower end, a welded Zircaloy-4 fitting. This fitting has a threaded portion which passes through a hole in the fuel assembly lower end fitting and is secured by a Zircaloy-4 nut.
This joint is secured with a stainless steel locking ring tack welded to the lower end fitting in four places.
O/ Amendment flo. 7 March 31, 1982 4.2-31
The central instrumentation guide tube inserts into a socket and a sleeve 7
in the upper and lower end fittings, respectively, and is thus retained laterally by the relatively small clearance at these locations. The upper end fitting socket is created by the center guide tube post which is threaded into the lower cast flow plate and tack welded in two places. The lower end 7 fitting sleeve is an extension from the center post of the lower end fitting assembly. There is no positive axial connection between the central guide tube and the end fittings.
The five guide tubes have the effect of ensuring that bowing or excessive swelling of the adjacent fuel rods cannot result in obstruction of the control element pathway. This is so because:
A. There is sufficient clearance between the fuel rods and the guide tube surface to allow an adjacent fuel rod to reach rupture strain without contacting the guide tube surface.
B. The guide tube, having considerably greater diameter and wall thickness (and also, being at a lower temperature) than the fuel rod, is considerably stiffer than the fuel rods and would, therefore, remain straight, rather than be deflected by contact with the surface of an adjacent fuel rod.
Therefore, the bowing or swelling of fuel rods would not result in obstruc-tion of the control element channels such as could hinder CEA movement.
The fuel assembly design enable reconstitution, i.e., removal and replacement of fuel and poison rods, of an irradiated fuel assembly. The fuel and poison rod lower end caps are conically shaped to ensure proper insertion within the fuel assembly grid cage structure; the upper end caps are designed to enable grappling of the fuel and poison rod for purposes of removal and handling. Threaded joints which mechanically attach the upper end fitting to the control element guide tubes will be properly torqued and locked during service, but may be removed to provide access to the fuel and poison rods.
Loading and movement of the fuel assemblies is conducted in accordance with strictly monitored administrative procedures and, at the completion of fuel loading, an independent check as to the location and orientation of each fuel assembly in the core is required.
The serial number provided on the fuel assembly upper end fitting enables verification of fuel enrichment and orientation of the fuel assembly. The serial number is also provided on the lower end fitting to ensure preservation of fuel assembly identity in the event of upper end fitting removal. Additional markings are provided on the fuel rod upper end caps as a secondary check to distinguish between fuel enrichments and burnable poison rods, if present.
During the manufacturing process, the lower end cap of each rod is marked to provide a means of identifyirg the pellet enrichment, pellet lot and fuel stack weight. In addition, a quality control program specification requires that measures be established for the identification and control of materials, components, and partially fabricated subassemblies. These means provide Amendment No. 7 March 31, 1982 4.2-32
4 i
! assurance that only acceptable items are used and also provide a method of Q relating an item or assembly from initial receipt through fabrication, installation, repair, or modification to an applicable drawing, specification, or other pertinent technical document.
4.2.2.2 Fuel Rod The fuel rods consist of slightly-enriched U09 cylindrical ceramic pellets, a round wire Type 302 stainless steel comprestion spring, and an alumina spacer disc located at each end of~the fuel column, all encapsulated within a Zircaloy-4 tube seal welded with Zircaloy-4 end caps. The fuel rods are internally pressurized with helium during assembly. Figure 4.2-8 depicts the fuel rod design.
Each fuel rod assembly includes both a serial number and a visual identifica-tion mark. The serial number ensures traceability of the fabrication history of each fuel rod component. The identification mark provides a visual check on pellet enrichment batch during fuel bundle fabrication.
The fuel cladding is cold worked and stress relief annealed Zircaloy-4 tubing 0.025 inches thick. The actual tube forming process consists of a series of cold working and annealing operations, the details of which are selected to provide the combination of and properties discussed in Section 4.2.1.2.2.
The U0 therma $pelletsaredishedatbothendsinordertobetteraccommodate i(A) expangion and fuel swelling. The density of the U0 is10.38g/cm,whichcorrespondsto94.75%ofthe10.96g/bmjnthepellets theoretical density (TD) of UO . However, because the pellet dishes and chamfers consti-tuteabout3%oftbevolumeofthepe pelletstackisreducedto10.06g/cm}letstack,theaveragedensityofthe
. This number is referred to as the
" stack density".
The compression spring located at the top of the fuel pellet column maintains the column in its proper position during handling and shipping. The alumina spacer disc at the lower end of the fuel rod reduces the lower end cap temperature, while the upper spacer disc prevents UO 7 chips, if present, from entering the plenum region. The fuel rod plenum which is located above i the' pellet column, provides space 'or axial thermal differential expansion
! of the fuel column and accommodates the initial helium loading and evolved I fission gases. (See Section 4.2.1.2.5.1 and 4.2.1.2.5.2.) The specific r manner in which these factors are taken into account, including the calculation
! of temperatures for the gas contained within the various types of rod internal 1
void volume, is discussed in Reference 14.
4.2.2.3 Burnable Poison Rod Fixed burnable neutron absorber (poison) rods, Figure 4.2-9, will be included in selected fuel assemblies to reduce the beginning-of-life moderator coeffi-cient. They will replace fuel rods at selected locations. The poison rods
! will be mechanically similar to fuel rods, but will contain a column of burnable poison pellets instead of fuel pellets. The poison material will
, 4.2-33 i
i
. ,- , . - - - - - - - , , . - . . , - - , - , , - , . . , ,n. .,.
be alumina with uniformly-dispersed boron carbide particles. The balance of the column will consist of alumina pellets, with the total column length the same as the column length in fuel rods. The burnable poison rod plenum spring is desinged to produce a smaller preload on the pellet column than that in a fuel rod because of the lighter material in the poison pellets.
Each burnable poison rod assembly includes a serial number and visual identifi-cation mark. The serial number is used to record fabrication information for each component in the rod assembly. The identification mark is unique to poison rods and provides a visual check on the pellet boron content during fuel bundle fabrication.
4.2.2.4 Control Element Assembly Description and Design The control element assemblies consist of four, and twelve neutron absorber elements arranged to engage the peripheral guide tubes of fuel assemblies.
The neutron absorber elements are connected by a spider structure which couples to the control element drive mechanism (CEDM) drive shaft extension.
The neutron absorber elements of a four element CEA engage the four corner guide tubes in a single fuel assembly. The four element CEAs are used for power shaping functions and make up the first control rod group to be inserted at high power. The twelve-element CEAs engage the four corner guide tubes in one fuel assembly and the two nearest corner guide tubes in adjacent fuel assemblies. The twelve element CEAs make up the balance of the control groups of CEAs and provide a bank of strong shutdown rods. The control element assemblies are shown in Figures 4.2-3 and 4.2-5. The pattern of CEAs (total of 89) is shown in Figure 4.2-10. Note that up to eight additional CEAs may be installed if desired for additional flexibility or future use.
Part-length CEAs are differentiated from full-length CEAs by using alphanumeric serialization instead of the numerical system used on the full-length CEAs.
7 The control elements of a full-length CEA consist of an Inconel 625 tube loaded with a stack of cylindrical absorber pellets. The absorber material consists of 73% TD boron carbide (B g C) pellets, with the exception of the lower portion of the elements, which contain reduced diameter B C4 pellets wrapped in a sleeve of type 347 stainless steel telt metal.
The design objective realized by the use of felt metal and reduced B C g pellets in the elenent tip zones is that as the B,C pellets swell due to irradiation, the felt metal sleeve compresses as 3 result of the applied loading. This compression limits the amount of induced strain in the clad-ding. Therefore buffering of the CEA following scram, which occurs when the Amendment No. 7 March 31, 1982 4.2-34
l J
B. Short-term axial load due to the impact of the spring loaded CEA spider against the upper guide structure support plates at the end of a CEA trip.
i For trips occurring during nonnal power operation, solid impact is not predicted to occur due to the kinetic energy of the CEA being dissipated ,
in the hydraulic buffer and by the CEA spring.
C. Short-term differential pressure load occurring in the hydraulic buffer regions of the outer guide tubes at the end of each trip stroke.
The buffer region slows the CEA during the last few inches of the trip a
stroke. the resultant differential pressyre across the guide tube in j this region is predicted to be 300 lb/i circumferential stresses of 3300 lb/in,p. , and is
, which thisless gives thanrise one-to quarter of the yield stress, for a very short term. The trip is assumed to be repeated daily. However the resultant stress is too small to have a significant effect on fatigue usage. P
- For conditions other than normal operation, the additional mechanical loads
- and large break LOCA and their resultant effect on the control element guide
{
tubes are discussed in the following paragraphs:
4.2.3.1.2.1 Op_erating Basis Earthquake (OBE). During the postulated OBE, the fuel assembly is subjected to lateral and axial accelerations which, in turn, cause the fuel assembly to deflect from its normal shape.
N The method of calculating these deflections is described in Section 3.7.3.14.
) The magnitude of the lateral deflections and resultant stresses are evaluated for acceptability. The method for calculating stresses from deflected shapes is described in Reference 50. The fuel assembly is designed to be capable of withstanding the axial loads without buckling and without sustaining excessive stresses.
j 4.2.3.1.2.2 Safe Shutdown Earthquake (SSE). The axial and lateral loads and deformation sustained by the fuel assembly during a postulated SSE have the same origin as those discussed above for the OBE, but they arise from initial ground accelerations twice those assumed for the OBE. The analytical methods used for the SSE are identical to those used for the OBE.
4.2.3.1.2.3 Loss-of-Coolant Accident (LOCA). In the event of a large 4
break LOCA,- there will occur rapid changes in pressure and flow within the reactor vessel. Associated with the transient are relati wly large axial
~
4 and lateral loads on the fuel assemblies. The response of a fuel assembly to the mechanical loads produced by a LOCA is considered acceptable if the fuel rods are maintained in a coolable array, i.e., acceptably low grid crushing. The methods used for analysis of combined seismic and LOCA loads and stresses is described in Reference 50.
4 4.2.3.1.2.4 Combined SSE and LOCA. It is not considered appropriate i to combine the stresses resulting from the SSE and LOCA events. Nevertheless, j for purposes of demonstrating margin in the design, the maximum stress 7:
1
( Amendment No. 7 March 31, 1982
, 4.2-37
intensities for each individual event will be combined by a square root of sum of the squares (SRSS) method. This will be performed as a function of fuel assembly elevation and position, e.g., the maximum stress intensities for the center guide tube at the upper grid elevation (as determined in the 7 analysis discussed in the above paragraphs for SSE and LOCA) will be com-bined by the SRSS method. It is expected that the results will demonstrate that the allowable stresses described in paragraph 4.2.1.1 are not exceeded for any position along the fuel assembly even unaer the added conservatism provided by this load combination.
To qualify the complete fuel assembly, full-scale hot loop testing is being conducted. The tests are designed to evaluate fretting and wear of components, refueling procedures, fuel assembly uplift forces, holddown performance and O
Amendment No. 7 March 31, 1982 0
4.2-37a
compatibility of tne fuel assembly with uterfacing reactor internals, CEAs V]
/
and CEDMs under conditions of reactor water chemistry, flow velocity, tempera-ture, and pressure. The test assemoly will be identical to the 16 x 16 five guide tube design. The test will be run for approximately 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> with completion scheduled to be timely for the first System 80 plant to go on-line.
Mechanical testing of the fuel assembly and its components is being performed to support analytical means of defining the assembly's structural characteris-tics. The test program consists of static and dynamic tests of spacer grids and static and vibratory tests of a full-size fuel assembly. These tests as well are scheduled for completion to support the first System 80 unit to go on-line.
4.2.3.1.3 Spacer Grid Evaluation The function of the spacer grids is to provide lateral support to fuel and burnable poison rods in such a manner that the axial forces are not sufficient to buckle or bow the rods and that the wear resulting at the grid-to-clad contact points will be limited to acceptably small amounts. It is also a criterion that the grid be capable of withstanding the lateral loads imposed during the postulated seismic and LOCA events.
fuel assemblies are designed such that the combination of fuel rod rigidity, grid spacing, and grid preload will not result in significant fuel rod deformation under axial loads, and the long-term effects of clad creep
( (reduction in clad OD), the reduction of grid stiffness with temperature and b the partial relaxation of the grid material during operation ensure that this criterion is also satisfied during all operating conditions. Moreover, inspection of irradiated fuel assemblies from the Maine Yankee (14 x 14),
Calvert Cliffs (14 x 14) Palisades (15 x 15) and Omaha (14 x 14) reactors has not shown significant bowing of the fuel rods. In view of these factors and the similarity of these design to the Standard System 80 designs, it is concluded that the axial forces applied by the grids on the cladding will not result in a significant degree of fuel rod bow. The influence of fuel rod lateral deflection is discussed further in Section 4.2.3.2.6. Additional discussion of the causes for and effects of fuel rod bowing are contained in Section 4.2.3.2.6 and in Reference 53.
The capability of the grids to support the clad without excessive clad wear is demonstrated by out-of pile flow testing, to be completed as describcd above, on the Standard System 80 assembly design and by the results of post-irradiation examination of grid-to-clad contact points in Maine Yankee fuel assemblies which showed only negligible clad wear (Reference 51).
The capability of the grid to withstand the lateral loads produced during the postulated seismic and LOCA events is demonstrated by impact testing the reference grid design, both at room temperature and at operating temperature, and comparing the test results with the analytical predictions of the seismic and LOCA loads.
)
4.2-38
O THIS PAGE INTENTI0t1 ALLY BLAllK.
g l
l O
i b. Adequate margin to criticality shall be provided for full j n rack loadings of fuel assemblies having a mechanical design similar to that described in Chapter 4.0 and enrichments up i
l (V )
to 3.7 w/o U-235.
- c. The degree of subcriticality provided shall be consistent with the requirements of ANSI Standard H18.2 Section 5.7.4.1.
i
- F. Independence 4
Not Applicable G. Thermal Limitations
- 1. Cooling air shall be provided to the CEDM's at a minimum flow rate of 700 SCFM per CEDM at a temperature in the range of 80F- l7 i 120F.
- 2. Drains, permanently connected systems, and other features of the
, spent fuel pool shall be designed so that neither maloperation
- nor failure can result in loss of coolant that would uncover the stored fuel, j' 3. Spent fuel pool cooling shall be capable of removing the decay heat generated from 1 complete core of spent fuel placed in the pool 7 days after shutdown in addition to 1/3 of a completed core that has been in the pool 90 days after shutdown.
j H. Monitoring
- 1. Low water level alarms shall be provided for the refueling pool and the spent fuel pool.
l 2. A system shall be provided to monitor the Reactor Coolant System
! for internal loose parts. The system shall have the ability to
- detect a loose part striking the internal surface of Reactor Coolant System components with an energy level of one-half foot i
pound or more. The system shall have alam and recording capability.
The system design shall be suitable for the temperature and humidity environment experienced in the area where the equipment nomally operates.
I. Operational / Controls 1
} Not Applicable i
- J. Inspection and Testing
- 1. In service Inspection shall be performed in accordance with Section XI of the ASME Code.
Amendment No. 7 March 31, 1982 i
b' 4.2-65
K. Chemistry / Sampling Not Applicable L. Materials
- 1. See Section 5.1.4.L.3 M. System / Component Arrangement Not Applicable N. Radiological Waste Not Applicable
- 0. Overpressure Protection Not Applicable P. Related Services
- 1. For refueling operations, the containment building crane shall have a minimum capacity of 225 tons.
- a. A hoisting speed of 6 inches per minute or less shall be utilized during refueling operations.
- b. A load measuring device shall be provided for use during heavy lifts.
- c. A low inching speed is required during those portions of the lift when close tolerance surfaces are engaging each other.
- 2. An overhead crane shall be provided in the new fuel storage area to facilitate handling of new fuel,
- a. The crane capacity shall be at least 1 ton to accommodate the weight of a fuel assembly.
- b. A vertical hoisting speed of 6 feet / minute or less shall be provided.
- c. The crane load shall be capable of being limited to prevent the hoist load from exceeding 5000 pounds when handling fuel 5 assemblies.
- 3. See Section 5.1.4.P.3 Q. Environmental Not Applicable O
4.2-66
I pl 31. Kingery, W. D., " Introduction to Ceramics," John Wiley & Sons, pp i 486-504.
V
- 32. Toulookan, Y. S., "Thermophysical Properties of High Temperature Solid Materials," Vol 4 and 5, MacMillan.
- 33. Moore, G. E. and Kelley, K. K., "J. Am. Chem. Soc.", Vol 69, pp 309-16, 1947.
- 34. Keilholtz, G. W., Moore, R. E., and Robitson, M. E., " Effects of High Boron Burnups on48 C and ZrB Dispersions in Al p3 0 and Zirca-loy-2," BM1-1627, April 24, 1963.2
- 35. Burian, R. J., Fromm, E. 0., and Gates, J. E. "Effect of High Boron Burnups on B C and ZrB Dispersions in A123 0 and Zircaloy-2" BM1-1627, April 4, 1963 2
- 36. Cunningham, G. W., " Compatibility of Metals and Ceramics, " Proceed-ings of Nuclear Applications of Nonfissionable Ceramics, pp 279-289, May 1966.
- 37. Graber, M. J., "A Metallurgical Evaluation of Simulated BWR Emergency Core Cooling Tests," Idaho Nuclear Corporation, IN-1453, March 1971.
- 38. Pitner, A. L., "The WDC 1 Instrumental Irradiation of Boron Carbine in a Spectrum-Hardened ETR Flux," HEDL-TME-73-38, April Q 1973.
- 39. Gray, R. G. and Lynam, L. R., " Irradiation Behavior of Bulk B C and 4
B4 C-sic Burnable Poison Plates," WAPD-261, October 1963
- 40. "HEDL Quarterly Technical Report for October, November and December 1974," Vol 1, HEDL-TME-74-4, pp A-51 to A-53, January 1975.
- 41. Mahagan, D. E. , " Boron Carbide Thermal Conductivity," HEDL-TME 78, September 1973.
- 42. Homan, F. J., " Performance Modeling of Neutron Absorbers," Nuclear Technology, Vol 16, pp 216-225, October 1972.
- 43. Pitner, A. L. and Nusscher, G. E., " Irradiation of Boron Carbide Pellets and Powders in Hanford Thermal Reactors," WHAN-FR-24, December 1970.
- 44. Pitner, A. L. and Russcher, G. E., "A Function on Predict LMFBR Helium Release Bound on Boron Carbide Irradation Data from Thermal Reactors," HEDL-TME-71-127, September 30, 1971.
- 45. HEDL-73-6, " Materials Technology Program Report for October, November, and December 1973," pp A-69 to A-72.
f%
- 46. Deleted 4
4.2-69
_rn,. , ,,-wp * .- 7 f,7- - - . , . w
- 47. Tipton, C. R. , " Reactor Handbook," Vol 1, Materials, Interscience, p 827, 1960.
- 48. "flational Alloy Development Program Information Meeting," pp 39-63, TC-291, May 22, 1975.
- 49. " Quarterly Progress Report - Irradiation Effects on Structural Materials," HEDL-TEM-161, pp GE GE-10.
- 50. " Structural Analysis of Fuel Assemblies for Seismic and Loss of Coolant Accident Loading," Combustion Engineering, Inc., 7 CENPD-178, Rev. 1, August 1981.
- 51. " Joint C-E/EPRI Fuel Performance Evaluation Program, Task C, Evalua-tion of Fuel Rod Performance on Maine-Yankee Core I," Combustion Engineering, Inc., CENPD-221, December 1975.
- 52. " Pressurized Water Reactor Project Period January 24, 1964 to April 23, 1964, WAPD-MRP-108.
- 53. " Fuel and Poison Rod Bowing," Combustion Engineering, Inc. , CENPD-225-P (Proprietary), October 1976.
- 54. Caye, T. E. "Saxton Plutonium Project, Quarterly Progress Report for the Period Ending March 31, 1972, WCAP-3385-31, November 1972.
- 55. Berman, R. M., Meieran, H. B., and Patterson, P., " Irradiation Behavior of Zircaloy-Clad Fuel Rods Containing Dished End U02 Pellets," (LWBR-LSBR Development Program), WAPD-TM-629, July 1967.
- 56. Baroch, S. J., et al., " Comparative Performance of Zircaloy and Stainless Steel Clad Fuel Rods Operated to 10,000 mwd /MTU in the VBWR," GEAP-4849, April 1966.
- 57. Megerth, F. H. , "Zircaloy-Clad U0,3 Fuel Rod Evaluation Program,"
Quarterly Progress Report No. 8, August 1969-October 1969. GEAP-10121, November 1969.
- 58. Megerth, F. H., "Zircaloy-Clad UO Fuel Rod Evaluation Program,"
Quarterly Progress Report No. 1, 7 november 1967-January 1968, GEAP-5598, March 1968.
- 59. San Onofre Nuclear Generating Station, Units 2 & 3, Final Safety Analysis Report, Volume-9, pages 4.2 4.2-61.
- 60. Brite, D. W. et al, "EEI/EPRI Fuel Densification Program Final Reprt," Battelle Pacific Northwest Labratoreis, March 1975.
- 61. Stephan, L. A., "The Response of Waterlogged U0 2 Fuel Rods to Power Bursts," IDO-ITR-105, April 1969.
- 62. Stephan, L. A., "The Effects of Cladding Material and Heat Treatment on the Response of Waterlogged 00 2 Fuel Rods to Power Burst," IM-ITR-lll, January 1970.
Amendment No. 7 March 31, 1982 4.2-70
TABLE 4.2-1 MECHANICAL DESIGN PARAMETERS (Sheet 1 of 4)
Core Arrangenent j Number of fuel assemblies in core, total 241 Number of CEAs 89
- Number of fuel rod locations 56,876 Spacing between fuel assemblies, fuel rod surface to surface, inches 0.208 Spacing, outer fuel rod surface to core shroud, inches 0.214 Hydraulic diameter, nominal channel, feet 0.0393 2
Totalflowarea(exgludingguidetubes),ft 60.9 Total core area, ft 112.3 Core equivalent diameter, inches 143.6 Core circumscribed diameter, inches 152.46 Total fuel loading, Kg U (assuming all rod locations are fuel rods) 102.7 x 10 3 Total fuel weight, lb U02 (assuming all rod locations are fuel rods) 257.1 x 10 3 7 Total weight of Zircaloy, lb 71,758 Fuel volume (including dishes), ft 3 409.6 O Fuel Assemblies No. of Enrichment No. of Poison Rods Batch Assemblies (wt%) U-235 per Assembly A0 69 1.92 0 B1 44 12 rods wit 1 1.92 16 208 rods wi th 2.78 B2 64 12 rods with 1.92 16 208 rods with 2.78 7 C0 40 12 rods with 2.78 0 224 rods with 3.30 C1 24 12 rods with 2.78 16 208 rods with 3.30 24T-Fuel Rod array square 16 x 16 Fuel Rod Pitch, inches 0.506 Spacer Grid Type Leaf spring Material Zircaloy-4 Number per assembly 11 Weight each, lb 1.7 i
Amendment No. 7 March 31, 1982
TABLE 4.2-1 (Cont'd.)
MECHANICAL DESIGN PARAMETERS (Sheet 2 of 4)
Fuel Assemblies (Cont'd.)
Bottom Spacer Grid Type Leaf spring Material Inconel 625 Number per assembly 1 Weight each, lb (with skirt) 3.2 7
Weight of fuel assembly, lb 1436 Outside dimensions Fuel rod to fuel rod, inches 7.972 x 7.972 Fuel Rod Fuel rod material (sintered pellet) UO 2
Pellet diameter, inches 0.325 Pellet length, inches 0.390 3
Pellet density, g/cm 10.38 3
Pellet theoretical density, g/cm 10.96 Pellet density (% theoretical) 94.75 Stack height density, g/cm 3 10.061 Clad material Zircaloy-4 Clad ID, inches 0.332 Clad OD, (nominal), inches 0.382 Clad thickness, (nominal), inches 0.025 Diametral grap, (cold, nominal), inches 0.007 Active length, inches 150 Plenum length, inches 9.677 Amendment No. 7 March 31, 1982
TABLE 4.2-1 (Cont'd.)
MECHANICAL DESIGN PARAMETERS (Sheet 3 of 4) 1 Control Element Assemblies (CEA) Full Length Part Length Number 76 13 Absorber elements, No. per assy. 7 12 and 4 4 i
Type Cylindrical Cylindrical rods rods Clad material Inconel 625 Inconel 625-Clad thickness, inches 0.035 0.035 Clad OD, inches 0.816 0.816 Diametral gap, inches 0.009 0.009 Elements Poison material B4 C/ Felt metal Inconel/B 4C (A
d and reduced dia. B 4C Poison length, inches 135-1/2/12-1/2 75/16 B4 C Pellet 7 Diameter, inches 0.737/0.674 0.737 Density,%of}heoreticaldensity 73 73 of 2.52 g/cm Weight % boron, minimum 77.5 77.5 Burnable Poison Rod 4
Absorber material Al23 0 -84C Pellet diameter, inches 0.307 l
Pellet length, inches, min 0.500 j Pellet density (% theoretical), min 93 Theoretical density, Al230 , g/cm 3 3.94 7
^
Amendment No. 7 March 31, 1982
IABLE 4.2-1 (Cont'd.)
MECHANICAL DESIGN PARAMETERS (Sheet 4 of 4)
Burnable Poison Rod (Cont'd.)
Theoretical density, B 4C, g/cm 3 2.52 Clad material Zircaloy-4 Clad ID, inches 0.332 Clad 00, inches 0.382 Clad thickness, (noninal), inches 0.025 Diamecral gap, (cold, nominal), inches 0.025 Active length, inches 136.0 Plenum length, inches 11.090 7 O
O Amendment No. 7 March 31, 1982
GRIPPER -
COUPLING I ll g HOLDDOWN
)
SPRING i-l l
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LOCKING SERIAL No.
NUT - J LOCATIONS "J ( T & PLANT ID
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ASSEMBLY p 244 5/8 e PLENUM o SPACER
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4 PELLETS W FELTMETAL i REDUCED DI AMUTER B4C PELLETS 12 1/2 ::_: -
F E LT- UE[
METAL & : SPACER REDUCED :
DIA.B 4C ,
l
- i .jt PE_LLETS f t ' '
Amendment No. 7 11/2 4 p/ March 31, 1982 C-E ' FULL LENGTH CONTROL ELEMENT ASSEMBLY Figure S E P8 / (4 - El.EMENT) 4.2-3
GRIPPER COUPLING ~+/ n I
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.=
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Q REDUCED DIAMETER
- 8 4C PELLETS METAL &
REDUCED DIA.B C STAIN LESS STE E L i - - - - SPACER 1 /2 y y y y ,
Amendment No. 7 March 31, 1982 b%)
C-E i FULL LENGTH CONTROL ELEMENT ASSEMBLY Figure S97!7P8 / (12 - ELEMENT) 4.2-4
I GRIPPER COUPLING %
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a I
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" Amendment No. 7 March 31, 1982
,r y e V V yfgp PART LENGTH CONTROL ELEMENT ASSEMBLY
.25
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Amendment No. 7 March 31, 1982 l
gh FUEL ASSEMBLY 2-
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l Amendment No. 7 March 31, 1982 O
degg FUEL SPACER GRID i
l
UPPER END CAP SPRING SPACER u
~
FUEL PELLETS 150" ACTIVE O = FUELLENcTs FUEL -
CLADDING _
SPACER -
LOWER -
END
^
CAP h
Amendment No. 7 March 31, 1982 Figure E POWER SYSTEMS COMBUSTtON ENGINEERING INC FUEL R0D 4.2-8
l m
UPPER- t3 l END M i CAP SPRING-S PACER -
s POISON PELLETS 136"
- POISON s SHIM LENGTH CLADDING SPACER gER CAP Amendment No. 7 March 31, 1982 O Figure g ggOgR g BURNABLE POISON R0D 4.2-9 CCYBUSDON ENG;NEEAING INC
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O S DENOTES SPARE CEA LOCATIONS 8 Amendment No. 7 March 31, 1982 b
C-E Figure g j / CONTROL ELEMENT ASSEMBLY LOCATIONS 4.2-10 !
t EFFECTIVE PAGE LISTIf(G G CHAPTER 4 APPENDIX 4A Table of Contents 1
'- Page Amendment i
Text Page Amendment
[
4A-1 l
4A-6 4A-7 le l
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O l i
Amendment fio. 7 March 31,1982 I i
- i 1
I l
I l t
l EFFECTIVE PAGE LISTING I C_HAPTER 4 I'
l O .
Table of Contents APPENDIX 4B !
r I !
- Page Amendment ;
! i l i
! 11 1 fii 1 i
1 Text i
Page Amendment i
48-3 j 1 ,
{ 43-4 1 i 4B-5 1 Tables Amendment
}
48-1 l Figures
! Amendment 4B-1 48-2 43-3 1
46-4 48-5 48-6 1 i
48-7 1 l
i l
i9 Amendment No. 7 i
March 31,1982 i
)
i l EFFECTIVE PAGE LISTING i
_C_HAPTER 4 APPENDIX 4C Table of Contents ll Page Amendment l
i 6 l 1 l Text l Page Amendment 4C-1 6 l 4C-2 6
, 4C-3 6 l l
1 Figures Amendment [
9 4C-3 4C-4 6
6 l
I I
1 L i t 1 (
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O Amendmer'. No. 7 March 31, 1982 i ,
(Sheet 1 of 4) l l
EFFECTIVE PAGE LISTIflG CHAPTER 5
{
Table of Contents !
i Page Amendment i i (
i ii 6 l
! iii '
i iv i i
i v Vi vii l viii
' ix 6 l x
! xi 6 i xii i
I j Text I
- Page Amendment 5.1-1 l 5.1-2 5.1-3
! 5.1-4
- 5.1-5 l 5.1-6 i 5.1-7 5.1-8
) 5.1-9 l 5.1-10 i 5.1-11 l 5.1-12 1 5.1-13 l 5.1-14 4
5.1-15 7 I 5.1-16 l 5.1-17 6 1
5.1-18 5.1-19 5.1-20 5.2-1 6
- 5.2-2 5.2-3 5.2-4 3 5.2-5 1 5.2-6 6 4
5.2-5(a) 6 5.2-6(b) 6 l 5.2-6(c) 7 i,
5.2-6(d) 6 I
Amendment tio. 7
- March 31, 1982 i
I
l (Sheet 2 of 4) !
l l
EFFECTIVE PAGE LISTIf4G (Cont'd) .
CHAPTER 5 ,
Text Pye. Amendment 5.2-7
, 5.2-8 5.2-9 5.2-10 5.2-11 5.2-12 6 5.2-13 5.2-14 5.2-15 5.2-16 5.2-17 5.3-1 5.3-2 5.3-3 5.3-4 6 5.3-5 6 5.3-6 5.3-7 5.3-8 5.3-9 5.3-10 5.3-11 5.3-12 5.3-13 5.3-14 5.3-15 l 5.4-1 5.4-2 5.4-3 5.4-4 5.4-5 5.4-6 5.4-7 5.4-8 5.4-9 5.4-10 5.4-11 5.4-12 5.4-13 5.4-14 5.4-15 5.4-16 5.4-17 5.4-18 6 5.4-19 5.4-20 Amendment tio. 7 March 31, 1982
, t (Sheet 3 of 4) l l l i
\
EFFECTIVE PAGE LISTIf4G (Cont'd)
CHAPTER S Text (Cont'd)
Page Amendment 5.4-21 5.4-22 i 5.4-23 6 5.4-24 5.4-25 5.4-26 5.4-27 l
5.4-28
- 5.4-29 7 l 5.4-30 5.4-31 7 5.4-31 (a ) 7 5.4-32 5.4-33 i 5.4-34 5.4-35 l
2 Tables Amendment
- 5.1.1-1 i
5.1.1-2 5.1.1-3 J
5.1.4-1
, 5.1.4-2
! 5.1.4-3
- 5.2-1 i
5.2-2 (Sheets 1-5) 5.2-3 5.3-1
. 5.3-2 5.3-3 5.3-4 5.3-5 5.3-6
! 5.3-7
! 5.3-8 (Sheets 1-3) i 5.4.1-1 1 5.4.2-1
- 5.4.7-1 l 5.4.7-2
- 5.4.7-3 (Sheets 1- 6, 8, 9) j 5.4.7-3 (Sheet 7) 7 5.4.10-1 j
9 5.4.10-2 5.4.13-1 5.4.13-2
- Amendment No. 7 j March 31,1982 i
l
(Sheet 4 of 4)
EFFECTIVE PAGE LISTIrlG (Cont'd)
CHAPTER 5 Figures Amendment 5.1.2-1 7 5.1.2-2 5.1.3-1 6 5.1.3-2 6 5.1.4-1 5.2-1 6 5.2-2 6 5.3-1 5.3-2 i 5.3-3 5.3-4 5.3-5 5.3-6 5.3-7 i 5.4.1-1 j 5.4.2-1 5.4.7-1
, 5.4.7-2 5.4.10-1 5.4.10-2 l 5.4.10-3 5.4.10-4
- 5.4.10-5 l
5.4.13-1 5.4.13-2 5.4.14-1 5.4.14-2 5.4.14-3 5.4.14-4 O
Amendment flo. 7 March 31,1982 l
- 7. N:n-metollic insulction ussd on th] R: actor Ccolant Pressuro i B:undry shall conform to R:gulatory Guida 1.36. Th2 chicrid2 and fluoride content of the non-metallic insulation shall be in the acceptable region as shown in Regulatory Guide 1.36. Tests ,
p shall be made on representative samples of the non-metallic l thermal insulation shall be demineralized or distilled water.
- 8. No contaminants, except for cutting oils, shall be left on any RCS component surface except for the time required to perform and evaluate the particular fabrication or inspection operation.
l 9. Field welding of the RCS piping assemblies and components shall be done in accordance with a welding procedure or procedures by welders qualified to ASME Section IX requirements.
M. System / Component Arrangement
- 1. The pressurizer and surge line shall be located entirely above the reactor coolant loops.
l
- 2. The pressurizer surge line maximum L/D (equivalent) shall be 330 assuming 12-inch Schedulo 160 piping. The L/D equivalent (Le/D) excludes entrance and exit losses but includes the height of'the pressurizer above the hot leg centerline. The equivalent L/D of the height is found by use of:
= SZ i
p where: Z is the height of the pressurizer surge nozzle above (
g the hot leg centerline in feet.
- 3. The maximum acceptable pressure drop through the pressurizer spray line piping is 19 psi at a total flow rate of 375 gpm and at a water temperature of 565F. This requirement is for the piping only, allowance does not have to be made for elevation losses, the valves, or for the entrance and exit nozzles.
- 4. Flooding of the reactor cavity from systems other than the reactor coolant system shall be precluded to prevent immersion of the reactor vessel during operation. This is normally accomplished by routing only reactor coolant system piping inside the reactor cavity, by minimizing drainage paths to the reactor cavity, and/or providing gravity drainage 7 paths out of the cavity below the bottom head of the vessel. The combined reactor cavity and ICI chase may be designed without gravity drainage paths below the hot and/or cold leg pipe penetrations, thereby allowing the reactor cavity to flood in the event of a breach of the reactor coolant pressure boundary inside the cavity.
- 5. The RCS sample piping shall be designed so that the overall transient time from the loop to the containment wall is approxi-mately 90 seconds to permit the decay of short-lived radionuclides (high energy nuclides such as N-16).
- 6. The RCS and main steam piping, MSIV's, primary and secondary Q safety valves and their discharge piping and ADV's shall be arranged and supported such that the limiting loads are not exceeded for normal and relieving conditions.
Amendment No. 7 g j _3 March 31, 1982
- 7. Following a secondary line break, either all steam paths downstream of the MISV's shall be sho.<n to be isolated by their respective control systems following a MSIS actuation signal, or the results of a blowdown through a non-isolated path shall be shown to be acceptable. An acceptable maximum steam flow from a nongi solated steam path is 10% of the main steam rate (MSR) (1.9 x 10 lb/hr
@ 1000 psia saturated steam). It is not required that the control systems for downstream valves nor the downstream valves themselves be designed to IEEE 279 and IEEE 308 or ASME Code,Section III and Seismic Category I criteria respectively.
- 8. The MSIV's for each steam generator shall be arrangea such that a maximum of 2000 cubic feet (total for two steam lines per steam generator) is contained in the piping between each steam generator and its associated MSIV's. This volume shall include all lines off of the main steam line up to their isolation valves.
- 9. The main steam lines shall be arranged such that a maximum of 14,000 cubic feet is contained between the MSIV's and the turbine stop valves. This volume shall include all lines off of the main steam line up to their isolation valves.
- 10. The main steam lines shall be headered together prior to the turbine stop valves but not upstream of the MSIV's, and a cross-connect line shall be provided which will maintain steam generator pressure differences within the following limits for all nonnal and upset conditions.
- a. 0-15% power operation pressure difference to be 1 psi.
- b. 15-100% power operation pressure difference to be 3 psi.
- 11. No automatically actuated valves shall be located upstream of the MSIV's except as required for supply to steam driven emergency feedwater pumps. Provisions shall be made to prevent blowdown of both steam generators through the emergency feedwater supply headers in the event of a steamfine break. The maximum allowable flow rate per valve is 1.9 x 10 lb/hr.
- 12. There shall be no isolation valves in the main steam lines between the steam generators and the secondary relief valves.
- 13. The main steam safety valves shall be arranged such that any condensate in the line between the safety valves and main steam line drains back to the main steam line.
- 14. All valves in the main steam line outside of containment up to and including the MSIV's shall be located as close as practical to the containment wall .
- 15. A 90 or 45 elbow facing downward shall be attached to each feedwater nozzle. Such a precaution will aid in the prevention of water hammer.
5.1-16
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5.2.2.10.2.2 Provision for Overpressure Protection During heatup, RCS pressure is maintained below the maximum pressure for SCS operation until RCS cold leg temperature exceegs, the applicable P-T operating curve temperature corresponding to 2500 lb/in. a (see Figure 3.4-2 in the Technical Specifications). If SI-651 and 653 or SI-652 and 654 SCS suction isolation valves are open and RCS pressure exceeds the maximum pressure for SCS operation, an alarm will notify the operator that a pressurization transient is occurring during low temperature conditions. Either SCS relief valve will terminate inadvertent pressure transients occurring during RCS temperature below ghe applicable P-T operating curve temperature corresponding to 2500 lb/in. a. Above the maximum LTOP temperature, overpressure protection is provided by the pressurizer safety valves when the SCS relief valve is isolated from the RCS. During cooldown whenever RCS cold leg temperature is below the applicable temperature for LTOP, the SCS relief valves provide the necessary protection. ' If the SCS is not aligned to the RCS before cold leg temperature is decreased to the maximum temperature requiring LTOP, an alarm will notify the operator 7 l to open the SCS suction isolation valves (SI-651, 652, 653, 654). The maximum temperature requiring LTOP is based upon the evaluation of the applicable P-T curves. However, the SCS can not be aligned to the RCS until the pressure is below the maximum pressure allowing SCS operation (see paragraph 5.4.7.2.3, item a.2). These LTOP conditions are within the SCS operating range. Technical Specifica-tion section 16.3/4.4.9.3 requires the SCS suction line isolation valves to be
/n i
i open when operating in the LTOP mode. Also, this Technical Specificatien l V ensures that appropriate action is taken if one or more SCS relief valves are out of service during the LTOP mode of operation. Either SCS relief valve will provide sufficient relief capacity to prevent any pressure transient from exceeding the isolation interlock setpoint (See figures 5.2-1 and 5.2-2). 5.2.2.10.2.3 Equipment Parameters The SCS relief valves are spring-loaded (bellows) liquid relief valves with sufficient capacity to mitigate the most limiting overpressurization event. l Pertinent valve parameters are as follows: Parameter Setpoint 450 lb/in.2 a Accumulation 10% Capacity 4000 (@ 10% acc) gal / min ) Since each SCS relief valve is a self actuating spring-loaded liquid relief . valve, control circuitry is not required. The valve will open when RCS pressure exceeds its setpoint. t l
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Amendment No. 7 March 31,1982 5.2-6c
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The SCS relief valves are sized, based on an inadvertent safety injection actuation signal (SIAS) with full pressurizer heaters operating from a water-solid condition. The SIAS assumes simultaneous operation of two HPSI pumps and three charging pumps with letdown isolated. The resulting flow capacity requirement for water is 4000 gpm. The analysis in Section 5.2.2.10.2.1 assumed that either SCS relief valve relieved water at this rate. The design relief capacity of each of two SCS relief valves (shown in P&ID Figure 6.3.2-1B) as supplied by the valve manufacturer is 5180 gpm. This design relief capacity exceeds the minimum required relief capacity of 4000 gpm with sufficient margin in relieving capacity for even the worst transient. The SCS relief valves are Safety Class 2, designed to Section III of the ASME Code. 5.2.2.10.2.4 Administrative Controls 6 Administrative controls necessary to implement the LTOP provisions are limited to those controls that open the SCS isolation valves. Before entering the low temperature region for which overpressure protection is necessary, RCS pressure is decreased to below the maximum pressure required for SCS operation. Once the SCS is aligned, no further specific administrative procedural controls are needed to ensure proper overpressure protection. The SCS will remain aligned whenever the RCS is at low temperatures and the reactor vessel head is secured. As designated in Table 7.5-2, indication of SCS isolation valve position is provided. 5.2.3 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS 5.2.3.1 Ma terialJecifica tion A list of specifications for the principal ferritic materials, austenitic stainless steels, bolting and weld materials, which are part of the reactor coolant pressure boundary is given in Table 5.2-2. Studies have shown that the irradiation induced mechanical property changes of SA-533B materials can depend significantly upon the amount of residial elements present in the compositions, namely; copper, phosphorous, anc vanadium. It has also been found that residual sulfur affects the initial toughness of SA-533B materials. Specific controls are placed on the residual chemistry of reactor vessel plates and the as-depositied welds used to join these plates to limit the maximum predicted increase in the reference temperature (RT, , which is discussed in Section 5.3.1.6) and to limit the extent of the rbtor vessel beltline. The beltline is defined by Appendix G of 10CFR50. 6 Amendrrent No. 6 O November 20, 1981 5.2-6d
- 5. Pumps Used During Shutdown Cooling w The LPSI pumps are used as part of the SCS. During shutdown cooling, these pumps take suction from the reactor hot leg pipes and discharge through the shutdown cooling heat exchangers. The flow is then returned to the RCS through the LPSI header to the four cold legs. One LPSI pump is aligned to each shutdown cooling heat exchanger. At the start of shutdown cooling, both of the LPSI pumps are in service. When the RCS temperature is below 200 F, the containment spray pumps may be realigned and started to provide additional flow through the heat exchangers. The LPSI pumps are described in Section 6.3.2.2.2.
5.4.7.2.3 Overpressure Prevention
- a. Overpressurization of the SCS by the RCS is prevented in the following ways
- i
- 1. The shutdown cooling suction isolation valves (SI-651, 652, 653, and 654) are powered by four independent power supplies such that a fault in one power supply or valve will neither line up the RCS to either of the two SCS trains inadvertently nor prevent the initiation of shutdown cooling with at least one train when pressure permits.
- 2. Interlocks associated with the shutdown cooling suction isolation valves prevent the valves from being opened if RCS pressure exceeds 400 psia, and close these valves automatically if RCS l pressure should risa above the accumulation pressure of the shutdown cooling suction line reliefs valves. This value is 700 l7 psia. The instrumentation and controls which implement this are I discussed in Section 7.6.
1
- 3. The SCS suction valves inside the containment are designed for full RCS pressure with the second valve forming the pressure boundary and class change.
- 4. Alarms on SI-651, 652, 653 and 654 annunciate when the shutdown cooling system suction isolation valves are not fully closed.
Also, if SI-651 and 653 or SI-652 and 654 valves are open and RCS pressure exceeds the maximum pressure for SCS operation, an 7 alarm will notify the operator that a pressurization transient is occurring during low temperature conditions.
- 5. Relief valves are provided as discussed in Section 5.4.7.2.2.
The effects of inadvertent operation are discussed in Table 5.4.7-3. 5.4.7.2.4 Applicable Codes and Classifications
- a. The SCS is a Safety Class 2 System, except for that portion discussed in b. below, which is Safety Class 1.
- b. The piping and valves from the RCS up to and including SI-653 and 654
( are designed to ASME B&PVC Section III, Class 1. Amendment flo. 7 March 31, 1982 5.4-29
- c. The piping, valves, and components of the SCS, with the exception of those in Section 5.4.7.2.4 b. are designed to ASME B&PVC Section III, Class 2.
- d. The component cooling water side of the shutdown cooling heat exchanger is designed to ASME B&PVC Section III, Class 3.
- e. The power operated valves are designed to the applicable IEEE Standards.
- f. The SCS is a Seismic Category 1 System.
5.4.7.2.5 System Reliability Considerations The SCS is designed to perform its design function assuming a single failure, as described in Section 5.4.7.1.2. To assure availability of the SCS when required, redundant components and power supplies are utilized. The RCS can be brought to refueling temperature utilizing one of the two redundant SCS trains. However, with the design heat load, the cooldown would be considerably longer than the specified 27-1/2 hour time period. A loss of instrument air to the shutdown cooling system will not result in a loss of cooling ability. Inadvertent overpressurization of the SCS is precluded by the use of pressure relief valves and interlocks installed on the shutdown cooling suction line isolation valves and safety injection tank isolation valves (see Section 7.6 and 5.4.7.2.3). The instrumentation, control, and electric equipment pertaining to the SCS was designed to applicable portions of IEEE Standards 279 and 308. In addition to normal offsite power sources, physically and electrically separated and redundant emergency power supply systems are provided to power safety-related components. See Chapter 8 for further discussion. Since the SCS is essential for a safe shutdown of the reactor, it is a Seismic Category I system and designed to remain functional in the event of a design basis earthquake. For long-term performance of the SCS without degradation due to corrosion, only materials compatible with the pumped fluid are used. Environmental conditions are specified for system components to ensure acceptable performance in normal and applicable accident environments (see Section 3.11). In the event of a limited leakage passive failure in one train of the SCS, continued core cooling is assured by the two independent train design of the SCS. Make-up of the leakage is provided by the manual alignment of the O 5.4-30
SIS to the refueling water tank or by opening the Safety Injection Tank [ isolation valves. The affected SCS train can then be isolated and core cooling continued with the other train. A limited leakage passive failure is defined as the failure of a pump seal or valve packing, whichever is greater. The maximum leakage is expected to be from a failed LPSI pump seal. This leakage to the pump compartment will normally drain to the room sump. From there it is pumped to the water management system. The sump pumps in each room will handle expected amounts of ieakage. If leakages are greater than the sump pump capacity, the room will be isolated. 5.4.7.2.6 Manual Actions
- 1. Plant Cooldown Plant cooldown is the series of manual operations which bring the reactor from hot shutdown to cold shutdown. Cooldown to approximately 350 F is accomplished by releasing steam from the secondary side of the steam generators. When the RCS pressure falls below 2150 psia, the Safety Injection Actuation Signal (SIAS) setpoint can be manually decreased as discussed in Section 7.2.1.1.1.6. When RCS pressure reaches 625 psig, the safety injection tank pressure is reduced to 400 psig. When RCS pressure reaches 400 psig, the safety injection tank isolation valves are closed.
When RCS temperature and pressure decrease below 350 F and the maximum pressure for SCS operation, the SCS may be used. If the SCS is not aligned to the RCS before cold leg temperature is reduced to below the maximum RCS cold leg temperature requiring LTOP, an alarm will notify the operator to open the SCS isolation valves (SI-651, 652, 653, 654). The maximum temperature requiring LTOP is based upon the evaluation of the applicable P-T curves. This operator action requires that the RCS be depressurized to below the maximum pressure for SCS operation, in 7 order to clear the permissive SCS interlock (see paragraph 5.4.7.2.3, item a.2). Interlocks associated with the six valves on the two SCS suction lines prevent overpressurization of the SCS. See Section 7.6 and 5.4.7.2.3 for details. Also, if SI-651 and 653 or Si-652 and 654 SCS suction isolation valves are open and RCS pi;ssure exceeds the maximum pressure for SCS operation, an alarm will notify the operator that a pressurization transient is occurring during low temperature conditions. Shutdown cooling is initiated using only the LPSI pumps (LPSIP), with the CSS lined up foi automatic initiation of spray, bypassing the shutdown cooling heat exchanger. The SCS is warmed up and placed in operation as follows (refer to Figures 6.3.2-1 A,1B, II, lJ,1K, and ll):
- a. The containment spray isolation valves for the shutdown cooling heat exchangers (SI-684*, 687*, 689, 695) are shut.
V b. The containment spray valves bypassing the shutdown heat exchangers (SI-688*,693) are opened. Amendment No. 7 5.4-31 March 31,1982
- c. The LPSI pump minimum flow recirculation isolation valves (SI-668,669*) are shut.
- d. The LPSI pump suction valves (SI-683*, 692) from the RWT and containment sump are shut. !
- e. The shutdown cooling suction line isolation valves (SI-651*, 652, l 653*,654,655*,656) in the two sr tion lines are opened.
O i 1 Amendment No l Ma rch 31, 19e , 5.4-31a
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4 i I i f. The crossover valves between the LPSI pump discharge and the shutdown cooling heat exchangers (SI-685*, 694) are opened.
- g. The crossover valves between the shutdown cooling heat exchanger outlet and the LPSI header (SI-686*, 696) are opened and the
; shutdown cooling throttle valves (SI-657*, 658) are cracked open.
- h. The SCS warmup line isolation valves (SI-690, 691*) are opened and the LPSI pumps are started to induce recirculation flow through the SCS (flow is limited to 5000 gpm per pump).
j i. Once flow has been induced in the SCS, the LPSI isolation valves (SI-615,625,635*,645*) are cracked open to allow a small i amount of flow from the RCS to heat up SCS valves and piping. l 4 j. The LPSI header isolation valves (SI-615, 625, 635*, 645*) are
! then gradually opened, while the warmup line isolation valves (SI-690,691*) are gradually closed to maintain a constant flow l of 5000 gpm per pump. When the LPSI header isolation valves (SI-615,625,635*,645*) are open to their preset positions and the ; SCS warmup line isolation valves (SI-690, 691*) are closed, the SCS is aligned in its operating mode, i k. The shutdown cooling throttle valves (SI-657*, 658) and the SCS I
bypass flow control valves (SI-306*, 307) are adjusted as necessary to maintain the RCS cooldown rate at 75 F/ hour or less, at a SCS flow of 5000 gpm through each heat exchanger. When reactor coolant temperature decreases below 200 F (typically 170 F), the containment spray pumps are aligned to provide additional shutdown cooling flow. The SCS is realigned to the following line-up (refer to Figure 6.3.2-1A):
- a. The containment spray pump suction valves (SI-104, 105*) from the RWT and containment sump are closed.
- b. The containment spray pump minimum flow recirculation line .
isolation valves (SI-664*, 665) are shut. I
- c. The containment spray bypass around the shutdown cooling heat exchanger valves (SI-688*,693) are shut.
- d. The containment spray pump suction valves (SI-184*,185) from shutdown cooling suction lines are opened.
, e. The containment spray pump discharge to the shutdown cooling heat ! exchangervalves(SI-684*,689) are opened.
! The containment spray pump discharge valves (SI-678*, 679) are f.
opened to the position determined by preoperational testing.
'O 5.4-32 , . . , . . . - , , - - . . - ~ - ~~, .- , . . - - - - - - , - - - - - - - , , . , - - , , , - - - - , - - -,-n- - -- -, .
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O O O ! TABLE 5.4.7-3 (Cont.) (Sheet 7 of 9) l i, SHUTDOW4 COOLING SYSTEM FMEA I ( l Symptoms and Local Effects Inherent Remarks and I No. Name Failure Mode Cause Including Dependent Failures Method of Detection
- Compensating Provision Other Effects l 23. SCS Stop a) Fails open Elect. Malf., None Position indication The redundant series Interlocks asso-l Valves for Suc- Mech. binding in control room, valve ensures that ciated with the tion Line Periodic testing SCS is protected from valves prevent SI-651 nonnal RCS pressure overpressurization.
51-652 during power operation These interlocks SI-653 prevent the valves SI-654 in the suction line of the SCS from being opened if RCS pressure exceeds 400 psia. These valves auto-ratically close if RCS pressure should rise above the accumulation pressure of the SCS suction line relief valves. This pressure is 700 psia. l7 b) Fails Elect. Malf., Prevention of decay heat re- Position indication Redundant shutdown cool-closed Mech. binding moval from core via one SCS in control room, ing subsystem assures subsystem during normal shut- Periodic testing adequate cooling although down cooling or long tenn cooling time will be ex-cooling following a small LOCA tended.
- 24. SI Tank Isola- a) Fails open Elect. Malf., Unable to isolate one SI tank Position indication None required During shutdown tion Valves Mech. binding from the RCS. in control room, cooling these SI-614 Periodic testing valves are closed.
SI-624 However, if a LOCA SI-634 occurs a SIAS will SI-644 automatically open these valves. SCS interlock prevents initiation of shut-down cooling unless SIT pressure is re-duced to a safe , level. SIT press-ure can be lowered by bleeding off nitrogen. Amendment No. 7 March 31, 1982
TABLE 5.4.7-3 (Cont.) (Sheet 8 of 9) SHUTDCLN C00_t I';G SYSTEM FPEA Inherent Remarks and Symptons and Local Effects Other Effects Including Dependent failures Method of Detection
- Compensating Provision No. Name Failure Made Cause No effect during shutdown Valve position indi- None required b) Fails Elect. Malf.,
Mech. binding cooling cations in control closed room, Periodic testing Valve position indi- Ncne required during Valve is normally a) Fails open Elect. Malf., No effect on shutdown cooling
- 25. Shutdown Cool- cation in control shutdown cooling locked closed in ing Line Isola- Mech, binding control room room, Periodic operations tica Valves testing SI-655 SI-656 Inability to align one shut- Valve position indi- Redundant shutdown cool-b) Fails Elect. Malf.,
down cooling subsystem for cation in control ing subsystem closed Mech, binding shutdown cooling room, Periodic testing Periodic testing Adjacent valve (SI-204, Valve is nomally
- 26. PCPS Crossover a) Fails oper. Mech. binding None SI-443,SI-450,51-454) locked closed at Valves to SCS provides back-up isola- valve 51-256 tion.
SI-442 51-455 51-458 Mech. binding None during shutdown cooling. See customer's SAR PCPS connection with re- One of the shut-b) Fails Isolation of the spent fuel for description of dundant SCCHX. down cooling HX closed may be aligned to pool cooling system from one PCPS. Periodic train of the SCS prevents use testing the PCPS when no longer needed to of one SDCHX to assist in maintain reactor cooling the spent fuel pool coolant at re-i ' when it contains 1-1/3 cores. fueling tempera-ture Contaminants Effective loss of one shutdown Low flow indications Redundant shutdown cool- Periodic sampling
- 27. Shutdown Cool- a) One line cooling subsystem from F-307 or F-306, ing subsystem will monitor build-ing Line clogs Periodic testing up of contaminants Seal failure Release of coolant and radio- Local leak detec- The leak can be isolated b) Limited activity outside of contain- tion. See customer's without affecting the Leakage in redundant subsystem ment. SAR one train Inability to control cool- Comparison with Redundant indicator
- 28. Flow Indicator false indi- Elect. Malf. redundant indicator, F-306, F-307 cation down rate in affected train.
with all other pro-F-338, F-348 cess instrumentation and valve position indications consist-ent. O O _ O
i } l EFFECTIVE PAGE LISTING i G CHAPTER 5 APPENDIX SA q Table of Contents Page Amendment a $ Abstract
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EFFECTIVE PAGE LISTING CHAPTER 5 APPENDIX SC Table of Contents Page Amendment Abstract i ' 11 111 Text i Page Amendment l l SC-1 j SC-2 : SC-3 Tables Amendment 5C-1 l l l Figures Amendment SC-1 SC-2 . SC-3 SC-4 i i l . l i 1O Amendment No. 7 March 31,1982
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. x xi 1 xii xiii 4 l xiv I xv xvi xvii 4 xvii (a) 4 xviii xix xx , xxi l xxii i xxiii ! xxiv i ! Text I i j Page Amendment 6.1-1 i 6.1-2 ) 6.1-3 ! 6.1-4
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(Sheet 2 of 6) EFFECTIVE PAGE LISTING (Cont'd) C_HAPTER 6 Text (Cont'd) Page_ Amendment _ 6.2-16 6.2-17 6.2-18 6.2-19 6.2-20 4 6.2-21 4 6.2-22 4 6.2-23 6.2-24 6.2-25 6.2-26 6.2-27 6.2-28 6.2-29 6.2-30 6.3-1 6.3-2 7 6.3-3 6 6.3-3(a) 6 6.3-4 6.3-5 6.3-6 6.3-7 6.3-8 6 6.3-9 6.3-10 6.3-11 6.3-12 6.3-13 7 6.3-14 6.3-15 6.3-16 6 6.3-17 6.3-18 6.3-19 6.3-20 6.3-21 6.3-22 4 6.3-23 6.3-24 4 6.2-25 4 6.3-26 6.3-27 4 6.3-28 4 6.3-29 6.3-30 Amendment No. 7 March 31,1982
l-l (Sheet 3 of 6) l l l EFFECTIVE PAGE LISTING (Cont'd) j 1 l CHAPTER 6 } Text (Cont'd) 1 Pale Amendment ( 6.3-31 6.3-32 4 I 6.3-33 4 ; i 6.3-33(a) 4
! 6.3-34 4
! 6.3-35 4 6.3-36 6.3-37 I j 6.3-38 l j 6.3-39 j 6.3-40 i 6.3-40(a) 4 6.3-40(b) 4 6.3-41 i l , 6.3-42 1 l 6.3-43 l i 6.3-44 l 1 6.4-1 ! _ Tables l Amendment ! i 6.1-1 (Sheets 1 and 2) - l 6.1-2 6.1-3 6.1-4 , 6.2.1-1 (Sheets 1-3) l 6.2.1-2 (Sheets 1-14) i 6.2.1-3 (Sheets 1-11) 6.2.1-4 (Sheets 1-11) 6.2.1-5 (Sheets 1-11) 6.2.1-6 (Sheets 1-13) 6.2.1-7 (Sheets 1-13) ! 6.2.1-8 (Sheets 1-13) l 6.2.1-9 (Sheets 1-13) 6.2.1-10 (Sheets 1-7) l 6.2.1-11 (Sheets 1-7) l 6.2.1-12 (Sheets 1-9) 6.2.1-13 (Sheets 1-7) 6.2.1-14 (Sheets 1-9) 6.2.1-15 (Sheets 1-7) i 6.2.1-16 (Sheets 1-9) ' 6.2.1-17 (Sheets 1-7) 6.2.1-18 (Sheets 1-9) G 6.2.1-19 (Sheets 1-7) 6.2.1-20 (Sheets 1-9) ' Amendment No. 7 ! March 31,1982 l l
(Sheet 4 of 6) i EFFECTIVE PAGE LISTING (Cont'd) Cl: APTER 6 Tables (Cont'd) Amendment 6.2.1-21 6.2.1-22 6.2.1-23 (Sheets 1 and 2) 6.2.1-24 6.2.1-25A (Sheets 1-3) 6.2.1-258 (Sheets 1-3) 6.2.1-26A (Sheets 1-3) 5.2.1-268 (Sheets 1-3) t.2.1-27A (Sheets 1-3) 6.2.1-27B (Sheets 1-3) 6.2.1-28A (Sheets 1-3) 6.2.1-288 (Sheets 1-3) 6.2.1-29A (Sheets 1-3) ! 6.2.1-29B (Sheets 1-3) 6.2.1-30 (Sheets 1-3) 6.2.1-31A (Sheets 1-3) . l 6.2.1-318 (Sheets 1-3) i 6.2.1-32A (Sheets 1-3) l 6.2.1-32B (Sheets 1-3) 6.2.1-33A (Sheets 1-3) [ i 6.2.1-33B (Sheets 1-3) , 6.2.1-34 (Sheets 1-3) ' 6.2.1-35A (Sheets 1 and 2) 6.2.1-35B (Sheets 1 and 2) 6.2.1-36 6.2.1-37 (Sheets 1-3) 4 6.2.1-38 6.2.4-1 (Sheets 1-3) (Sheet 4) 7 (Sheet 5) 6.3.2-1 (Sheets 1 and 2) 6.3.2-2 (Sheets 1-10) 6.3.2-3 (Sheets 1 and 2) 6.3.2-4 (Sheets a-e) 6.3.2-5 (Sheets a and b) 6.3.2-6 (Sheets 1-6) 6.3.3.2-1 4 6.3.3.2-2 4 6.3.3.2-3 6.3.3.2-4 4 6.3.3.2-5 4 t 6.3.3.2-6 6.3.3.3-1 6.3.3.3-2 4 , 6.3.3.3-3 6.3.3.3-4 6.3.3.3-5 4 6.3.3.3-6 4 Amendment No. 7 March 31., 1982 .
(Sheet 5 of 6) EFFECTIVE PAGE LISTING (Cont'd)
- CHAPTER 6 k.) Tables (Cont'd)
Amendment 6.3.3.5-1 (Sheets 1 and 2) 6.3.3.5-2 (Sheets 1 and 2) 6.3.3.5-3 6.3.3.6-1 6.3.3.7-1 1 Figures Amendment 6.2.1-1 (Sheets 1 and 2) 6.2.1-2 6.2.1-3
- 6. 2.1 -4 6.2.1-5 6.2.1-6 6.2.1-7 6.2.1-8 6.2.1-9 6.2.1-10 6.2.1-11 (Sheets 1 and 2)
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(Sheet 6 of 6) EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 6 Figures (Cont'd) Amendment 6.3.3.2 (Sheets 7A-7H) 4 (Sheets 8A-8G) (Sheet 8H) 4 l (Sheets 9A-9G) l (Sheet 9H) 4 (Sheets 10 and 11) 4 6.3.3.3 (Sheets lA-lH) l (Sheets 2A-2H) (Sheets 3A-3E) l (Sheet 3F) 4 (Sheets 3G and 3H) I (Sheets 4A-4H) (Sheets SA-5H) (Sheets 6A-6H) (Sheet 7) 6.3.3.4-1 4
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6.3.3.4-2 6.3.3.4-3 ; 6.3.3.4-4 6.3.3.4-5 4 6.3.3.4-6 6.3.3.5 (Sheets lA-lF) l 1 l I I l 1 l l l l e Amendment No. 7 March 31, 1982 ,
l k 1 I 1 ! TABLE 6.2.4-1 (Cont'd.) (Sheet 3 of 5) - CONTAINMENT ISOLATION SYSTEM ; Valve Location Penetration Applicable Line(5) ESF Valve III Valve Relative To Type C(8) Valve I7) l Number GDC System (4) Size (in) Function Arrangement Number Containment Leakage Test Type i 28 SS SCS 16 No 5 SI-691 Outside Yes Globe ! SI-655 Outside Yes Gate , SI-653 Inside Yes Gate 29 55 SIS 2 No 6 SI-463 Outside Yes Globe i SI-682 Inside Yes Globe , f 40 55 CVCS 2 No 7 CH-523 Outside Yes Globe i CH-516 Inside Yes Globe 41 55/56 CVCS 2-1/2 No 8 CH-524 Outside Yes Globe [ i CH-431 Inside Yes Check i CH-433 Inside Yes Check CH-854 Outside Yes Globe CH-393 Inside Yes Globe i 43 55 CVCS 1 No 9 CH-505 Outside Yes Globe CH-506 Inside Yes Globe 1 44 55 CVCS 3 No 10 CH-560 Inside Yes Globe ! CH-561 Outside Yes Globe ' 45 55 CVCS 1-1/2 No 11 CH-494 Inside Yes Check CH-580 Outside Yes Globe 57 55 CVCS 1-1/2 No 12 CH-255 Outside Yes Globe , CH-835 Inside Yes Check i i i
l TABLE 6.2.4-1 (Cont'd.) (Sheet 4 of 5) CONTAINMENT ISOLATION SYSTEM Vaive Position Primary (2) Secondary (2) ESF(3) Closure Penetration Applicable g) Valve Actuation Actuation Shut- Post- Actuation Time Power Number GDC System Operator Mode Mode Normal down Accident Failure Signal (Sec) Source 28 55 SCS Motor R M C 0 or C 0 or C FAI None 30 EA Motor R M C 0 0 or C FAI None 80 EA Motor R R C 0 0 or C FAI None 80 EC 29 55 SIS None M M C 0 or C C FAI None N.A. N.A. Air A R C 0 or C ~ FC SIAS 5 EA 40 55 CVCS Air A R, M 0 C C FC CIA 5/SIAS 5 EB Air A R 0 C C FC CIAS 5 EA 41 55/56 CVCS Motor R M 0 0 0 FAI None 5 EB None A A C 0 or C 0 or C 0 or C N.A. None N.A. N. A. l7 None A A 0 0 or C N.A. None N.A. N.A. Hand M M C C C N.A. None N.A. N.A. Hand M M C C C N.A. None N.A. N.A. 43 55 CVCS Air A R,M 0 0 or C C FC CIAS 5 EB Air A R 0 0 or C C FC CIAS 5 EA l , 44 55 CVCS Air A R 0 or C C C FC CIAS 5 ' EA Air A R, M 0 or C C C FC CIAS 5 EB 45 55 CVCS None A A 0 or C N.A. None N.A. C C N.A. Air A R, M 0 or C C C FC CIAS 5 EA 57 55 CVCS Motor R M 0 0 0 or C FAI None P, 5 EA None A A 0 0 0 or C N.A. None N.A. N.A. l I I l l Amendment No. 7 March 31,1982 E._____________ 9 _ . _ _ _ __ __ ____ __ 9 __ _ G__ _______
fg 6.3 EMERGENCY CORE COOLING SYSTEM
\ 1 V 6.3.1 DESIGN BASES 6.3.1.1 Summary Description The Emergency Core Cooling System (ECCS) or Safety Injection System (SIS) is designed to provide core cooling in the unlikely event of a Loss-of-Coolant Accident (LOCA). The ECCS prevents significant alteration of core geometry, Precludes fuel melting, limits the cladding metal-water reaction, removes the energy generated in the core and maintains the core subcritical during the extended period of time following a LOCA.
The SIS accomplishes these functional requirements by use of redundant active and passive injection subsystems. The active portion of the SIS consists of high and low pressure Safety Injection pumps and associated valves. The passive portion consists of pressurized Safety Injection Tanks (SIT). In addition, the Safety Injection System functions to inject borated water into the Reactor Coolant System to add negative reactivity to the core in the unlikely event of a steam line rupture. Safety Injection is also initiated in the event of a Steam Generator Tube Rupture or a CEA Ejection incident. The system is actuated automatically. 6.3.1.2 Criteria V 6.3.1.2.1 Functional Design Bases
- a. The shutoff head and flowrates of the High Pressure Safety Injection Pump (HPSIP) and Low Pressure Safety Injection Pump (LPSIP) were selected to insure that adequate flow is delivered to the RCS to accomplish the functional requirements of Section 6.3.1.1.
- b. Storage of fluid for the SIS is accomplished by the Refueling Water Tank (RWT) which contains a sufficient amount of borated fluid to accomplish the functional requirements of Section 6.3.1.1.
- c. The SIS is designed such that equal flows are delivered to each injection point, regardless of break location.
6.3.1.2.2 Reliability Design Bases
- a. The safety function defined in Section 6.3.1.1 can be accomplished assuming the failure of a single active component during the injection mode of operation or a single active or limited leakage passive failure of a component during the recirculation mode of operation. For failure analysis, all necessary supporting systems including the onsite elec-trical power system are considered a part of the Safety Injection System. A Failure Modes and Effects Analysis is presented in Table 6.3.2-2.
O_ 6.3-1
- b. Components of the Safety Injection System and instrumentation which must operate following a LOCA are designed to operate in the environment of Section 3.11.
- c. The Safety Injection System is designed to perform the functions of Section 6.3.1.1 for the entire duration of a LOCA.
- d. The Safety Injection System is designed to Seismic Category I require-ments.
6.3.1.3 Interface Requirements Below are detailed the interface requirements that the SIS places on certain aspects of the BOP, listed by categories. In addition, applicable GDC and Regulatory Guides, which C-E utilizes in its design of the SIS, are presented. These GDC and Regulatory Guides are listed only to show what C-E considers to be relevant, and are not imposed as interface requirements, unless specifically called out as such in a particular interface requirement. Relevant GDC - 1, 2, 3, 4, 13, 18, 20, 21, 22, 23, 35, 36, 37, 54, 57 Relevant Reg. Guides - 1.1, 1.26, 1.28, 1.29, 1.31, 1.36, 1.38, 1.44, 1.46, 1.48, 1.53, 1.64, 1.68, 1.75, 1.79, 1.82 A. Power
- 1. The Safety Injection System pumps and valves shall be capable of being powered from the plant turbine generator (onsite power 7 source), and/or plant startup power source (offsite power),
and the emergency generators (emergency power).
- 2. Power connections shall be through a minimum of two independent buses so that in the event of a LOCA in conjunction with a single failure in the electrical supply, the flow from one high-pressure and one low-pressure safety injection train shall be available for core protection.
- 3. Each electrical bus of the above shall be connected to one high-pressure safety injection pump and associated valves and one low-pressure safety injection pump and associated valves.
- 4. Each emergency generator and the automatic sequencers necessary for generator loading shall be designed such that flow to the core is attained within a maximum of 30 seconds. The emergency generator interface requirements are described in Section 8.3.1 l and shall be complied with. I 1
- 5. Instrument power supplies shall be provided as stated in Chapter 8.
- 6. The SIS hot leg injection valves shall be powered such that a j single electrical failure cannot cause spurious initiation of hot leg injection flow through either hot leg injection line, nor l
Amendment No. 7 March 31, 1982 6.3-2
The high-pressure safety injection pumps are sized such that one HPSI pump (after consideration of spillage directly out the break) will supply adequate water to the core to match decay heat boiloff rates soon enough to minimize core uncovery and allow small break LOCA's to meet the performance criteria of 10CFR50.46. A typical pump characteristic curve is shown in Figure 6.3.2-3. The effectiveness of the pump during a steam line break is also analyzed to assure that the pumps are adequately sized. Mechanical shaft seals are used and are provided with leakoffs which collect any leakage past the seals. The seals are designed for operation with a pumped fluid temperature of 350 F.
, The pump motors are specified to have the capability of starting and accel-i erating the driven equipment, under load, to design point running speed within 5 seconds based on an initial voltage of 75% of the rated voltage at the motor terminals, increasing linearly with time to 90% voltage in the first 2 seconds, and increasing to 100% voltage in the next 2 seconds.
f The pumps are provided with drain and flushing connections to permit reduction of radiation before maintenance. The pressure containing parts of the pump are stainless steel with internals selected for compatibility with boric acid solutions. The materials selected are analyzed to ensure that differential , expansion during design transients can be accommodated. The pumps are provided with minimum flow protection to prevent damage resulting from operation against a close discharge. Also, individual HPSI 7 pump ultrasonic flow meters provide low flow alarming. s The design temperature is based on the saturation temperature of the reactor coolant at the containment design pressure plus a design tolerance. The design pressure for the high pressure pumps is based on the shutoff head plus maximum containment pressure plus a design tolerance. The High-Pressure Pump Data is summarized in Table 6.3.2-1. 6.3.2.2.4 Piping l Piping is specified to deliver borated safety injection water from the i safety injection tanks and from the refueling water tank via the safety injection pumps, to the safety injection nozzles in the RCS. The major piping sections are (refer to Figures 6.3.2-1A & IB):
- a. From each safety injection tank to its respective RCS cold leg safety injection nozzle;
- b. Redundant piping from the refueling water tank and containment sump to the suction of the high- and low-pressure safety injection pumps;
- c. Redundant piping from the high-pressure safety injection pumps discharge to redundant high-pressure injection headers each of which serves the four safety injection nozzles on the cold legs and one nozzle on each shutdown cooling suction line; i
Amendment No. 7 March 31, 1982 6.3-13 I
- d. Redundant piping from the low pressure safety injection pump discharge to each low pressure injection header which serves two of the four safety injection nozzles.
The Safety Injection System piping is fabricated of austenitic stainless steel and is designed to ASME Code Section III. Flexibility and seismic loading analyses are performed by each Applicant to confirm the structural adequacy of the system piping. 6.3.2.2.5 Valves The location, type and size, type of operator, position (during the normal operating mode of the plant) and failure position of the SIS valves, is shown in Figures 6.3.2-1A and 6.3.2-1B. Pressure design rating and code design classification are also shown. A valve list is given in Table 6.3.2-6.
- a. Relief Valves Protection against overpressure of components within the Safety Injection System is provided by conservative design of the system piping, appropriate valving between high pressure sources and low-pressure piping, and by relief valves. All lines within the high- and low pressure systems from the RCS up to and including the safety injection valves are designed for full Reactor Coolant System pressure. In addition, the high pressure header to which the charging pumps discharge is designed for full Reactor Coolant System pressure up to and including the header check valve. Relief valves are provided as required by applicable codes. All relief valves are of the totally enclosed, pressure tight-type with suitable provisions for gagging.
A tabulation of Safety Injection System relief valves is provided below.
- 1. SI-211, 221, 231, and 241, Safety Injection Tank relief valves.
The relief valves on the safety injection tanks are sized to protect the tanks against the maximum fill rate of liquid or gas into the safety injection tanks. They discharge into the containment. The set pressure is 700 psig with a capacity of 6000 SCFM of gas or 230 gpm of liquid.
- 2. SI-473, Check Valve Leakage Relief Valve.
A relief valve is provided on the safety injection test and leakage return line. This relief valve is sized to protect against overpressure of the line when relieving injection line pressure following check valve testing or during normal operation. It discharges into the reactor drain tank. The set pressure is 2050 psig with a capacity of 35 gpm.
- 3. SI-474 and SI-407, Safety Injection Tank Fill Line Relief Valves.
Relief valves are located on the Safety Injection Tank fill line to protect against overpressure due to a temperature increase. SI-474 discharges to 6.3-14 l
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(Sheet 1 of 2) l EFFECTIVE PAGE LISTING CH__ APTER 6 APPENDIX 6A Table of Contents Page Amendment ADStract i ii iii iv v Text Page Amendment 6A-1 6A-2 6A-3 6A-4 l 6A-5 6A-6 6A-7 6A-8 6A-9 6A-10 6A-ll 6A-12 6A-13 6A-14 6A-15 6A-16 6A-17 6A-18 6A-19 6A-20 6A-21 6A-22 6A-23 6A-24 6A-25 6A-26 6
, 6A-27 6A-28 6A-29 6A-30 6A-31 Amendment No. 7 March 31,1982
(Sheet 2 of 2) EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 6 APPENDIX 6A Tables Amendment 4.5 (Sheets 1-5) 5 5.2 (Sheets 1 and 2) 5.4 6.1 6.2 7.13 l 9' t l l l O Amendment No. 7 March 31,1982
(Sheet 1 of 2) EFFECTIVE PAGE LISTING CHAPTEP 6 APPENDIX 6B Table of Contents Page Amendment Abstract 1 ii iii iv V vi Text Page Amendrient j 6B-1 6B-2 6B-3 6B-4 0 6B-5 68-6 6B-7 6B-8 6B-9 68-10 l 6B-11 6B-12 6B-13 6B-14 68-15 68-16 6B-17 6B-18 l 6B-19 68-20 l 6B-21 6B-22 6B-23 6B-24 6 6B-25 68-26 6B-27 6B-28 68-29 6B-30 Amendment No. 7 March 31, 1982
1 (Sheet 2 of 2) i EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 6 A WENDIX 6B aMes Amendment 4.3 (Sheets 1-4) 5 5.3 5.4 6.2 ) 1 gres Amendment I 3.5 1 O l l O Amendment No. 7 March 31,1982
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i (Sheet 1 of 6) i i 1 'l EFFECTIVE PAGE LISTING l CHAPTER 7 l 1 Table of Contents l Page Amendment i i ii iii iv .I v i vi i vii i viii j ix ! x xi j xii 7 1, xiii xiv xv 5 xvi xvii 7 t 0 Text l Page Amendment i
- 7.1-1 i 7.1-2 l 7.1-3
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- 7.1-12 l 7.1-13
- 7.1-14 l 7.1-15 7.1-16 7.1-17 7.2-1 7.2-2 7.2-3 6
.i 7.2-4 5 ! 7.2-4(a) 5 l l Amendment No. 7 March 31, 1982' I 1 l'
(Sheet 2 of 6) EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Text (Cont'd) Page Amendnent 7.2-5 7.2-6 5 7.2-7 7.2-8 7.2-9 6 7.2-10 7.2-11 7.2-12
! 7.2-13 7.2-14 7.2-15 7.2-16 7.2-17 7.2-18 7.2-19 5 7.2-19(a) 5 7.2-20 7.2-21 5 7.2-22 5 7.2-23 7.2-24 7.2-25 G 7.2-25(a) 5 l 7.2-26 7.2-27 7.2-28 7.2-29 7.2-30 5 7.2-30(a) 5 7.2-31 6
- 7. 2-31 (a ) 6 7.2-32 7.2-33 6 7.2-33(a) 6 7.2-33(b) 6 7.2-33(c) 6 1.2-34 1.3-1 i 7.J-2 7.3-3 7.3-4 7.3-5 7.3-6 7.3-7 7.3-8 7.3-9 Amendment No. 7 March 31, 1982
i (Sheet 3 of 6) i EFFECTIVE PAGE LISTIf4G (Cont'd) CHAPTER 7 l Text (Cont'd) i 1 i Page Amendment i 7.3-10 7.3-11 7.3-12 7.3-13 7.3-14 7.3-15 7.3-16 ' 7.3-17 7.3-18 5
- 7.3-19 7.3-20 7.3-21
! 7.3-22 6 1 7.3-23
! 7.3-24 7.3-25 i 7.4-1 7.4-2 7.4-3 .9 l 7.4-4 7.4-5 7.4-6 5 1 7.4-7 7.4-8 i 7.4-9 , 7.4-10 5 7.5-1 I 7.5-2 5 1 I 7.5-3 7.5-4 7.5-5 I 7.5-6 7.5-7 7.5-8 7.5-9 ! 7.5-10 7.5-11 i 7.6-1 i 7.6-2 I 7.6-3 i 7.6-4 l 7.6-5 1 7.6-6 7.6-7 l 7.6-8 ! 7.6-9 i i 4 Amendment fio. 7 March 31, 1982 i
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(Sheet 4 of 6)
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EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Text (Cont'd) Page Amendment 7.7-1 7.7-2 7.7-3 7.7-4 7.7-5 7.7-6 6 7.7-6(a) 6 7.7-7 7.7-8 7 7.7-8(a) 7 7.7-9 7.7-10 5 7.7-10(a) 7 7.7-11 7.7-12 6 7.7-12(a) 6 7.7-13 7.7-14 7.7-15 5 7.7-16 7.7-17 6 7.7-18 7.7-19 5 7.7-20 7.7-21 Tables Amendment ! 7.2-1 l 7.2-2 5 7.2-3 5 7.2-4 5 7.2-5 (Sheets 1-129) 5 7.3-1 7.3-2 7.3-3 5 7.3-4 7.3-5 7.3-6 7.5-1 (Sheets 1 and 2) 7.5-2 (Sheets 1-3) 7.5-3
- 7. 6-1 7 7.7-1 Amendment No. 7 March 31,1982
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(Sheet 5 of 6) l EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 i i
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Amendment j 7.1-1 l ! 7.1-2 5 ; 7.1-3 1 7.1-4 (Sheets A-C) I 7.1-5 5 7.1-6 (Sheets A and B) 7.1-7 7.1-8 5
, 7.1-9 7.1-10 7.1-11 7.1-12 5 7.1-13 (Sheets A and B) 7.1-14 7.1-15 7.1-16 (Sheets A and B)
! 7.1-17 (Sheets A-C) i 7.1-18 5 7.2-1 5 . 7.2-2 5 7.2-3 7.2-4 7.2-5
- 7.2-6 7.2-7 7.2-8 7.2-8(a) 6 7.2-9 i 7.2-9(a) 6 7.2-9(b) 6 7.2-10 7.2-11 5 7.2-12 5 7.2-13 5 7.2-14 5 7.2-15 7.2-16 7.2-17 5
! 7.3-1(a) 1 7.3-l(b) 7.3-1(c) 5 j 7.3-1(d) 5 7.3-2 5
( 7.3-3 5 7.3-3(a) 5 i 7.3-4 l j Amendment No. 7 March 31,1982 il
(Sheet 6 of 6) EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 7 Figures (Cont'd) Amendment 7.3-5 7.3-6 7.4-1 7.4-2 7.6-1(a) 7.6-1(b) 7.6-2 7.6-3 7.7-1 7.7-2 7.7-3 7.7-4 7.7-5 5 7.7-6 5 7.7-7 6 7.7-8 7.7-9 7.7-10 7 O 6 O Amendment No. 7 March 31,1982
t TABLE OF CONTENTS (Cont'd.) O CHAPTER 7 Section Subject Page No. 7.5.2 ANALYSIS 7.5-4 7.5.2.1 Analysis of Safety-Related Plant Process 7.5-4 Display Instrumentation 7.5.2.2 Analysis of Reactor Trip System Monitoring 7.5-5 7.5.2.3 Analysis of Engineered Safety Features 7.5-5
- Monitoring 7.5.2.4 Analysis of CEA Position Indication 7.5-6 7.5.2.5 Analysis of Post-Accident Monitoring 7.5-6 Instrumentation 7.5.2.6* Analysis of Automatic Bypass Indication on 7.5-10 a System Level 7.6 ALL OTHER SYSTEMS REQUIRED FOR SAFETY 7.6-1 7.
6.1 INTRODUCTION
7.6-1 7 . 6.1.1 System Descriptions 7.6-1 7.6.1.1.1 Shutdown Cooling System Suction Line 7.6-1 Valve Interlocks 7.6.1.1.2 Safety Injection Tank Isolation Valve 7.6-2 Interlocks 7.6.1.2 Design Bases 7.6-2 7.6.1.2.1 Shutdown Cooling System Suction Line 7.6-2 Valve Interlocks 7.6.1.2.2 Safety Injection Tank Isolation Valve 7.6-3 Interlocks 7.6.1.3 Final System Drawings 7.6-3 7.6.2 ANALYSIS 7.6-4 7.6.2.1 Design Criteria 7.6-4 4 7.6.2.1.1 Shutdown Cooling System Suction Line 7.6-4 Valve Interlocks 7.6.2.1.2 Safety Injection Tank Isolation Valve 7.6-4 Interlocks
*See Applicant's SAR xi
TABLE OF CONTENTS (Cont'd.) CHAPTER 7 Section Subject Page No. 7.6.2.2 Equipment Design Criteria 7.6-4 7.6.2.2.1 Shutdown Cooling System Suction Line 7.6-4 Valve Interlocks 7.6.2.2.2 Safety Injection Tank Isolation Valve 7.6-7 Interlocks 7.7 CONTROL SYSTEMS NOT REQUIRED FOR SAFETY 7.7-1 7.
7.1 DESCRIPTION
7.7-1 7.7.1.1 Control Systems 7.7-1 7.7.1.1.1 Reactivity Control Systems 7.7-1 7.7.1.1.2 Reactor Coolant System Pressure 7.7-2 Control System 7.7.1.1.3 Pressurizer Level Control System 7.7-3 7.7.1.1.4 Feedwater Control System 7.7-4 7.7.1.1.5 Steam Bypass Control System 7.7-4 7.7.1.1.6 Reactor Power Cutback System 7.7-6 7.7.1.1.7 Boron Control System 7.7-6 7.7.1.1.8 In-Core Instrumentation System 7.7-7 7.7.1.1.9 Ex-Core Neutron Flux Monitoring 7.7-8 System (Non-Safety Channels) }.?.1.1.10 Boron Dilution Alarm System 7.7.-8 7.7.1.2 Design Comparison 7.7-8 7.7.1.2.1 Reactivity Control Systems 7.7-9 7.7.1.2.2 Reactor Coolant Pressure Control 7.7-9 System 7.7.1.2.3 Pressurizer Level Control System 7.7-9 7.7.1.2.4 Feedwater Control System 7.7-9 7.7.1.2.5 Steam Bypass Control System 7.7-10 7.7.1.2.6 Reactor Power Cutback System 7.7-10 7.7.1.2.7 Boron Control System 7.7-10 7.7.1.2.8 In-Core Instrumentation System 7.7-10 7.7.1.2,9 Ex-Core Neutron Flux Monitoring 7.7-10 System 7.7.1.2.10 Boron Dilution! Alarm System 7.7-10a 7.7.1.3 Monitoring Systems 7.7-11 7.7.1.3.1 Core Operating Limit Supervisory 7.7-11 System (COLSS) O Amendment No. 7 March 31, 1982 xii
LIST OF FIGURES CHAPTER 7
,k Figure No. Subject 7.1-1 MCBD Symbols, Notes & Abbreviations 7.1-2 Loop 1 Temperatures MCBD i
j 7.1-3 Reactor Coolant Pump MCBD 4 7.1-4A (Hi) Pressurizer Pressure MCBD 7.1-4B (Lo) Pressurizer Pressure MCBD 7.1-4C (SPS) Pressurizer Pressure MCBD 7.1-5 Pressurizer Level Control System MCBD 7.1-6A Miscellaneous Pressurizer Measurements MCBD 7.1-6B Miscellaneous Pressurizer Measurements MCBD 7.1-7 Nuclear Instrumentation MCBD i 7.1-8 Letdown Line and Le+.down Control Valve MCBD d 7.1-9 Refueling Water Tank MCBD l 1 7.1-10 Charging Pumps MCBD 7.1-11 Reactor Drain Tank MCBD 7.1-12 Safety Injection Tank 1 MCBD i l 7.1-13A Shutdown Cooling and Containment Spray MCBD 7.1-13B Shutdown Cooling and Containment Spray MCBD j 7.1-14 Shutdown Cooling Valves MCBD 7.1-15 Containment Pressure NCBD { 7.1-16A H'.gh Pressure Safety Injection MCBD j 7.1-16B High Pressure Safety Injection MCBD 7.1-17A Steam Generator Protective System MCBD ( 7.1-17B Steam Generator Protective System MCBD ! 7.1-17C Steam Generator Protective System MCBD I l 7.1-18 Steam Generator D/P MCBD i l5 Amendment No. 5 xv October 26, 1981
l LIST OF FIGURES CHAPTER 7 Figure Subject 7.2-1 Typical Measurement Channel Functional Diagram (Pressurizer Pressure Wide Range) 7.2-2 Reed Switch Position Transmitter Assembly Schematic 7.2-3 Reed Switch Position Transmitter Cable Assemblies 7.2-4 CEA Position Signals Within Reactor Protection System 7.2-5 Ex-Core Neutron Flux Monitoring System 7.2-6 Reactor Coolant Pump Speed Sensors Typical For Each Reactor Coolant Pump 7.2-7 Core Protection Calculator Functional Block Diagram 7.2-8 Bistable Block Diagram 7.2-8a Supplementary Protection System Block Diagram 7.2-9 Reactor Protective System Simplified Functional Logic Dia-gram 7.2-10 Typical Trip Channel Bypass 7.2-11 Matrix, Bistable Trip and Log Trip Interlock Ckt. 7.2-12 Basic PPS Testing System (Shown For Reactor Protective System) 7.2-13 Plant Protection System Interface Logic Diagram 7.2-14 Simplified PPS Cabinet Layout (Rear View) 7.2-15 Typical PPS Bay Layout 7.2-16 Auxiliary Relay Cabinet A (Front View) 7.3-la ESFAS Signal Logic (SIAS) 7.3-lb ESFAS Signal Logic (CSAS, CIAS, RAS) 7.3-lc ESFAS Signal Logic (MSIS) 7.3-ld ESFAS Signal Logic (EFAS 1, EFAS 2) O xvi
_ = . . . . - - - - _ . .- . _ - - - LIST OF FIGURES (Cont'd.) l CHAPTER 7 Figure Subject 7.3-2 Functional Diagram of a Typical Engineered Safety Feature Actuation 7.3-3 ESFAS Auxiliary Relay Cabinet Schematic Diagram for Typical Actuation Signal 7.3-3a ESFAS Auxiliary Relay Cabinet Schematic Diagram For the EFAS (or MSIS) 7.3-4 Control Circuit for a Solenoid Actuated, Air Operated Valve 7.3-5 Control Circuit for a Motor Operated Valve 7.3-6 Control Circuit for a Pump Motor 7.4-1 Shutdown Cooling System Logic Diagram 7.4-2 Chemical and Volume Control System Logic Diagram i 7.6-la- Shutdown Cooling System Suction Line Isolation Valve Inter-s lock
/ 7.6-lb Shutdown Cooling System Suction Line Isolation Valve Inter-lock 7.6-2 Safety Injection Tank Isolation Valve Interlocks 7.6-3 Safety-Related Interlock Test Circuit 7.7-1 Reactor Regulating System l 7.7-2 CEDMCS - RPS Interface Block Diagram l 7.7-3 Pressurizer Pressure Control System Block Diagram 7.7-4 Pressurizer Level Control System Block Diagram 7.7-5 Feedwater Control System Block Diagram 7.7-6 Steam Bypass Control System Block Diagram 7.7-7 Reactor Power Cutback System Simplified Block Diagram l
7.7-8 Boronometer Block Diagram l I 7.7-9 Functional Diagram of the Core Operating Limit Supervisory O System . b ! 7.7-10 Boron Dilution Alarm Simplified Block Diagram 17 i Amendment No. 7 xvii March 31, 1982
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pi Pretrip alarms are initiated above the trip setpoint to provide audible and visible indication of approach to a trip condition. gJ , 7.2.1.1.1.7 Low Steam Generator Water Level. The low steam generator water level trip is provided to trip the reactor when measured steam generator . water level falls to a low preset value. Separate trips are provided from l ~ each steam generator. The nominal trip setpoint is provided in Table 7.2-4. Pretrip alarms are initiated above the trip setpoint to provide audible and visible indication of approach to a trip condition. 7.2.1.1.1.8 Low Steam Generator Pressure. The low steam generator pressure trip is provided to trip the reactor when the measured st 7am
- generator pressure falls to a low preset value. Separate trips are provided from each steam generator. The nominal trip setpoint during normal operation 6 is provided in Table 7.2-4. At steam generator pressures below normal, the operator has the ability to manually decrease the setpoint to a fixed increment below existing system pressure. This is used during plant cooldown.
During startup, this setpoint is automatically increased and remains at the fixed increment below generator pressure. This fixed increment is provided in Table 7.2-4. Pretrip alarms are initiated to provide audible and visible indication of approach to a trip condition. O 7.2.1.1.1.9 High Containment Pressure. The high containment pressure V trip is provided to trip the reactor when measured containment pressure reaches a high preset value. The nominal trip setpoint is provided in Table 7.2-4. The trip is provided as additional design conservatism (i.e. , additional means of providing a reactor trip). The high containment pressure trip setpoint is selected in conjunction with the high-high containment pressure setpoint to prevent exceeding the containment design pressure during a design basis LOCA or main steam line break accident. Pretrip alarms are initiated to provide audible and visible indication of approach to a trip condition. 7.2.1.1.1.10 High Steam Generator Water Level. A high steam generator water level trip is provided to trip the reactor when measured steam generator water level rises to a high preset value. Separate trips are provided from ' each steam generator. The nominal trip setpoint is provided in Table 7.2-4. Pretrip alarms are initiated to provide audible and visible indication of approach to a trip condition. 7.2.1.1.1.11 Manual Trip. A manual reactor trip is provided to permit the operator to trip the reactor. Actuation of two adjacent pushbutton ! switches in the main control room will cause interruption of the ac power l to the CEDMs. Two independent sets of trip pushbuttons are provided; ! either one of which will cause a reactor trip. There are also manual I reactor trip switches at the reactor trip switchgear. t ) Amendment No. 6 7.2-3 November 20, 1981
The remote manual initiation portion of the Reactor Trip System is designed as an input to the RTSS. This design is consistent with the recommendations of NRC Regulatory Guide 1.62. The amount of equipment common to both automatic and manual initiation is kept to a minimum. Once initiated, the manual trip will go to completion as required in Section 4.16 of IEEE Standard 279-1971. 7.2.1.1.1.12 Low Reactor Coolant Flow. The low reactor coolant flow trip is provided to trip the reactor when the pressure differential across the primary side of either steam generator decreases below a rate limited variable setpoint, as shown in Figure 7.2-17. A separate trip is provided for each steam generator. This function is used to provide a reactor trip 5 for a reactor coolant pump sheared shaft event. Pretrip alarms are provided. 7.2.1.1.2 Initiating Circuits 7.2.1.1.2.1 Process Measurements. Various pressures, levels, and temperatures associated with the NSSS and the containment building are continuously monitored to provide signals to the RPS trip bistables. All protective parameters are measured with four independent process instrument channels. A detailed listing of the parameters measured is contained in Table 7.2-3. A typical protective channel, as shown in Figure 7.2-1, consists of a sensor / transmitter, converter / power supply, current loop resistors, indicating meter or recorder, trip bistable / calculator inputs, and outputs for the Plant Monitoring System (PMS). The piping, wiring, and components of each channel are physically separated from that of other like protective channels to provide independence. The output of each transmitter is an ungrounded current loop. Exceptions are (1) the nuclear instruments, and (2) the reactor coolant pump speed sensors which provide a pulsed voltage signal. Signal isolation is provided for computer inputs. Each redundant channel is powered from a separate vital ac bus. 7.2.1.1.2.2 CEA Position Measurements. The position of each CEA is an input to the RPS. These positions are measured by means of two reed switch assemblies on each CEA. Each reed switch assembly consists of a series of magnetically actuated reed switches spaced at intervals alang the CEA housing and wired with precision resistors in a voltage divider network (see Figure 7.2-2). A magnet attached to the CEA extension actuates the adjacent reed switches, causing voltages proportional to position to be transmitted for each assembly. The two assemblies and wiring are physically and electrically separated from each other (see Figure 7.2-3). l5 One set of the redundant signals for all CEA's is monitored by one CEA Calculator and the other set of signals by the redundant CEA Calculator. Amendment No. 5 October 26, 1981 7.2-4
)
l r ( TABLE 7.6-1 SHUTDOWN COOLING SYSTEM AND SAFETY INJECTION TANK INTERLOCKS SYSTEM SETPOINT FUNCTION Shutdown Cooling System Suction Line Valves < 400 psia Permits valves to be opened by operator.
> 700 psia Valves are automatically closed. l7 Safety Injection Tank Isolation Valves > 500 psig Valves are automatically opened.
< 415 psig Permits valves to be closed by operator.
SIAS Automatically opens the valves, \s if the valves are closed. Sends an open signal if valves are open that overrides a closing signal. Shutdown Cooling Relief Valves 435 psig Prevents or mitigates overpres-surization of the SCS. O v Amendment No. 7 March 31, 1982
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prescribed boron concentration either manually or automatically. To assist (O
'j the operator in maintaining the proper boric acid concentration in the Reactor Coolant System, indications of boron concentration, in parts per million (ppm), are provided on a digital readout and on a recorder. These signals are supplied by the Boronometer. Additional recorders indicate reactor makeup water flow and boric acid makeup flow, which can be used to determine whether boration or dilution is occurring.
The Boronometer detects the boron concentration by passing reactor coolant around a neutron source. Refer to Figure 7.7-8 for the Boronometer block diagram. Around the source are BF 3 neutron detectors. As the boron concentra-tion decreases the neutron flux detected will increase. The circuitry converts this flux signal, corrected for sample temperature, to a ppm boron signal in the signal processing drawer. These processed signals are sent to the PMS, the control room and to an annunciator. The information supplied by the Boronometer system is used in addition to regular sampling of the reactor coolant to determine boron concentration. At power, the boron concentration, in addition to CEA position determines reactor coolant temperature. Because of the long time required to chang'e the boron concentration, the boron is used for long term effects such as fuel burnup and fission product build up. Boron concentration control can also be used for load following. By adjusting the boron concentration, the CEAs can be withdrawn to provide an adequate shutdown margin. 7.7.1.1.8 In-Core Instrumentation System V} The in-core instrumentation system is used to monitor the core power distribu-tion. There are 61 in-core monitoring assemblies with five self powered Rhodium detectors in each location. The 61 assemblies are strategically distributed about the reactor core, and the five detectors are axially distributed along the length of the core at 10, 30, 50, 70 and 90% of core height. This permits representative three diminsional flux mapping of the core. The Rhodium detectors produce a delayed beta current proportional to the neutron activation of the detectors which is proportional to the neutron flux in the detector region. The signals from the in-core detectors are converted to usable voltage signals by the In-Core Amplifier System which sends these signals to the Plant Monitoring Computer (PMC) portion of the PMS by way of a multiplexer. The PMS converts these analog voltages to equivalent digital signals and performs the background, beta decay delay and Rhodium depletion compensation using digital signal processing routines. In addition to the fixed system described above there is a movable in-core monitoring system. The movable system consists of two movable detectors and i associated hardware to position either probe at any core locations. The movable detector system provides a flux map independent of the fixed detector p) system. The movable in-core system is controlled by the PMS and provides for fully automatic mapping of the total core. 7.7-7
The fixed and movable in-core instrumentation systems are designed to perform the following functions:
- a. To determine the gross power distribution in the core during different operating conditions from 20% to 100% power;
- b. To provide data to estimate fuel burn-up in each fuel assembly;
- c. To provide data for the evaluation of thermal margins in the core; The fixed and movable in-core detectors can be used to assist in the calibra-tion of the ex-core detectors by providing azimuthal and axial power distribu-tion information. The ex-core system is used to provide indication of the flux power and axial distribution for the Reactor Frotective System.
7.7.1.1.9 Ex-Core Neutron Flux Monitoring System (Non-Safety Channels) The ex-core neutron flux monitoring system includes neutron detectors located around the reactor core and signal conditioning equipment located in the control room area. Neutron flux is monitored from source levels through full power operation and signal outputs are provided for reactor control and for information display. Two startup channels provide source level neutron flux information to the reactor operator for use during extended shutdown periods, initial reactor II 5 startup, startups af ter extended shutdown periods, and following reactor refueling operations. Each channel consists of a dual section proportional counter assembly, with each section having multiple BF3 proportional counters, one preamplifier located outside the reactor shield, and a signal processing drawer containing power supplies, a logarithmic amplifier, and test circuitry. High voltage power to the proportional counters is terminated several decades of neutron flux above the source level to extend detector life. These channels provide readout and audio count rate information but have no direct control or protective functions. Two control channels provide neutron flux information, in the power operating range of 1% to 125%, to the Reactor Regulating System for use during automatic turbine load-following operation (see Section 7.7.1.1.1). Each control channel consists of a dual section uncompensated ionization chamber detector and a signal conditioning drawer containing power suoplies, a linear amplifier, and test circuitry. The detector is operated in the current mode only. These channels are completely independent of the safety channels. 7.7.1.1.10 Boron Dilution Alarm System Reactivity control in the reactor core is effected, in part, by soluble boron in reactor coolant system. The Boron Dilution Alarm System (Figure 7.7-10) utilizes the startup channel nuclear instrumentation signals to detect a possible inadvertent boron diultion event while in Modes 3-6. There are 7 two redundant and independent channels in the Boron Dilution Alarm System (BDAS) to ensure detection and alarming of the event. Amendment No. 7 O March 31, 1982 7.7-8
) The BDAS contains logic which will detect a possible inadverent boron V dilution event by monitoring the startup channel neutron flux indications.
When these neutron flux signals increase (during shutdown) to equal or greater than the calculated alarm setpoint, alarm signals are initiated to the Plant Annunciation System. The alarm setpoint is periodically, automatically lowered to be a fixed amount above the current neutron flux signal. The alarm setpoint will only follow decreasing or steady flux levels, not an increasing signal. 7 The current neutron flux indication and alarm setpoint (per channel) are dis-played. There is also a reset capability to allow the operator to acknowledge the alarm and initialize the system. 7.7.1.2 Design Comparison The functional design of the following, non-safety, control systems was performed by Combustion Engineering. The design differences between the control systems in the CESSAR Licensing scope and the control systems pro-vided for the reference plant (Arkansas Nuclear One - Unit 2 - (AN0-2) NRC Docket No. 50-368) are discussed in this section. .(/ 1 0 U) c Amendment No. 7 7.7-8a
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) i j i 7.7.1.2.10 Boron Dilution Alarm System The Boron Dilution Alarm System is an addition to the CESSAR design. There 7 i is no functional comparison to the reference plant. .i 4 i i j i l i i i \,O - I l 1 i i ; i i l l Amendment No. 7 i March 31, 1982 l l l 7.7-10a i I
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I l O ; j RESET i 9F STARTUP CHANNEL NUCLEAR BORON DILUTION m CURRENT FLUX & INSTRUMENTATION SIGNALM " SETPOINT DISPI TY ALARM SYSTEM LOGIC l 1r ALARM SIGNAL TO < THE PLANT ANNUNCIATION ! SYSTEM NOTE: ONLY ONE OF TWO IDENTICAL CHANNELS IS SHOWN. l Amendment No. 7 fla rch 31, 1982 i l C-E / BORON DlLUTION ALARM SYSTEM Figure SIMPLIFIED BLOCK DI AGRAM 7.7-10 t
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'a ge Amendment i
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j 8.1-1 8.1-2 I 8.1-3 1 i 8.2-1 ! 8.3-1 . ] 8.3-2 .) 8.3-3 1 , 1 ' l , i
- Tables * '
. Amendment i
[ 8.3.1-1 (Sheet 1 and 2) (Sheet 3) 1 8.3.1-2 l 8.3.1-3 8.3.1-4 . ) Figures I
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(Sheet T oT 3) EFFECTIVE PAGE LISTING 9 Table of Contents CHAPTER 9 Page Amendment i ii iii iv v vi i Text Page Amendment 9.1-1 l 9.1-2 l 9.1-3 l 9.1-4 9.1-5 l 9.1-6 9.1-7 9.1-8 9 9.1-9 9.1-10 9.1-11 9.1-12 9.1-13 9.1-14 9.1-15 9.1-16 ' 9.1-17 9.1-18 j 9.1-19 [ 9.1-20 l 9.1-21 9.1-22 9.1-23 9.2-1 6 l 9.3-1 9.3-2 9.3-3 9.3-4 9.3-5 9.3-6 9.3-7 9.3-8 9.3-9 9.3-10 0 Amendment No. 7 March 31, 1982
(Sheet 2 of 3) EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 9 Text (Cont'd) Page Amendment 9.3-11 9.3-12 9.3-13 9.3-14 9.3-15 9.3-16 9.3-17 9.3-18 9.3-19 9.3-20 9.3-21 9.3-22 9.2-23 9.3-24 9.3-25 9.3-26 9.3-27 9.3-28 9.3-29 7
- 9. 3-29(a ) 7 9.3-30 9.3-31 9.3-32 6 9.3-33 6 9.3-34 6 l 9.3-35 I 9.4-1 Tables !
Amendment , 9.1-1 9.1-2 (Sheets 1 and 2) l 9.2-1 l 9.3-1 (Sheets 1 and 2) l 9.3-2 (Sheets 1 and 2) 9.3-3 1 9.3-4 (Sheets 1-10) 1 9.3-5 ' l 9.3-6 (Sheets 1-4) 9.3-7 (Sheets 1-37) (Sheet 38) 7 (Sheets 39-49) (Sheet 50) 7 (Sheets 51-92) (Sheet 93) (Sheets 94-100) 9.3.8 (Sheets I and 2) 7 Amendment No. 7 March 31,1982
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CHAPTER 9
! Figures Amendment 9.1-1 9.1-2 l
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9.1-9 9.1-10 9.1-11 9.1-12 , 9.1-13 9.1-14 9.1-15 9.1-16 I 9.1-17 l 9.1-18
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l 9.1-22 J, 9.3-1 7 9.3-2 - 9.3-3 9.3-4 6 i i i l l l l i I i i i I Amendment No. 7 i March 31,1982 [ I
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[
- c. In the event of a failure of a bus, standby equipment connected to other buses shall be capable of being placed in operation.
', 2. Emergency Power Requirements
- a. Charging Pumps - Each emergency power bus shall supply one pump. Additionally, the third charging pump shall be capable of receiving power from either emergency power bus. The charging pumps shall not be automatically sequenced on the emergency power busses.
- b. The following are emergency power supply requirements for CVCS instrumentation:
Control Instrument Location ()) Emergency Bus L-200 (RWT level) A/C A L-201 (RWT level) A/C B F-212 (Charging flow) A/C B P-212 (Charging pressure) A/C A L-203A (RWT RAS level) A A L-2038 (RWT RAS level) A B L-203C (RWT RAS level) A C L-203D (RWT RAS level) A D ^ c) The following are emergency power supply requirements for CVCS valves:
) Emergency Bus Control Location ())
Valve CH-515(receivesSIAS) B A/C CH-516 (receives SIAS & CIAS) A A/C CH-560 (receives CIAS) A A CH-561 (receives CIAS) B A CH-580 (receives CIAS) A A CH-506 (receives CIAS) A A/C l CH-505 (receives CIAS) B A/C CH-523 (receives CIAS) B A CH-507 A A/C CH-530 B A j CH-531 A A 4 CH-203 B A/C 1 CH-205 A A/C l CH-255 A A CH-501 A A CH-524 B A A 7 CH-536 A Note (1): Location code is as follows; A-Control Room, ' B-Local, C-Remote Shutdown Panel, D-Location outside Control Room. iO Amendment No. 7
-29 March 31, 1982
B. Protection from Natural Phenomena l
- 1. The location, arrangement, and installation of the RWT, charging pump gravity feed piping, charging pumps, charging pump discharge piping, the letdown line between the RCS and letdown containment Ol!
)
1 Amendment No. March 31, 198
- 9. 3- 29a
,A isolation valves, and Safety Injection Systems (SIS) trains
(' suction piping shall be such that floods (and tsunami and seiches
> for applicable sites) or the effects thereof will not prevent them from performing their functions. The severity of the above natural phenomena to be considered, as well as the combination of the effects of these natural phenomena with the design conditions of ANSI N18.2-1973, shall meet the requirements of Criterion 2 of 10CFR50, Appendix A.
- 2. The location, arrangement and installation of the RWT, charging pump gravity feed piping, charging pumps, charging pump discharge piping, the letdown line between the RCS and letdown containment isolation valves, and SIS trains suction piping shall be such that winds and tornadoes or the effects thereof will not prevent them from performing their functions. The severity of the winds and tornadoes to be considered, as well as the combination of the effects of these natural phenomena with the design conditions of ANSI N18.2-1973, shall meet the requirements of Criterion 2 of 10CFR50, Appendix A.
- 3. The location, arrangement, and installation of the RWT, charging pump gravity feed piping, charging pumps, charging pump discharge piping, the letdown line between the RCS and letdown containment isolation valves, and SIS trains suction piping shall be such that they will withstand the effects of earthquakes without loss of the capability to perform their functions. The severity of
' (n)
(_/ The severity of the earthquakes considered, as well as the combin-ation of these natural phenomena with the design conditions of ANSI N.18.2-1973, shall meet the requirements of Appendix A of 10CFR50, Appendix A of 10CFR100, and NRC Regulatory Guide 1.48. Failure of non-seismic systems and structures shall not cause loss of either SIS train. C. Protection from Pipe Failure The letdown subsystem (from the RCS coolant system), charging system (from valve CH-ll8 through the charging pumps to RCS to CH523), auxiliary spray, high pressure safety injection header, and drain header isolation valves (CH-329, 332, 3367) and boric acid addition system (including both of the Refueling Water Tank gravity feed connections to the charging pump suction header) the connections from the refueling water tank to the suction of the safety injection system pumps, and the Refueling Water Tank and spent fuel pool connections to the charging pump suction header via the Boric Acid Makeup Pumps and valve CH-514 shall be protected from loss of function from the effects of pipe rupture, such as pipe whip, jet impingement, jet reaction, pressurization, or flooding. D. Missiles The portion of the CVCS protected from pipe failure (see 9.3.4.6.C) shall also be protected from loss of function from the effects of missiles in p accordance with the missile barrier design interface requirement of Section 3.5.3.1. 9.3-30
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x v/ TABLE 9.3-7 (Continued) (Sheet 37 of 100) CHEMICAL AND VOLUME CONTROL SYSTEM (t,VCS) FAILURE MODE AND EFFECTS ANALYSIS Symptoms and Local Effects Inherent Remarks and Failure Mode Cause Including Dependent Failures Method of Detection Compensating Provision Other Effects
& Name Mech. binding No impact on normal operation. Operator Valve, CH-524 can be 120) Charging Line a) fails Unable to isolate charging closed Manual Isola- open tion Valve; line for maint. or for alter-CH-429 nate path charging thru HPSI header Mech. binding Unable to reestablish Operator Alternate charging path b) fails charging flow thru normal thru HPSI header closed path Mech. binding, No impact on normal operation. Valve position Manual isolation Handwheel on valve 121) Charging Line a) fails valve operator Unable to isolate charging indicator in con- valve, CH-429 can be used to Isolation open trol room, flow close valve if Valve; failure, loss line for maint. or alternate of power path charging thru HPSI indicator, f!-212 operator mal-CH-524 function.
header Mech, binding. Unable to reestablish charging Valve position Alternate path charging b) fails valve operator thru normal path; if this indicator in con- thru HPSI header closed failure occurs during normal opera- trol room, flow tion the chg. pump disch. indicator, FI-212 relief will lift. Mech. binding No impact on normal operation. Operator None 122) Test Connec- a) fails Unable to test charging line tion CH-854 closed isolation valves IAW ASME XI. Contamination, Minor loss of primary coolant Local leak Drain line is blind flanged b) seat detectors leakage mech. damage outside containment 123) Temperature erroneous Elect. or mech. No impact on system operation. Periodic test None Indicator, temperature malfunct., TI-229 has no control function TI-229 indications setpoint drift Mech, binding, No impact on normal operation. Valve position in- Redundant valves from Cold shutdown can 124) Auxiliary Spray a) fails dication in control separate power supplies. be achieved with-valves; CH-203, closed valve operator Unable to use the charging out auxiliary CH-205 failure, loss pumps to provide aux. PZR room spray, of power spray for PZR pres. control during plant shutdown
TABLE g.3-7 (Continued) (Sheet 33 of 100) ' CHEMICAL A'.D VOLUME CONTROL SYSTEM (CVCSl FAILURE MODE AND EFFECTS ANALYSIS Symptoms and Local Effects Inherent Remarks and No. Name Failure Mode Cause Including Dependent Failures Method of Detection Compensating Provision Other Effects b) fails spurious sig- Excess PZR spray flow, result- Valve position in- None PZR heaters will open nal, operator ing in reduction of RCS pres. aicators in control come on to main-error room tain PZR pres. 125) Charging Line a) fails Mech. failure, Sudden loss of charging flow, VCT and PZR level Alternate charging path Pressure Con- closed Spurious signal VCT level increases, PZR level indications, lo through HPSI header. trol Valve, decreases. Pressure increases flow alarms from Spring check valve CH-CH-240 in chcrging line FI-212, Hi pres. 435 will open to main-indic, from PI-212 tain charging flow b) regulates Valve operator Short term decrease in RCP Lo flow indications Seal injection flow con-back pres- malfunction, seal injection flow and in- or alarms from seal trol valves will open to sure too mech. binding crease in charging flow injection flow indi- increase flow, thereby low cators. Lo delta reestablishing flow pres. indication or balance alarm from PDIC-240 c) regulates Valve operator Short term increase in RCP Hi flow indications Seal injection flow con-back pres- malfunction, seal injection flow and de- or alarm from seal trol valves will close to sure too mech. binding crease in charging flow. injection flow indi- limit flow. Spring check high partial block- Increase in charging line cators. Hi delta valve CH-435 will open to l7 age pres. pres. indication or maintain charging flow if alarm from PDIC-240 neces sa ry. 126) Auxiliary Spray a) fails Mech. binding, No impact on normal opera- Lo flow indication None Plant can be Line Check closed blockage tion. Unable to provide from FI-212, PZR brought to cold Valve; CH-431 aux. PZR spray for PZR pres- pres., not de- shutdown with-sure control during plant creasing. Out auxiliary shutdown spray. b) fails Mech. failure Diversion of PZR spray flow PZR pres. indica- Aux. spray valves CH-203 open to charging line. Possible ters and CH-205 are closed dur-PZR pres increase ing normal operation 127) Differential a) spurious Elect. or mech. PDIC-240 will drive CH-240 Hi flow alarms from Seal injection flow con-Pressure Lo diff. malfunct., closed trying to maintain a seal injection flow trol valves will main-Indicator / pres setpoint drift DP of 30 lbs. seal injection indicators, Hi pres tain seal inject, flow. ' Controller; readings flow will increase, charging indic. from PI-212, Spring check valve, CH-PDIC-240 line pressure will increase CH-240 position 435 will open to main-indicator tain charging flow if necessary. Amendment No. 7 Ma 1, 1982
l i 1 i G G G f TABLE 9.3-7 (Continued) (Sheet 49 of 100) CHEMICAL AND VOLUME CONTROL SYSTEM (CVCS) l a FAILURE MODE AND EFFECTS ANALYSIS ; 6 l Symptoms and Local Effects Inherent Remarks and Including Dependent Failures Method of Detection Compensating Provision Other Effects I g Name Failure Mode Cause l 165) BAMP Recircu- a) fails Mech. binding No impact on normal operation. Operator Valves CH-510 and CH-647 ( l lation Valves; open Unable to isolate recircula- provide adequate isola- ' i CH-192, CH-130 lation line for maint. on tion .' BAMP ), b) fails Mech. failure Unable to establish recircu- Operator Redundant BAMP available This valve would closed lation flow path for one be repaired before . BAMP. Possible damage to starting affected pump if it is dead headed pump. Valves , l into a closed makeup line closed only for t pumo maint. 166) BAMP Suction a) fails Mech. binding, No impact on normal operation Operator RWT is nonnal source of borated makeup water to Pool Cool- closed blockage unable to obtain borated make- , j ing and Puri- up water from PCPS ! fication System (PCPS) Isola-tion Valve; ; CH-144 b) seat Contamination. BAMP will draw suction on Spent fuel pool Redundant isolation l > leakage mech. damage spent fuel pool, gradually level indicators valve in PCPS l reducing its level. Reduced l l shielding and cooling for l spent fuel 167) BAMP Discharge a) fails Mech. failure, No impact on nonnal operation. Operator None l to PCPS closed blockage Unable to supply borated water . Isolation to spent fuel pool from RWT Valve, ; CH-753 I b) seat Contamination, Minor diversion of makeup SFP Level indica- None leakage mech. damage flow to spent fuel pool (SFP). tors. Possibly Lo , Gradual SFP level increase flow indic. from , FQRC-210Y i i )
TABLE 9.3-7 (Continued) (Sheet 50 of 100) l CHEMICAL AND VOLUME CCNTROL SYSTEM (CVCS) FAILURE MODE AND EFFECTS ANALYSIS Symptoms and Local Effects Inherent Remarks and No. Name Failure Mode Cause including Dependent Failures Method of Detection Compensating Provision Other Effects 168) RWT Gravity a) fails Mech. failure, No impact on normal operation. Valve position Alternate gravity feed Feed to closed blockage, loss Unable to supply boric acid indication in controlpath to individual Charging Pump of power. solution frcm RWT via one gra- room. charging pump suction Suction Isola- vity feed line to charging pump lines tion Valve; suction header without the BAMPs CH- 536 b) seat Contamination Diversion of boric acid Boronometer indi- None leakage trech. damage solution from RWT to RCS via cations, sample charging pumps. Possible analysis. Decreasing over boration of RCS reactor power c) fails Mech. failure Diversion of boric acid Boronometer indi- None open solution from RWT to RCS cations, sample via charging pumps. Possible analysis. Decreasing over boration of RCS. reactor power. 169) RWT Gravity a) fails Mech. failure, Same as 168 a) None Feed to Same as 168 a) closed blockage Charging Pump Suction Header Check Valve, CH-190 b) fails Mech. failure, No impact on normal operation None Isolation valve, open seat leakage CH-141 170) Boric Acid a) fails Mech. binding No impact on normal operation. Operator None Filter (BAF) open Unable to isolate BAF for Isolation element replacement Valves; CH-161, CH-166 b) fails Mech binding Unable to place BAF back in Operator Boric acid makeup closed service after maint. can continue through diversion valve CH-164 171) BAF Diversion a) fails Mechanical No impact on normal operation. Operator None Valve, closed binding, Unable to divert boric acid CH-164 blockage makeup flow past BAF when BAF element replacement needed Amendment No. 7 March 31, 1982 e G - - G
\
TABLE 9.3-8 j CHEMISTRY AND VOLUME CONTROL SYSTEM LIST OF ACTIVE VALVES j
Reference:
Figure 9.3-1, P&ID
! Task P+ID Valve
- Line Actuator
- Environmental * -
Number Coordinates Type Size (in) Type _ Design Criteria CH 118 C3 C 4.00 N C(I) CH-190 B3 C 3.00 N C II) CH-305 88 C 20.00 N C, D CH-306 C7 C 20.00 N C, D j CH-328 B2 C 2.00 N C II) CH-331 E2 C 2.00 N C II) CH-334 G2 C 2.00 N C(I) CH-440 C2 C 2.00 N C II) CH-505 G7 D 1.00 N C(I) CH-506 G7 D 1.00 N A-1, A-2, B
\j CH-530 B8 T 20.00 M C, D CH-531 C8 T 20.00 M C, D j
Reference:
Figure 9.3-2, P&ID 7 CH-494 H7 C 1.50 N A-1, A-2, B j CH-560 D7 G 3.00 D A-1, A-2, B ! CH-561 D7 G 3.00 D C(I) l CH-580 H6 G 1.50 D C(I)
Reference:
Figure 9.3-4, P&ID CH-203 H7 G 2.00 S A-1, A-2, B CH-205 G7 G 2.00 S A-1, A-2, B l CH-240 G6 G 2.50 D A-1, A-2, B j CH-255 F3 G 1.50 M C(I) CH-431 G6 C 2.00 N A-1, A-2, B CH-433 G6 C 2.50 N A-1, A-2, B CH-515 H8 G 2.00 D A-1, A-2, B CH-516 H8 G 2.00 D A-1, A-2, B Ameldment No. 7 March 31, 1982 l l
TABLE 9.3-8 (Cont'd) p,eference: Figure 9.3-4, P&ID (Cont'd) Task P+ID Valve
- Line Actuator
- Environmental
- Humber Coordinates _ Type Size (in) Type Design Criterp CH-523 E8 G 2.00 D C(I)
CH-524 E8 G 2.50 M C(I) CH-639 D8 C 2.50 N C(I) CH-787 H1 C 1.00 N A-1, A-2, B CH-802 G1 C 1.00 N A-1, A-2, B CH-807 F1 C 1.00 N A-1, A-2, B CH-812 El C 1.00 N A-1, A-2, B 7 CH-835 F2 C 1.50 N A-1, A-2, B I CH-866 H1 C 1.00 N A-1, A-2, B CH-867 G1 C 1.00 N A-1, A-2, B CH-868 F1 C 1.00 N A-1, A-2, B CH-869 El C 1.00 N A-1, A-2, B ! O o Refer to Table 1.1-1 for definition of Symbols; Appendix 3.11 A for Environmental Design Criteria Legend Note (1): C, F, G required if valve in annulus building (2): See Section 3.11 for the extent of environmental qualification testing. Amendment No. March 31, 1982
-. .. =. - . . -
f I TABLE 15.0-6 (Cont'd) N f PRESSURIZER LEVEL CONTROL SYSTEM
- 24. Backup Charging Pump Fails to Turn On
- 25. Backup Charging Pump Fails to Turn Off
- 26. Letdown Flow Control Valve Fails to Close 1 27. Letdown Flow Control Valve Fails to Open MAIN FEEDWATER SYSTEM l 28. One MFIV Fails to Close
- 29. One Back-flow Check Valve Fails to Close i MAIN STEAM SYSTEM
- 30. One MSIV Fails to Close i 31. One Atmospheric Dump Valve Fails to Open
- 32. One MSSV Fails to Reclose EMERGENCY FEEDWATER SYSTEM 5 33. Failure of Any One Emergency Feed Pump to Start EMERGENCY CORE COOLING SYSTEM
- 34. Failure of One HPSI or LPSI Pump j ELECTRICAL POWER SOURCES
- 35. Loss of Offsite Power After Turbine Trip i
- 36. Failure of One Emergency Generator to Start, Run, or Load 4 37. Failure of One Breaker to Achieve Fast Transfer to Backup Power Supply i
l 4 L l j I i Amendment No. 7 March 31, 1982 2
O I i THIS PAGE INTENTIONALLY BLANK. O' l l l O
l EFFECTIVE PAGE LISTING ! CHAPTER 10 Table of Contents Page Amendment , i 6 ii iii iv Text Page_ Amendment 10.3-1 10.3-2 5 10.3-2(a) 5 10.3-3 6 10.4 1 l 10.4-2 4 10.4-3
@ Tables j Amendment 10.3.4-1 5 1 10.3.4-2 5 l
i Figures Amendment 10.3.4-1 I I i l l l l I I
. Amendment No. 7 '
! March 31, 1982 l
(Sheet 1 of 2) EFFECTIVE PAGE LISTING CHAPTER 11 Table of Contents Page Amendment i l ii 6 Text Page Amendment 11.1-1 6 11.1-2 6 11.1-3 11.1-4 11.1-5 11.1-6 11.1-7 11.1-8 11.1-9 6 11.1-10 11.1-11 11.1-12 11.1-13 1 11.1-13(a) 6 ll.1-13(b) 1 11.1-13(c) 1 ll.1-13(d) 6 11.1-14 11.1-15 , Tables Amendment 11.1.1-1 (Sheets 1 and 2) 6 11.1.1-2 6 11.1.1-3 11.1.2-1 11.1.2-2 (Sheets 1 and 2) 11.1.2-3 11.1.2-4 11.1.2-5 (Sheets 1 and 2) 11.1.2-6 11.1.2-7 11.1.2-8 11.1.2-9 < 11.1.3-1 11.1.3-2 l 11.1.3-3 Amendment No. 7 March 31,1982
l (Steet 2 of 2) EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 11 Tables (Cont'd) Amendment 11.1.3-4 (Sheets 1-3) 11.1.6-1 11.1.7-1 6 11.1.7-2 (Sheet 1) 6 (Sheet 2) 11.1.8-1 6 11.1.9-1 (Sheets 1 and 2) 6 11.1.9-2 6 O l Amendment No. 7 March 31, 1982
/' ' TABLE OF CONTENTS CHAPTER 11 Section Subject Page No.
11.0 RADI0 ACTIVE WASTE MANAGEMENT 11.1-1 11.1 SOURCE 11.1-1 11.1.1 DESIGN BASIS SOURCE TERMS 11.1-1 11.1.1.1 Maximum Fission Product Activities in 11.1-1 Reactor Coolant 11.1.1.2 Normal Operating Source Terms Including 11.1-3 Anticipated Operational Occurrences 11.1.2 DEPOSITED CRUD ACTIVITIES 11.1-4 11.1.3 TRITIUM PRODUCTION IN REACTOR COOLANT 11.1-7 11.1.3.1 Activation Sources of Tritium 11.1-7
,~ 11.1.3.2 Tritium From Fission 11.1-7 \- /# 11.1.4 NEUTRON ACTIVATION PRODUCTS 11.1-9 11.1.4.1 Nitrogen-16 Activity 11.1-9 11.1.4.2 Carbon-14 Production 11.1-9 11.1.5 FUEL EXPERIENCE 11.1-10 11.1.6 LEAKAGE SOURCES 11.1-11 11.1.7 SPENT FUEL P0OL FISSION PRODUCT AND CORROSION 11.1-12
- PRODUCT ACTIVITIES l
l 11.1.8 STEAM GENERATOR ACTIVITY MODEL 11.1-13 i 11.1.9 RADWASTE SYSTEMS 11.1-13 1 APPENDIX CORE RESIDENCE TIMES ll.A-1 1 ll.1-A Amendment No. 1 i February 20, 1981
LIST OF TABLES
~
CHAPTER 11 Table Subject 11.1.1-1 Basis for Reactor Coolant Fission Product Activities 11.1.1-2 Maximum Activities in the Reactor Coolant Due to Continuous Operation at 4100 Mwt with One Percent Failed Fuel 11.1.1-3 Reactor Coolant System Activities During Nonnal Operations Including Anticipated Operational Occurrences 11.1.2-1 Long-Lived Isotopes in Crud 11.1.2-2 Measured Radioactive Crud Activity (dpm/mg-crud) 11.1.2-3 System Parameters 11.1.2-4 System Parameters 11.1.2-5 Average and Minimum Residence Times, Days 11.1.2-6 Assumed System Parameters, System 80 11.1.2-7 Long-Lived Crud Activity for a Standard 3817 Mwt Plant 11.1.2-8 Average Calculated Reactor Coolant Crud Activity 11.1.2-9 Equilibrium Crud Film Thickness 11.1.3-1 Tritium Activation Reactions 11.1.3-2 Parameters Used in Tritium Production Determination 11.1.3-3 Tritium Production in Reactor Coolant 11.1.3-4 Tritium Production and Release at Operating PWR's 11.1.6-1 Leakage Assumptions From C-E Supplied Equipment 11.1.7-1 Maximum Fission and Corrosion Product Activities in the Spent Fuel Pool 11.1.8-1 Basis for Steam Generator Liquid Activities 11.1.9-1 Annual Spent Resin Activity Input to SMWS 6 11.1.9-2 Specific Activities of Sources to the GWMS During Normal Operation Amendment No. 6 O November 20, 1981 ii
i O' 11.1.8 STEAM GENERATOR ACTIVITY MODEL The specific activities in the steam generator and secondary systems are to
! be discussed in the Applicant's SAR. The bases data for these activities are supplied in Tab k 11.1.8-1.
11.1.9 RADWASTE SYSTEMS I Detailed information, including references to P& ids pressures, temperatures, flow rates, and expected volumes of waste input to each of the radwaste systems is provided below. Liquid Waste Management System (LWMS)
- 1. Chemical addition package strainer drain (Zone G-5 of Figure 9.3-1.).
Flow 0-10 gpm Chemical Nature Primary grade water and 2060 ppm LiOH(max) l Pressure 25 psig j Temperature 40-120 F I i
- 2. Supply to LWMS waste condensate tank (Zone D-5 of Figure 9.3-3).
Flow 0-20 gpm 3 Chemical Nature Primary grade makeup water 'f ' Temperature Pressure 120-130'F 55 psig
- 3. Supply to LWMS waste concentrator (Zone G-7 of Figure 9.3-3).
Flow 0-20 gpm Chemical Nature Primary water Temperature 40-90 F Pressure 60 psig
- 4. BAC Drains (Zone D-5 of Figure 9.3-3).
Flow 0-20 gpm Chemical Nature Primary water and component cooling water Temperature 40-200 F Pressure ATM Solid Waste Management System (SWMS)
- 1. Ion exchanger resin sluicing lines (Zones A-1, C-4, and G-5 of Figures 9.3-4, 9.3-2, and 9.3-3, respectively) .
O Amendment No. 1 11.1-13 February 20, 1981
Flow 100 gpm (max) water and 100 SCFM (max) air Chemical Nature Resin, air, reactor makeup water Pressure 75 psig Tempera ture 40-12g"F Volume of dewatered resin 36ftfionexchangersluicingoperation Volume of resin discharged 180 ft per year (based on one replacement per 6 resin bed per year) Spent resin activity input to SWMS per Table 11.1.9-1 year
- 2. Strainer blowdown lines (Zones A-1, F-4, and G-5 of Figures 9.3-4, 9.3-2 and 9.3-3, respectively)
Flow 10 gpm Chemical Nature Resin slurry Pressure 50 psig Temperature 40-120 F
- 3. Boric acid concentrator concentrate discharge to SWMS (Zone B-5 of Figure 9.3-3).
Continuous: Flow 0-20 gpm 12 wt % boric acid (max) Tempera ture 160-180 F Pressure 55 psig Batch: Flow 20 gpm 12 wt % buric acid (max) Temperature 160-180 F Pressure 55 psig Volume 2000 gallons (max)
- 4. The Solid Waste Management System shall be capable of receiving the following quantities of spent filter cartridges or equivalent each year:
Replacement Frequency Waste Volume 3 Seal injection filters 2 4.18 ft 3 Purification filters 4 16.72f3 2.09 ft Boric acid filters 1 3 Reactor drain filters 1 2.09 ft 3 Reactor makeup filters 1 2.09 ft Gas Waste Management System (GWMS)* l6
- 1. Purification and deborating ion exchanger vent (Zone D-1 of Figure 9.3-4; one ion exchanger vent rate / year).
Flow 0-20 scfm Chemical Nature Air Tempera ture 40-120 F Pressure 0 psig Volume 170 scf/ year Amendment No. 6 11.1-13a November 20, 1981
l 1 EFFECTIVE PAGE LISTING
- CHAPTER 11 l APPENDIX 11.1-A.
i ' Table of Contents I 1
; Page Amendment
- ! j Text 1
Page Amendment l 11.A-1 6 11.A-2 6 11.A-3 ) i j 1 l i l I i I i l l l 9 Amendment No. 7 March 31, 1982 i e . _ _ _. - - _ _
- EFFECTIVE PAGE LISTING 1
l CHAPTER 12 _ Table of Contents
! Page Amendment ,
I i 1 ! ) ii 1 ! l - Text i Page. Amendment j 12.1-1 1 1 12.1-2 1 J 12.1-3 1 j 12.2-1 1
- 12.2-1(a) 1
! 12.2-2 12.2-3
- 12.2-4 1 12.3-1 1 12.3-2
- 12.3-3 1
! 12.3-4 1 ! 12.3-5 1 i Tables l Amendment l ! 12.2-1 ! 12.2-2 ( 12.2-3 12.2-4 12.2-5 12.2-6 (Sheets 1 and 2) 12.2-7 12.2-8 (Sheets 1 and 2) 12.2-9 12.2-10 (Sheets 1 and 2) 12.2-11 1 O Amendment No. 7 March 31,1982
4 1 i f : i f 1 EFFECTIVE PAGE LISTING 1 , I CHAPTER 13 I i' 1 Table of Contents 1 1 l Page Amendment ! q. i I 1 Text ' l i 1 Page Amendment l
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t (Sheet 1 of 4) EFFECTIVE PAGE LISTING CHAPTER 14 Table of Contents
- Page Amendment i 6 ii 6 iii iv V
vi 6 Text Page Amendment 14.1-1 14.2-1 14.2-2 14.2-3 14.2-4 6 14.2-4(a) 6 14.2-5 6 14.2-5(a) 6 14.2-6 6 , 14.2-7 6 1 14.2-7(a) 6 14.2-7(b) 6 l 14.2-7(c) 6 14.2-8 6 14.2-9 6 14.2-10 6 14.2-11 6 i 14.2-12 6 l 14.2-13 6 14.2-14 6 14.2-15 6 14.2-16 6 14.2-17 6 14.2-18 - 6 14.2-19 6 14.2-20 6 l 14.2-21 6 14.2-22 6 14.2-23 6 14.2-24 6 l 14.2-25 6 14.2-26 6 14.2-27 6 14.2-28 6 Amendment No. 7 March 31, 1982 l
(Sheet 2 of 4) EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 14 Text _ (Cont'd) Page Amendmen t 14.2-29 6 14.2-30 6 14.2-31 6 14.2-32 6 14.2-33 6 14.2-34 6 l 14.2-35 6 j 14.2-36 6 14.2-36(a) 6 14.2-37 6 14.2-38 6 14.2-38(a) 6 14.2-39 6 l 14.2-40 6 14.2-41 6 ) 14.2-42 6 1 14.2-43 6 l 14.2-44 6 14.2-45 6 l 14.2-46 6 14.2-47 6 14.2-48 6 14.2-49 6 14.2-49(a) 6 14.2-50 6 14.2-51 6 14.2-52 6 14.2-53 6
- 14.2-54 6 l 14.2-55 6 l 14.2-56 14.2-57 6 l,
14.2-58 6 14.2-59 6 14.2-60 6 14.2-61 6 14.2-62 6 l, 14.2-63 6 14.2-64 6 14.2-65 6 l I 14.2-66 6 14.2-67 14.2-68 6 14.2-69 6 l 14.2-70 6 14.2-71 6 Amendment No. 7 l March 31,1982
(Sheet 3 of 4) EFFECTIVE PAGE LISTING (Cont'd)
@ CHAPTER 14 Text (Cont'd)
Page Amendment 14.2-72 6 14.2-73 6 14.2-74 6 14.2-75 6 14.2-76 6 14.2-77 6 14.2-77(a) 6 14.2-78 6 14.2-79 6 14.2-80 6 14.2-81 6 14.2-82 6 14.2-83 6 14.2-84 6 14.2-85 6 14.2-86 6 14.2-87 7 14.2-88 6 9 14.2-89(a) 14.2-90 14.2-90(a) 6 6 6 14.2-91 6 14.2-91(a) 6 14.2-92 6 14.2-93 6 14.2-94 6 14.2-95 6 14.2-96 6 14.2-97 6 14.2-98 6 14.2-99 6 ' 14.2-99(a) 7 14.2-100 7 14.2-101 6 , 14.2-102 6 14.2-103 6 Tables Amendment 14.2-1 6 , 14.2-2 (Sheets 1 and 2) 6 S 14.2-3 (Sheet 1) ' , (Sheet 2) 6 l l l Amendment No. 7 March 31,1982 l l
- . - . - - - - - _ - - - . - _ - - , - ~ . , , _ - . . _
(Sheet a of 4) EFFECTIVE PAGE LISTING (Cont'd) CHAPTER 14 Tables (Cont'd) Amendment 14.2-4 (Sheets 1 and 2) 14.2-5 14.2-6 6 14.2-7 6 i O l i l l l l O l Amendment No. 7 March 31, 1982 l l
2.2 The RRS, FWCS, SBCS, RPCS, and the pressurizer level and pressure control systems are in automatic operation. 3.0 TEST METHOD q 3.1 Load increases and decreases (steps and ramps) in accordance with the C-E Fuel Pre-conditioning Guidelines will be performed at power levels in the 90 to 100% range and with swings in the 50 to 25 to 6 50% power level. 4.0 DATA REQUIRED 4.1 Time dependent data. 4.1.1 Pressurizer level and pressure. l 4.1.2 RCS temperatures. 4.1.3 CEA position. 4.1.4 Power level and demand. 4.1.5 Steam generator levels and pressures. 4.1.6 Feedwater and steam flow. 5.0 ACCEPTANCE CRITERIA 5.1 The step and ramp transients demonstrate that the plant performs T load changes allowed by C-E's Fuel Pre-conditioning Guidelines and I data has been taken that will demonstrate the plant's ability to 6 meet unit load swing design transients. 5.2 That no audible noise or significant vibration is observed in the economizer or in the rest of the Feedwater and Emergency Feedwater 7 systems, due to water hammer. 14.2.12.5.4 Control Systems Checkout Test 1.0 OBJECTIVE l.1 To demonstrate that the automatic control systems operate satis-factorily during steady-state and transient conditions. 2.0 PREREQUISITES 2.1 The reactor is operating at the desired conditions. 2.2 The RRS, FWCS, SBCS, RPCS, and the pressurizer level and pressure controls are in automatic operation. 3.0 TEST METHOD 3.1 The performance of the control systems during normal operations, transients and trips will be monitored to demonstrate that the systems are operating satisfactorily. ( Amendment No. 7 March 31, 1982 14.2-87
4.0 DATA REQUIRED 4.1 Time dependent data. 4.1.1 Pressurizer level and pressure. 4.1.2 RCS temperatures. 4.1.3 CEA position. 4.1.4 Power level and demand. 4.1.5 Steam generator levels and pressures. 4.1.6 Feedwater and steam flow. 5.0 ACCEPTANCE CRITERIA 5.1 The control systems maintain the reactor power, RCS temperature, pressurizer pressure and level, and steam generator levels and pressures within their control bands during both steady state and l6 tralsient operation. 14.2.12.5.5 Reactor Coolant and Secondary Chemistry and Radiochemistry Test 1.0 OBJECTIVE 1.1 To conduct chemistry tests at various power levels with the intent of gathering corrosion data and determining activity buildup. 1.2 To verify proper operation of the process radiation monitor. 1.3 To verify the adequacy of sampling and analysis procedures.
- 2. 0 PREREQUISITES 2.1 The reactor i: stable at the desired power level.
2.2 Sampling systems for the RCS and CVCS are operable. 3.0 TEST METHOD 3.1 Samples will be collected from the RCS and secondary system at various power levels and analyzed in the laboratory using applicable sampling and analysis procedures. 3.2 Samples will be collected at the process radiation monitor at various power levels, analyzed in the laboratory, and compared with the process radiation monitor to verify proper operation. Amendment No. 6 November 20, 1981 14.2-88
3.0 TEST METHOD 3.1 Planar radial peaking factors are verified for various CEA configura- 16 1 tions by comparison of the CPC values with values measured with j the incore detector system. 1 3.2 The CEA shadowing factors are verified by comparing excore detector 16 responses for various CEA configurations with the unrodded excore responses. i l 3.3 The shape annealing factors are measured by comparing incore j power distributions and excore detector responses during a free
- Xe oscillation.
*3.4 The temperature annealing factors are verified by comparing core j power and excore detector responses for various RCS temperatures.
4.0 DATA REQUIRED 4.1 Conditions of the measurement. { 4.1.1 Power. 4.1.2 Burnup. 4.2 Time dependent data. 4.2.1 Incore and excore detector readings. 4.2.2 CEA position. 4.2.3 RCS temperatures. 5.0 ACCEPTANCE CRITERIA 5.1 Measured radial peaking factors determined from incore flux maps are no higher than the corresponding values used in the CPCs. 5.2 The CEA shadowing factors, and temperature annealing factors used in the CPCs agree within the acceptance criteria specified in the CPC test requirements. l6 5.3 The shape annealing matrix have been measured and the boundary point p.ower correlation constants used in the CPCs are within the limits specified by the test requirements.** 6
*This test will be performed only on the "first-of-a-kind" plant.
**As specified in the appropriate revisions or supplements of CEN 63A. l6 d
Amendment NO. 6 14.2-99 November 20, 1981 i _ _ _ _ . - . _ _ , _ , .. __ _ ...,-_..,__.,._.m- , , , . . . , , - - -,.,... , , _ _ _ _ _ - ~ _ . _ _
14.2.12.5.17 Main and Emergency Feedwater Systems Test 1.0 OBJECTIVE 1.1 To demonstrate that the operation of the main feedwater and emergercy feedwater systems during Hot Standby, Startup and other normal .7 operations, transients, and plant trips is satisfactory. O l i t i Amendment No. 7 March 31, 1982 l O l 14.2-99a
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2.0 PREREQUISITES 2.1 The SBCS, FWCS, RRS, RPCS, and pressurizer pressure and level 7 controls are operable in either manual or automatic modes. 3.0 TEST MET}iOD 3.1 Performance of the feedwater systems will be monitored during normal operation, transients, and trips. 4.0 DATA REQUIRED 4.1.1 Reactor power 4.1.2 RCS temperatures 4.1.3 Pressurizer pressure 4.1.4 Steam generator levels and pressures 4.1.5 Steam and feedwater flows 5.0 ACCtPTANCE CRITERIA 5.1 The main and emergency feedwater systems perform as designated by the system description. 5.2 No audible noise or vibration is observed during design operation, 7 due to water hammer. 14.2.12.5.18 CPC Verification 1.0 OBJECTIVE To verify DNBR and Local Power Density (LPD) calculations of the CPCs. 2.0 PREREQUISITES 2.1 The reactor is at the desired power level and CEA configuration with equilbrium Xe. 2.2 The CPCs are operational. i 2.3 The incore detector system is operational. 3.0 TEST METHOD 3.1 Specified values are recorded from the CPCs. 3.2 The values for LPD and DNBR obtained from the CPCs are compared i with the values calculated for the same conditions using the l i CPC FORTRAN Simulator. Amendment No. 7 M rch 31, 1982 14.2-100
O i L 1 1 i CHAPTER 15 l ! ACCIDENT ANLAYSES i i l l l O l i l l l l Chapter 15 and its appendices are completely replaced in Amendemnt No. 7. Due to the effort required to revise the format from the original submittal, previous amendments were submitted as interim documents. Therefore., revision lines are not shown on the revised pages. O Amendment No. 7 L1 arch 31, 1982
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i ) (Sheet 1 of 12) EFFECTIVE PAGE LISTING CHAPTER 15 i Table of Contents ; a Page Amendment -, 1 7 l 11 7 4 iii 7 i iv 7 i V 7 vi 7 vii 7 viii 7 ix 7 , x 7 x1 7
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(Sheet 2 of 12) EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Table of Contents Page Amendment 15.1-1 7 15.1-2 7 15.1-3 7 15.1-4 7 15.1-5 7 15.1-6 7 15.1-7 7 15.1-8 7 15.1-9 7 15.1-10 7 15.1-11 7 15.1-12 7 15.1-13 7 15.1-14 7 15.1-15 7 15.1-16 7 15.1-17 7 15.2-1 7 15.2-2 7 15.2-3 7 15.2-4 7 15.2-5 7 15.2-6 7 15.2-7 7 15.2-8 7 15.2-9 7 15.2-10 7 15.3-1 7 15.3-2 7 15.3-3 7 15.3-4 7 15.3-5 7 15.3-6 7 15.3-7 7 15.3-8 7 15.3-9 7 15.3-10 7 15.3-11 7 15.3-12 7 15.3-13 7 15.3-14 7 15.3-15 7 Amendment No. 7 March 31, 1982
1 i l (Sneet 3 of 12) ~ EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 l l Table of Contents Page Amendment 1 15.4-1 7 15.4-2 7 15.4-3 7 15.4-4 7 15.4-5 7 15.4-6 7 15.4-7 7 15.4-8 7 15.4-9 7 15.4-10 7 i 15.4-11 7 15.4-12 7 15.4-13 7 15.4-14 7 15.4-15 7 15.4-16 7 15.4-17 7 i 9 15.4-18 15.4-19 15.4-20 15.4-21 7 7 7 7 15.4-22 7 15.5-1 7 15.5-2 7 15.5-3 7 15.5-4 7 15.5-5 7 15.5-6 7 15.6-1 7 15.6-2 7 15.6-3 7 15.6-4 7 15.6-5 7 15.6-6 7 15.6-7 7 15.6-8 7 15.6-9 7 15.6-10 7 15.6-11 7 15.6-12 7 15.6-13 7 Amendment No. 7 March 31, 1982
(Sheet 4 of 12) EFFECTIVE PAGE LISTIf1G (Cont'd.) CHAPTER 15 Table of Contents Page Amendment 15.6-14 7 15.6-15 7 15.6-16 7 15.6-17 7 15.6-18 7 15.6-19 7 15.6-20 7 15.6-21 7 15.7-1 7 15.7-2 7 15.7-3 7 Tables Table No. Amendment 15.0-1 7 15.0-2 7 15.0-3 7 15.0-4 7 15.0-5 7 15.0-6 7 15.1.4-1 7 15.1.4-2 7 15.1.4-3 7 l 15.1.5-1 7 15.1.5-2 7 l 15.1.5-3 7 15.1.5-4 7 15.1.5-5 7 15.1.5-6 7 15.1.5-7 7 15.1.5-8 7 15.1.5-9 7 15.1.5-10 7 l 15.1.5-11 7 15.2.3-1 7 15.2.3-2 7 15.2.3-3 7 15.2.3-4 7 Amendment No. 7 March 31, 1982
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) 15.6.2-2 7 15.6.2-3 7 ?l 15.6.2-4 7 1 15.6.2-5 7 Amendment No. 7 March 31, 1982 4
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(Sheet 6 of 12) EFFECTIVE PAGE LISTIflG (Cont'd.) CHAPTER 15 Tables Table fio. Amendment 15.6.3-1 7 15.6.3-2 7 15.6.3-3 7 15.6.3-4 7 15.6.3-5 7 15.6.3-6 7 15.6.3-7 7 15.6.3-8 7 15.6.3-9 7 15.6.3-10 7 15.6.5-1 7 15.7.4-1 7 Figures Figure fio. Amendment 15.0-1 (sheets A,B,C) 7 15.1.4-1.1 7 15.1.4-1.2 7 15.1.4-1.3 7 15.1.4-1.4 7 15.1.4-1.5A 7 15.1.4-1.5B 7 15.1.4-1.6 7 ! 15.1.4-1.7 7 15.1.4-1.8 7 15.1.4-1.9 7 15.1.4-1.10 7 , 15.1.4-1.11 7 l 15.1.4-1.12 7 15.1.4-1.13 7 15.1.4-1.14 7 15.1.4-1.15 7 l 15.1.4-2.1 7 15.1.4-2.2 7 15.1.4-2.3 7 15.1.4-2.4 7 15.1. 4 -2. 5A 7 ! 15.1. 4 -2. 5B 7 15.1.4-2.6 7 Amendment fio. 7 March 31, 1982
(Sheet 7 of 12) EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Figures Fiqure No. Amendment 15.1.4-2.7 7 15.1.4-2.8 7 15.1.4-2.9 7 15.1.4-2.10 7 15.1.4-2.11 7 15.1.4-2.12 7 15.1.4-2.13 7 15.1.4-2.14 7 15.1.4-2.15 7 15.1.5-1.1 7 15.1.5-1.2 7 15.1.5-1.3 7 15.1.5-1.4 7 15.1.5-1.5A 7 15.1.5-1.5B 7 15.1.5-1.6 7 15.1.5-1.7 ( 15.1.5-1.8 7 7 15.1.5-1.9 7 15.1.5-1.10 7 15.1.5-1.11 7 15.1.5-1.12 7 15.1.5-1.13 7 15.1.5-1.14 7 15.1.5-1.15 7 15.1.5-1.16 7 15.1.5-2.1 7 15.1.5-2.2 7 15.1.5-2.3 7 15.1.5-2.4 7 15.1.5-2.5A 7 15.1.5-2.5B 7 15.1.5-2.6 7 15.1.5-2.7 7 15.1.5-2.8 7 15.1.5-2.9 7 15.1.5-2.10 7 15.1.5-2.11 7 15.1.5-2.12 7 15.1.5-2.13 7 15.1.5-2.14 7 s 15.1.5-2,15 7 1 Amendment No. 7 March 31, 1982
(Sheet 8 of 12) O EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Figures Figure No. Amendment 15.1.5-3.1 7 15.1.5-3.2 7 15.1.5-3.3 7 15.1.5-3.4 7 15.1.5-3.5A 7 15.1.5-3,58 7 15.1.5-3.6 7 15.1.5-3.7 7 15.1.5-3.8 7 15.1.5-3.9 7 15.1.5-3.10 7 15.1.5-3Al 7 15.1.5-3.12 7 15.1.5-3.13 7 15.1.5-3.14 7 15.1.5-3.15 7 15.1.5-4.1 7 15.1.5-4.2 7 15.1.5-4.3 7 15.1.5-4.4 7 15.1.5-4.5A 7 15.1.5-4.5B 7 15.1.5-4.6 7 15.1.5-4.7 7 15.1.5-4.8 7 15.1.5-4.9 7 15.1.5-4.10 7 15.1.5-4.11 7 15.1.5-4.12 7 15.1.5-4.13 7 15.1.5-4.14 7 15.1.5-4.15 7 15.1.5-5.1 7 15.1.5-5.2 7 15.1.5-5.3 7 15.1.5-5.4 7 15.1.5-5.5 7 15.1.5-5.6 7 15.1.5-5.7 7 15.1.5-5.8 7 15.1.5-5.9 7 Amendment No. 7 March 31, 1982
! i (Sheet 9 of 12) i f EFFECTIVE PAGE-LISTING (Cont'd.) ! CHAPTER 15 Figures l Figure No. Amendment i 1' - 15.2.3-1 (sheets A,B,C) 7 15.2.3-2 7
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(Sheet 10 of 12) EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Figures Figure No. Amendment 15.4.2-1 (sheets A,B,C,D) 7 15.4.2-2 7 15.4.2-3 7 15.4.2-4 7 15.4.2-5 7 15.4.2-6 7 15.4.2-7 7 15.4.2-8 7 15.4.2-9 7 15.4.2-10 7 15.4.2-11 7 15.4.2-12 7 15.4.3-2 7 15.4.3-3 7 15.4.3-4 7 15.4.3-5 7 15.4.3-6 7 15.4.3-7 7 15.4.3-8 7 15.4.3-9 7 15.4.3-10 7 15.4.3-11 7 15.4.3-12 7 15.4.3-13 7 15.4.6-1 7 15.4.7-1 7 15.4.8-1 (sheets A,B,C,D,E,F) 7 15.4.8-2 7 15.4.8-3 7 15.4.8-4 7 15.4.8-5 7 15.4.8-6 7 15.4.8-7 7 15.4.8-8 7 15.4.8-9 7 15.4.8-10 7 15.4.8-11 7 15.4.8-12 7 15.4.8-13 7 15.5.2-1 (sheets A,B,C,D) 7 15.5.2-2 7 Amendment No. 7 March 31, 1982
(Sheet 11 of 12) EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Figures Figure No. Amendment 15.5.2-3 7 15.5.2-4 7 15.5.2-5 7 15.5.2-6 7 15.5.2-7 7 15.5.2-8 7 15.5.2-9 7 15.5.2-10 7 15.5.2-11 7 15.6.2-1 (sheets A,B,C) 7 15.6.2-2 7 15.6.2-3 7 15.6.2-4 7 15.6.2-5 7 15.6.2-6 7 15.6.2-7 7 ( 15.6.2-8 15.6.2-9 7 7 15.6.2-10 7 15.6.2-11 7 15.6.2-12 7 15.6.2-13 7 15.6.2-14 7 15.6.3-1 (sheets A,B,C,0) 7 15.6.3-2 7 15.6.3-3 7 15.6.3-4 7 15.6.3-5 7 15.6.3-6 7 15.6.3-7 7 15.6.3-8 7 15.6.3-9 7 15.6.3-10 7 15.6.3-11 7 15.6.3-12 7 15.6.3-13 7 15.6.3-14 7 15.6.3-15 7 15.6.3-16 7 n' 15.6.3-17 7 ( 15.6.3-18 (sheets A,B,C,0) 7 15.6.3-19 7 Amendment No. 7 March 31, 1982 ..-_ _ _ _ - - _ _ _ . - - - - - - __ J
(Sheet 12 of 12) EFFECTIVE PAGE LISTING (Cont'd.) CHAPTER 15 Figures Figure No. Amendment 15.6.3-20 7 15.6.3-21 7 15.6.3-22 7 15.6.3-23 7 15.6.3-24 7 15.6.3-25 7 15.6.3-26 7 15.6.3-27 7 15.6.3-28 7 ' 15.6.3-29 7 15.6.3-30 7 15.6.3-31 7 15.6.3-32 7 15.6.3-33 7 15.6.3-34 7 O Amendment No. 7 March 31, 1982
TABLE OF CONTENTS Chapter 15 O Section Subject Page No.
- 15. ACCIDENT ANALYSES 15.0 ORGANIZATION AND METHODOLOGY 15.0-1 15.0.1 CLASSIFICATION OF TRANSIENTS AND ACCIDENTS 15.0-1 15.0.1.1 Format and Content 15.0-1 15.0.1.2 Event Categories 15.0-1 15.0.1.3 Event Frequencies 15.0-1 15.0.1.4 Events and Event Combinations 15.0-2 l 15.0.1.5 Section Numbering 15.0-2 15.0.1.6 Sequence of Events Analysis 15.0-2 15.0.2 SYSTEMS OPERATION 15.0-4 i 15.0.3 CORE AND SYSTEM PERFORMANCE 15.0-5 15.0.3.1 Mathematical Model 15.0-5 15.0.3.1.1 Loss of Flow Analysis Method 15.0-5 15.0.3.1.2 CEA Ejection Analysis Method 15.0-5 15.0.3.1.3 CESEC Computer Program 15.0-5 15.0.3.1.4 C0AST Computer Program 15.0-6 15.0.3.1.5 STRIKIN-II Computer Program 15.0-6 15.0.3.1.6 TORC Computer Program 15.0-7 15.0.3.1.7 Reactor Physics Computer Programs 15.0-7 15.0.3.2 Initial Condition 15.0-7 15.0.3.3 Input Parameters 15.0-7 15.0.3.3.1 Doppler Coefficient 15.0-7 15.0.3.3.2 Moderator Temperature Coefficient 15.0-8 15.0.3.3.3 Shutdown CEA Reactivity 15.0-8
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Amendment No. 7 i March 31, 1982
TABLE OF CONTENTS (Continued) Chapter 15 Section Subject Page No. 15.0.3.3.4 Effective Delayed Neutron Fraction 15.0-9 15.0.3.3.5 Decay Heat Generation Rate 15.0-9 15.0.4 RADIOLOGICAL CONSEQUENCES 15.0-9 15.1 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 15.1-1 15.1.1 DECREASE IN FEEDWATER TEMEPRATURE 15.1.1 15.1.1.1 Identification of Event and Causes 15.1-1 15.1.1.2 Sequence o# Events and System Operations 15.1-1 15.1.1.3 Analysis of Effects and Consequences 15.1-1 15.1.1.4 Conclurions 15.1-1 15.1.2 INCREASE IN FEEDWATER FLOW 15.1-2 15.1.2.1 Identification of Event and Causes 15.1-2 15.1.2.2 Sequence of Events and System Operations 15.1-2 15.1.2.3 Analysis of Effects and Consequences 15.1-2 15.1.2.4 Conclusions 15.1-2 15.1.3 INCREASED MAIN STEAM FLOW 15.1-3 15.1.3.1 Identification of Event and Causes 15.1-3 15.1.3.2 Sequence of Events and System Operations 15.1-3 15.1.3.3 Analysis of Effects and Consequences 15.1-3 15.1.3.4 Conclusions 15.1-3 15.1.4 INADVERTENT OPENING 0FA STEAM GENERATOR RELIEF OR SAFETY VALVE 15.1-4 15.1.4.1 Identification of Event and Causes 15.1-4 15.1.4.2 Sequence of Events and System Operations 15.1 4 15.1.4.3 Analysis of Effects and Consequences 15.1-6 15.1.4.4 Conclusions 15.1-8 Amendment No. 7 ii March 31, 1982
i 1
! TABLE OF CONTENTS (Continued)
Chapter 15 U Section Subject Page No. 15.1.5 STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE CONTAINMENT 15.1-10 15.1.5.1 Identification of Event and Causes 15.1-10 15.1.5.2 Sequence of Events and System Operations 15.1-11 15.1.5.3 Analysis of Effects and Consequences 15.1-12 ! 15.1.5.4 Conclusions 15.1-16 l 15.2 DECREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 15.2-1 15.2.1 LOSS OF EXTERNAL LOAD 15.2-1 15.2.1.1 Identification of Event and Causes 15.2-1 15.2.1.2 Sequence of Events and System Operations 15.2-1 15.2.1.3 Analysis of Effects and Consequences 15.2-1 15.2.1.4 Conclusions 15.2-1 - 15.2.2 TURBINE TRIP 15.2-2 15.2.2.1 Identification of Event and Causes 15.2-2 15.2.2.2 Sequence of Events and System Operations
^
l 15.2-2 15.2.2.3 Analysis of Effects and Consequences 15.2-2 15.2.2.4 Conclusions 15.2-2 15.2.3 LOSS OF CONDENSER VACUUM 15.2-3 15.2.3.1 Identification of Event ar.d Causes 15.2-3 15.2.3.2 Sequence of Events and System Operations 15.2-3 15.2.3.3 Analysis of Effects and Consequences 15.2-5 l 15.2.3.4 Conclusions 15.2-6 ] 15.2.4 MAIN STEAM ISOLATION VALVE CLOSURE 15.2-7 15.2.4.1 Identification of Event and Causes 15.2-7 15.2.4.2 Sequence of Events and Systen Operations 15.2-7
... Amendment No. 7 "I March 31, 1982
TABLE OF CONTENTS (Continued) Chapter 15 Section Subject Page No. 15.2.4.3 Analysis of Effects and Consequences 15.2-7 15.2.4.4 Conclusions 15.2-7 15.2.5 STEAM PRESSURE REGULATOR FAILURE 15.2-7 15.2.6 LOSS OF NON-EMERGENCY A-C POWER TO THE STATION AUXILIARIES 15.2-8 15.2.6.1 Identification of Event and Causes 15.2-8 15.2.6.2 Seauence of Events and System Operations 15.2-8 15.2.6.3 Analysis of Effects and Consequences 15.2-8 15.2.6.4 Conclusions 15.2-9 15.2.7 LOSS OF NORMAL FEEDWATER FLOW 15.2-9 15.2.7.1 Identification of Event and Causes 15.2-9 15.2.7.2 Sequence of Events and System Operations 15.2-9 15.2.7.3 Analysis of Effects and Consequences 15.2-9 15.2.7.4 Conclusions 15.2-10 15.2.8 FEEDWATER SYSTEM PIPE BREAKS 15.2-10 15.3 DECREASE IN REACTOR COOLANT FLOW RATE 15.3-1 15.3.1 TOTAL LOSS OF REACTOR COOLANT FLOW 15.3-1 15.3.1.1 Identification of Event and Causes 15.3-1 15.3.1.2 Sequence of Events and System Operations 15.3-2 15.3.1.3 Analysis of Effects and Consequences 15.3-4 15.3.1.4 Conclusions 15.3-5 l l 15.3.2 FLOW CONTROLLER MALFUNCTION CAUSING FLOW C0ASTDOWN 15.3-6 ; 15.3.3 SINGLE REACTOR COOLANT PUMP ROTOR SEIZURE WITH LOSS OF 0FFSITE POWER 15.3-6 15.3.3.1 Identification of Event and Causes 15.3-6 iv Amendment No. 7 March 31, 1982
TABLE OF CONTENTS (Continued) Chapter 15 [j\
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Section Subject Page No. 15.3.3.2 Sequence of Events and System Operations 15.3-7 15.3.3.3 Analysis of Effects and Consequences 15.3-9 ' 15.3.3.4 Conclusions 15.3-13 15.3.4 REACTOR COOLANT PUMP SHAFT BREAK WITH LOSS OF 0FFSITE POWER 15.3-14 15.3.4.1 Identification of Event and Causes 15.3-14 15.3.4.2 Sequence of Events and System Operations 15.3-14 15.3.4.3 Analysis of Effects and Consequences 15.3-14 15.3.4.4 Conclusions 15.3-15 15.4 REACTIVITY AND POWER DISTRIBU110N ANOMALIES 15.4-1 15.4.1 UNCONTROLLED CONTROL ELEMENT ASSEMBLY WITHDRAWAL
,_s FROM A SUBCRITICAL OR LOW POWER CONDITION 15.4-1 \s_,) 15.4.1.1 Identification of Event and Causes 15.4-1 15.4.1.2 Sequence of Events and System Operations 15.4-1 15.4.1.3 Analysis of Effects and Consequences 15.4-2 15.4.1.4 Conclusions 15.4-3 15.4.2 UNCONTROLLED CONTROL ELEMENT ASSEMBLY WITHDRAWAL AT POWER 15.4-4 15.4.2.1 Identification of Event and Causes 15.4-4 15.4.2.2 Sequence of Events and System Operations 15.4-4
- 15.4.2.3 Analysis of Effects and Consequences 15.4-5 15.4.2.4 Conclusions 15.4-6 15.4.3 SINGLE FULL LENGTH CONTROL ELEMENT ASSEMBLY DROP 15.4-7 15.4.3.1 Identification of Event and Causes 15.4-7 15.4.3.2 Sequence of Events and System Operations 15.4-7
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s) 15.4.3.3 Analysis of Effects and Consequences 15.4-7 ( v Amendment No. 7 March 31, 1982
TABLE OF CONTENTS (Continued) Chapter 15 Section Subject Page No. 15.4.3.4 Conclusions 15.4-9 16.4.4 START UP 0F AN INACTIVE REACTOR COOLANT PUMP 15.4-10 15.4.4.1 Identification of Event and Causes 15.a-10 15.4.4.2 Sequence of Events and System Operations 15.4-10 15.a.4.3 Analysis of Effects and Consecuences 15.4-10 15.4.a.4 Conclusions 15.4-10 15.4.5 FLOW CONTROLLER MALFUtlCTION CAUSING AN INCREASE IN BWR CORE FLOW 15.4-11 15.4.6 INADVEP,TEllT DEB 0 RATION 15.4-11 15.4.6.1 Identification of Event and Causes 15.4-11 15.4.6.2 Sequence of Events and System Operations 15.4-12 15.4.6.3 Analysis of Effects and Consequences 15.4-12 15.4.6.4 Conclusions 15.4-14 15.4.7 IllADVERTENT LOADING OF A FUEL ASSEMBLY INTO THE IMPROPER POSITION 15.4-15 15.4.7.1 Identification of Event and Causes 15.4-15 15.4.7.2 Sequence of Events and System Operations 15.4-15 15.4.7.3 Analysis of Effects and Consequences 15.4-16 15.a.7.4 Conclusions 15.4-16 15.4.8 CONTROL ELEMENT ASSEMBLY (CEA) EJECTION 15.4-17 15.4.8.1 Identification of Event and Causes 15.4-17 15.4.8.2 Sequence of Events and System Operations 15.4-17 15.4.8.3 Analysis of Effects and Consequences 15.4-19 15.4.8.4 Conclusions 15.4-21 15.5 INCREASE IN RCS INVENTORY 15.5-1 vi Amendment No. 7 March 31, 1982
TABLE OF CONTENTS (Continued) IC Chapter 15 Section Subject Page No. 15.5.1 INADVERTENT OPERATION OF THE ECCS 15.5-1 15.5.1.1 Identification of Event and Causes 15.5-1 15.5.1.2 Sequence of Events and System Operations 15.5-1 15.5.1.3 Analysis of Effects and Consequences 15.5-1 15.5.1.4 Conclusions 15.5-1 15.5.2 CVCS MALFUNCTION-PRESSURIZER LEVEL CONTROL SYSTEM MALFUNCTION WITH LOSS OF 0FFSITE POWER 15.5 1 15.5.2.1 Identification of Event and Causes 15.5-1 15.5.2.2 Sequence of Events and System Operations 15.5-3 15.5.2.3 Analysis of Effects and Consequences 15.5-5 15.5.2.4 Conclusions 15.5-6 15.6 DECREASE IN REACTOR COOLANT SYSTEM INVENTORY 15.6-1 15.6.1 INADVERTENT OPENING OF A PRESSURIZER SAFETY / RELIEF VALVE 15.6-1 15.6.2 DOUBLE-ENDED BREAK OF A LETDOWN LINE OUTSIDE CONTAINMENT 15.6-2 15.6.2.1 Identification of Event and Causes 15.6-2 15.6.2.2 Sequence of Events and System Operations 15.6-2 15.6.2.3 Analysis of Effects and Consequences 15.6-4 15.6.2.4 Conclusions 15.6-6 15.6.3 STEAM GENERATOR TUBE RUPTURE 15.6-7 15.6.3.1 Steam Generator Tube Rupture Without a , Loss of Offsite Power 15.6-7 l 15.6.3.1.1 Identification of Event and Causes 15.6-7 15.6.3.1.2 Sequence of Events and System 15.6-7 Operations 15.6.3.1.3 Analysis of Effects and Consequences 15.6-9 vii Amendment No. 7 March 31, 1982
TABLE OF CONTENTS (Continued) Chapter 15 Section Subiect Page No. 15.6.3.1.4 Conclusions 15.6-14 15.6.3.2 Steam Generator Tube Rupture With a Loss of Offsite Power 15.6-15 15.6.3.2.1 Identification of Event and Causes 15.6-15 15.6.3.2.2 Sequence of Events and System 15.6-15 Operations 15.6.3.2.3 Analysis of Effects and Consequences 15.6-17 15.6.3.2.4 Conclusions 15.6-20 15.6.5 LOSS-OF-COOLANT ACCIDENT (LOCA) 15.5 'L1 15.6.5.1 Identification of Causes 15.6-21 15.6.5.2 Analysis of Events and Consequences 15.6-21 15.7 RADI0 ACTIVE MATERIAL RELEASED FROM A SYSTEM OR COMPONENT 15.7-1 15.7.1 WASTE GAS SYSTEM FAILURE 15.7.2 RADI0 ACTIVE LIQUID WASTE SYSTEM LEAK OR FAILURE 15.7.3 RADI0 ACTIVE RELEASE DUE TO LIQUID CONTAINING TANK FAILURE 15.7-1 15.7.4 FUEL HANDLING ACCIDENT 15.7-1 15.7.4.1 Identification of Event and Causes 15.7-1 15.7.4.2 Sequence of Events and System Operations 15.7-1 15.7.4.3 Analysis of Effects and Consequences 15.7-1 15.7.4.4 Conclusions 15.7-3 0 viii Amendnent No. 7 March 31, 1982
LIST OF TABLES lV Chapter 15 Table Subject 15.0.1 (Intentionally Blank) 15.0.2 Chapter 15 Subsection Designation 15.0.3 (Intentionally Blank) 15.0.4 Reactor Protection System Trips Used in the Safety Analysis l 15.0.5 Initial Conditions 15.0.6 Single Failures 15.1.4-1 Sequence of Events for Full Power Inadvertent Opening of a Steam Generator Atmospheric Dump Valve (10SGADV) 15.1.4-2 Sequence of Events for Full Power Inadvertent Opening of a Steam Generator Atmospheric Dump Valve with Loss of Offsite Power after Turbine Trip (IOSGADV + LOP) 15.1.4-3 Assumptions and Initial Conditions for Full Power Inadvertent Opening of an Atmospheric Dump Valve (IOSGADY and 10SGADV + O(,/ LOP) 15.1.5-1 Sequence of Events for a Large Steam Line Break During Full Power Operation with Concurrent loss of Offsite Power (SLBFPLOP) 15.1.5-2 Sequence of Events for a large Steam Line Break During Full Power Operation with Offsite Power Available (SLBFP) 15.1.5-3 Sequence of Events for a Large Steam Line Break During Zero Power Operation with Offsite Power Available (SLBFP) 15.1.5-4 Sequence of Events for a large Steam Line Break During Zero Power Operation with Offsite Power Available (SLBZP) 15.1.5-5 Sequence of Events for a Small Steam Line Break Outside Containment During Full Power Operation with Offsite Power Available (SSLBFP) 15.1.5-6 Assumptions and Initial Conditions for a large Steam Line Break During Full Power Operation with Concurrent loss of Offsite Power (SLBFPLOP) ix Amendment No. 7 March 31, 1982
LIST OF TABLES (Continued) Chapter 15 Table Subject 15.1.5-7 Assumptionsand Initial Conditions for a large Steam Line Break During Full Power Operation with Offsite Power Available (SLBFP) 15.1.5-8 Assumptions and Initial Conditions for a large Steam Line Break During Zero Power Operation with Concurrent loss of Offsite Power (SLBZPLOP and SLBZPLOPD) 15.1.5-9 Assumptions and Initial Conditions for a large Steam Line Break During Zero Power with Offsite Power Available (SLBZP) 15.1.5-10 Assumptions and Initial Conditions for a Small Steam Line Break Outside Containment During Full Power Operation with Offsite Power Available (SSLBFP) 15.1.5-11 Parameters used in Evaluating the Radiological Consequences of Steam Line Breaks Outside Containment Upstream of MSIV 15.2.3-1 Sequence of Events for the LOCV 15.2.3-2 Disposition of Normally Operatina Systems for LOCV 15.2.3-3 Utilization of Safety System for LOCV 15.2.3 4 Assumed Initial Conditions for LOCV 15.3.1-1 Sequence of Events for Total Loss of Reactor Coolant Flow 15.3.1-2 Disposition of Normally Operating Systems for the Total Loss of Reactor Coolant Flow 15.3.1-3 Utilization of Safety Systems for the Total Loss of Reactor Coolant Flow 15.3.1 4 Assumed Initial Conditions for Total Loss of Reactor Coolant Flow 15.3.3-1 Sequence of Events for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-2 Disposition of Normally Operating Systems for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 9 x Amendment No. 7 March 31,1982
/O LIST OF TABLES (Continued) ! )
Chapter 15 Table Subject . 15.3.3-3 Utilization of Safety Systems for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-4 Assumed Initial Conditions for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-5 Parameters Used in Evaluating the Radiological Consequences of a Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-6 Secondary System Mass Release to the Atmosphere for the Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Event 15.3.3-7 Radiological Consequences of a Postulated Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip
'J 15.4.1-1 Sequence of Events for the Sequential CEA Withdrawal Event 15.4.1-2 Disposition of Normally Operating Systems for the Seauential CEA Withdrawal at Low Power 15.4.1-3 Utilization of Safety Systems for the Sequential CEA Withdrawal at Low Power 15.4.1-4 Assumption and Initial Condition for the Low Power CEA Withdrawal Analysis 15.4.2-1 Sequence of Events for the Sequential CEA Withdrawal Event 15.4.2-2 Disposition of Hormally Operating Systems for the Sequential CEA Withdrawal at Full Power 15.4.2-3 Utilization of Safety Systems for the Sequential CEA Withdrawal at Full Power 15.4.2-4 Assumptions and Initial Conditions for the Sequential CEA Withdrawal Analysis 15.4.3-1 Sequence of Events for the Single Full Length CEA Drop Event f)/ \m 15.4.3-2 Disposition of Hormally Operating Systems for the Single Full Length CEA Drop xi Amendment No. 7 March 31, 1982
LIST OF TABLES (Continued) Chapter 15 Table Subject 15.4.3-3 Assumptions and Initial Conditions for the Single Full Length Central Element Assembly Drop 15.4.6-1 Assumption for the Inadvertent Deboration Analysis 15.4.8-1 Sequence of Events for the CEA Ejection Event 15.4.0-2 Disposition of Normally Operating Systems for the CEA Ejection Event 15.4.8-3 Utilization of Safety Systems for the CEA Ejection Event 15.4.8-4 Initial Reactor States Considered for the CEA Ejection Event 15.4.8-5 Assumption used for the CEA Ejection Analysis Full Power Beginning of Cycle Initial Conditions. 15.4.8-6 Parameters used in Evaluating the Radiological Consequences of a CEA Ejection 15.4.8-7 Secondary System Mass Release to the Atmosphere 15.4.8-8 Radiological Consequences of a Postulated CEA Ejection Event 15.5.2-1 Sequence of Events for the PLCS Malfunction with a loss of Offsite Power at Turbine Trip 15.5.2-2 Disposition of Normally Operating Systems for the PLCS Malfunction with Loss of Off-Site Power 15.5.2-3 Utilization of Safety Systems for the PLCS Malfunction with Loss of Off-Site Power 15.6.2-1 Alarms that will be Actuated for the Double Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Control Valve Event 15.6.2-2 Sequence of Events for a Double Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Control Valve 15.6.2-3 Disposition of Normally Operating Systems for the Double Ended Break of a Letdown Line, Outside Containment, Upstream of the Letdown Control Valves xii Amendment No. 7 March 31, 1982
LIST OF TABLES (Continued) O Q Chapter 15 Table Subject 15.6.2-4 Utilization of Safety Systems for the Double Ended Break of a Letdown Line, Outside Containment, Upstream of the Letdown Control Valves 15.6.2-5 Assumed Input Parameters and Initial Conditions for the Double Ended Break of the Letdown Line Outside Containment Upstream of the Letdown Line Control Valve 15.6.3-1 Sequence of Events for the Steam Generator Tube Rupture 15.6.3-2 Disposition of Normally Operating Systems for the Steam Generator Tube Rupture 15.6.3-3 Utilization of Safety Systems for the Steam Generator Tube Rupture 15.6.3-4 Assumption and Initial Conditions for the Steam Generator Tube Rupture 15.6.3-5 Radiological Consequences of the Steam Generator Tube Rupture ( 'j 15.6.3-6 Sequence of Events for the Steam Generator Tube Rupture with a Loss of Offsite Power 15.6.3-7 Disposition of Normally Operating Systems for the Steam Generator Tube Rupture with a Loss of Offsite Power 15.6.3-8 Utilization of Safety Systems for the Steam Generator Tube Rupture with a loss of Offsite Power 15.6.3-9 Assumption and Initial Conditions for the Steam Generator Tube Rupture with a Loss of Offsite Power 15.6.3-10 Radiological Consequences of a Steam Generator Tube Rupture with a Loss of Offsite Power 15.6.5-1 System 80 Radio Iodine and Noble Gas Activity Inventory in l Containment Atmosphere i 15.7.4-1 Parameters used in Evaluating the Radiological Consequences of a Fuel Handling Accident i O Amendment No. 7 xiii March 31, 1982
LIST OF FIGURES Chapter 15 Figure Sub.iect 15.0-1A Sequence of Events-Symbols, Acronyns, and Definitions 15.0-1B Sequence of Events-Symbols, Acronyms, and Definitions 15.0-1C Sequence of Events-Symbols, Acronyms, and Definitions 15.1.4-1.1 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Core Power vs Time 15.1.4-1.2 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Core Average Heat Flux vs Time 15.1.4-1.3 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) RCS Pressure vs Time 15.1.4-1.4 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Reactor Coolant Flow Rate vs Time 15.1.4-1.5A Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Reactor Coolant Temperature ( A) vs Time 15.1.4-1.5B Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Reactor Coolant Temperature (B) vs Time 15.1.A-1.6 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Pressurizer Water Volume vs Time 15.1.4-1.7 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Steam Generator Pressures vs Time 15.1.4-1.8 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Steam Flow Rate to Atmosphere vs Time 15.1.4-1.9 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Steam Generator Steam Flow Rate vs Time 15.1.4-1.10 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Feedwater Flow Rates vs Time 15.1.4-1.11 Inadvertent Opening of an Atmospheric Dump Valve (10SGADV) Feedwater Enthalpy vs Time 15.1.a-1.12 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Steam Generator Mass Inventories vs Time 15.1.4-1.13 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Steam Flow to Atmosphere vs Time xiv Amendment No. 7 March 31, 1982
[ LIST OF FIGURES (Continued) V Chapter 15 Figure Subject 15.1.4-1.14 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Volume Above Hot Leg vs Time 15.1.4-1.15 Inadvertent Opening of an Atmospheric Dump Valve (IOSGADV) Minimum DNBR vs Time 15.1.4-2.1 10SGADV with Loss of Offsite Power after Turbine Trip Core Power vs Time 15.1.4-2.2 10SGADV with Loss of Offsite Power after Turbine Trip Core Average Heat Flux vs Time 15.1.4-2.3 10SGADV with Loss of Offsite Power after Turbine Trip RCS Pressure vs Time , 15.1.4-2.4 10SGADV with Loss of Offsite Power after Turbine Trip 1 Reactor Coolant Flow Rate vs Time [] 15.1.4-2.5A 10SGADV with Loss of Offsite Power after Turbine Trip Reactor Coolant Temperature ( A) vs Time (/ 15.1.4-2.5B IOSGADV with Loss of Offsite Power after Turbine Trip Reactor Coolant Temperature (B) vs Time 15.1.4-2.6 10SGADV with Loss of Offsite Power after Turbine Trip Pressurizer Water Volume vs Time 15.1.4-2.7 10SGADV with Loss of Offsite Power after Turbine Trip Steam Generator Pressures vs Time 15.1.4-2.8 10SGADV with Loss of Offsite Power after Turbine Trip Steam Flow to Atmosphere vs Time 15.1.4-2.9 10SGADV with Loss of Offsite Power after Turbine Trio Steam Generator Steam Flow Rate vs Time 15.1.4-2.10 10SGADV with Loss of Offsite Power after Turbine Trip Feedwater Flow Rates vs Time 15.1.4-2.11 10SGADV with Loss of Offsite Power after Turbine Trip Feedwater Enthalpy vs Time 15.1.4-2.12 10SGADV with Loss of Offsite Power after Turbine Trip Steam Generator Mass Inventories vs Time b xv Amendment No. 7 March 31,1982
LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.1.4-2.13 IOSGADV with Loss of Offsite Power after Turbine Trip Steam Flow to Atmosphere vs Time 15.1.4-2.14 10SGADV with Loss of Offsite Power after Turbine Trip Reactor Vessel Liquid Volume vs Time 15.1.4-2.15 10SGADV with Loss of Offsite Power after Turbine Trip Minimum DNBR vs Time 15.1.5-1.1 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Core Power vs Time 15.1.5-1.2 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Core Heat Flux vs Time 15.1.5-1.3 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power RCS Pressure vs Time 15.1.5-1.4 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Coolant Flow Rate vs Time 15.1.5-1.5A Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Coolant Temperature ( A) vs Time 15.1.5-1.5B Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Coolant Temperature (B) vs Time 15.1.5-1.6 Full Power Large Steam Line Break with Concurrent loss of Offsite Power Reactivity Changes vs Time 15.1.5-1.7 Full Power Large Steam Line Break with Concurrerit Loss of Offsite Power Pressurizer Water Volume vs Time 15.1.5-1.8 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Steam Generator Pressures vs Time O xvi Amendment No. 7 March 31, 1982
LIST OF FIGURES (Continued) p Chapter 15 V Figure Subject 15.1.5-1.9 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Steam Generator Blowdown Rates vs Time 15.1.5-1.10 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Feedwater Flow Rates vs Time
- 15.1.5-1.11 Full Power Large Steam Line Break with Concurrent Loss of Offsite i Power l Feedwater Enthalpy vs Time I
15.1.5-1.12 Full Power Large Steam Line Break with Concurrent loss of Offsite Power Steam Generator Mass Inventories vs Time 15.1.5-1.13 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Integrated Steam Mass Release Thru Break vs Time 15.1.5-1.14 Full Power Large Steam Line Break with Concurrent Loss of Offsite i m Power Safety Injection Flow vs Time 15.1.5-1.15 Full Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Vessel Liquid Volume vs Time
- 15.1.5-1.16 Full Power Large Steam Line Break with Concurrent loss of Offsite i Power Minimum Post-Trip DNBR vs Time 15.1.5-2.1 Full Power Large Steam Line Break with Offsite Power Available Core Power vs Time t 15.1.5-2.2 Full Power Large Steam Line Break with Offsite Power Available Core Heat Flux vs Time 15.1.5-2.3 Full Power Large Steam Line Break with Offsite Power Available RCS Pressure vs Time l
15.1.5-2.4 Full Power Large Steam Line Break with Offsite Power Available Reactor Coolant Flow Rate vs Time 15.1.5-2.5A Full Power Large Steam Line Break with Offsite Power Available Reactor Coolant Temperatures ( A) vs Time i (
.. Amendment No. 7 xv11 March 31, 1982
- _ _ - - _ _ _\
LIST OF FIGURES (Continued) Chapter 15 Fiaure Subject 15.1.5-2.5B Full Power Large Steam Line Break with Of# site Power Available Reactor Coolant Temperatures (B) vs Time 15.1.5-2.6 Full Power Large Steam Line Break with Offsite Power Available Reactivity Changes vs Time 15.1.5-2.7 Full Power Large Steam Line Break with Offsite Power Available Pressurizer Water Volume vs Time 15.1.5-2.8 Full Power Large Steam Line Break with Offsite Power Available Steam Generator Pressures vs Time 15.1.5-2.4 Full Power Large Steam Line Break with Offsite Power Available Steam Generator Blowdown Rates vs Time 15.1.5-2.10 Full Power Large Steam Line Break with Offsite Power Available Feedwater Flow Rates vs Time 15.1.5-2.11 Full Power Large Steam Line Break with Offsite Power Available Feedwater Enthalpy vs Time 15.1.5-2.12 Full Power Large Steam Line Break with Offsite Power Available Steam Generator Liquid Mass vs Time 15.1.5-2.13 Full Power Large Steam Line Break with Offsite Power Available Integrated Steam Release vs Time 15.1.5-2.14 Full Power Larce Steam Line Break with Offsite Power Available Safety Injection Flow vs Time 15.1.5-2.15 Full Power Large Steam Line Break with Offsite Power Available Reactor Vessel Liquid Volume vs Time 15.1.5-3.1 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Core Power vs Time 15.1.5-3.2 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Core Heat Flux vs Time 15.1.5-3.3 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power RCS Pressure vs Time O xviii Amendment No. 7 March 31, 1982
l f'~'} LIST OF FIGURES (Continued) 1 /
"' Chapter 15 Figure Subject 15.1.5-3.4 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Coolant Flow Rate vs Time 15.1.5-3.5A Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Coolant Temperatures (A) vs Time 15.1.5-3.5B Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactor Coolant Temperatures (B) vs Time 15.1.5-3.6 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Reactivity Changes vs Time 15.1.5-3.7 Zero Power Large Steam Line Break with Concurrent loss of Offsite Power Pressurizer Water Volume vs Time O ! 15.1.5-3.8 Zero Power Large Steam Line Break with Concurrent Loss of Offsite (V Powcr Steam Generator Pressures vs Time 15.1.5-3.9 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Steam Generator Blowdown Rates vs Time 15.1.5-3.10 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Feedwater Flow Rates vs Time
- 15.1.5-3.11 Zero Power Large Steam Line Break with Concurrent Loss of Offsite Power Feedwater Enthalpy vs Time 15.1.5-3.12 Zero Power Large Steam Line Break with Concurrent loss of Offsite Power Steam Generator Mass Inventories vs Time 15.1.5-3.13 Zero Power large Steam Line Break with Concurrent Loss of Offsite Power Integrated Steam Mass Release Thru Break vs Time 15.1.5-3.1A Zero Power Large Steam Line Break with Concurrent loss of Offsite
['\ Power Safety Injection Flow vs Time xix Amendment No. 7 March 31, 1982
LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.1.5-3.15 Zero Power Large Steam Line Break with Concurrent loss of Offsite Power Reactor Vessel Liquid Volume vs Time 15.1.5-4.1 Zero Power Large Steam Line Break with Offsite Power Available Core Power vs Time 15.1.5-4.2 Zero Power Large Steam Line Break with Offsite Power Available Core Heat Flux vs Time 15.1.5 4.3 Zero Power Large Steam Line Break with Offsite Power Available RCS Pressure vs Time 15.1.5-4.4 Zero Power Large Steam Line Break with Offsite Power Available Reactor Coolant Flow Rate vs Time 15.1.5-4.5A Zero Power Large Steam Line Break with Offsite Power Available Reactor Coolant Temperatures ( A) vs Time 15.1.5-4.5B Zero Power Large Steam Line Break with Offsite Power Available Reactor Coolant Temperatures (B) vs Time 15.1.5-4.6 Zero Power Large Steam Line Break with Offsite Power Available Reactivity Changes vs Time 15.1.5-4.7 Zero Power Large Steam Line Break with Offsite Power Available Pressurizer Water Volume vs Time 15.1.5 a.9 Zero Power Large Steam Line Break with Offsite Power Available Steam Generator Pressures vs Time 15.1.5-4.9 Zero Power Large Steam Line Break with Offsite Power Available Steam Generator Blowdown Rates vs Time 15.1.5-4.10 Zero Power Large Steam Line Break with Offsite Power Available Feedwater Flow Rates vs Time - 15.1.5-4.11 Zero Power Large Steam Line Break with Offsite Power Available Fredwater Enthalpy vs Time 15.1.5-4.12 Zero Power Large Steam Line Break with Offsite Power Available Steam Generator Liquid Mass vs Time 15.1.5 a.13 Zero Power Large Steam Line Break with Offsite Power Available Integrated Steam Release vs Time 15.1.5-4.14 Zero Power Large Steam Line Break with Offsite Power Available Sa fety Injection Flow vs Time Amendment No. 7 March 31, 1982
LIST OF FIGURES (Continued) () Figure Chapter 15 Subject 15.1.5-4.15 Zero Power Large Steam Line Break with Offsite Power Available Reactor Vessel Liquid Volume vs Time 15.1.5-5.1 Full Power Small Steam Line Break with AC Power Available Core Power vs Time 15.1.5-5.2 Full Power Small Steam Line Break with AC Power Available Core Heat Flux vs Time 15.1.5-5.3 Full Power Small Steam Line Break with AC Power Available RCS Pressure vs Time 15.1.5-5.4 Full Power Small Steam Line Break with AC Power Available Core Flow Rate vs Time 15.1.5-5.5 Full Power Small Steam Line Break with AC Power Available Reactor Coolant Temperaturn vs Time 15.1.5-5.6 Full Power Small Steam Line Break with AC Power Available
-~g Reactivity Changes vs Time
\s_- 15.1.5-5.7 Full Power Small Steam Line Break with AC Power Available ,
Steam Generator Blowdown Rates vs Time 15.1.5-5.8 Full Power Small Steam Line Break with AC Power Available Peactor Vessel liquid Volume vs fime 15.1.5-5.9 Full Power Small Steam Line Break with AC Power Available DNBR vs Time 15.2.3-1A Sequence of Events Diagram for LOCV l 15.2.3-1B Sequence of Events Diagram for LOCV 15.2.3-1C Sequence of Events Diagram for LOCV I 15.2.3-2 Loss Of Condenser Vacuum Core Power vs Time ! 15.2.3-3 Loss Of Condenser Vacuum Core Average Heat Flux vs Time 15.2.3-4 Lors Of Condenser Vacuum Reactivity vs Time i 15.2.3-5 Loss Of Condenser Vacuum RCS Pressure vs Time 15.2.3-6 Loss Of Condenser Vacuum RCS Pressure vs Time O Amendment No. 7 xxi March 31, 1982
LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.2.3-7 Loss Of Condenser Vacuum Core Average Coolant Temperature vs Time 15.2.3-8 Loss Of Condenser Vacuum Pressurizer Water Volume vs Time 15.2.3-9 Loss Of Condenser Vacuum Steam Generator Water Level vs Time 15.2.3-10 Loss Of Condenser Vacuum Stream Generator Pressure vs Time 15.2.3-11 Loss Of Condenser Vacuum Steam Generator Pressure vs Time 15.2.3-12 Loss Of Condenser Vacuum Feedwater Flow vs Time 15.2.3-13 Loss Of Condenser Vacuum Total Steam Flow vs Time 15.2.3-14 Loss Of Condenser Vacuum Minimum DtlBR vs Time 15.3.1-1A Sequence of Events Diagram for Total Loss of Reactor Coolant Flow 15.3.1-1B Sequence of Events Diagram for Total Loss of Reactor Coolant Flow 15.3.1-1C Sequence of Events Diagram fcr Total Loss of Reactor Coolant Flow 15.3.1-1D Sequence of Events Diagram for Total loss of Reactor Coolant Flow 15.3.1-2 Total Loss of Reactor Coolant Flow Core Power vs Time 15.3.1-3 Total Loss of Reactor Coolant Flow Core Average Heat Flux vs Time 15.3.1 4 Total Loss of Reactor Coolant Flow RCS Pressure vs Time 15.3.1-5 Total Loss of Reactor Coolant Flow Core Avarage Coolant Temperatures vs Time 15.3.1-6 Total Loss of Reactor Coolant Flow Reactivity vs Time 15.3.1-7 Total Loss of Reactor Coolant Flow Core Flow Fraction vs Time 15.3.1-8 Total loss of Reactor Coolant Flow Right Hand & Left Hand Steam Generator Pressures vs Time 15.3.1-9 Total loss of Reactor Coolant Flow CE-1 Minimum DNBR vs Time xxii Amendment No. 7 March 31, 1982
LIST OF FIGURES (Continued)
\ Chapter 15 d Figure Subject 15.3.3-1A Sequence of Events Diagram for Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-1B Sequence of Events Diagram for Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-1C Sequence of Events Diagram for Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-1D Sequence of Events Diagram for Single Reactor Coolant Pump Rotor 4 Seizure with Loss of Offsite Power Resulting from Turbine Trip 15.3.3-2 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite . Power Resulting from Turbine Trip Core Power vs Time l
. 15.3.3-3 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trio Core Average Heat Flux vs Time 15.3.3-4 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip
/ RCS Pressure vs Time 15.3.3-5 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trio Core Average Coolant Temperature vs Time 15.3.3-6 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbino Trip Reactivity vs Time 15.3.3-7 Single Reactor Coolant Pump Rotor Seizure with loss of Offsite Power Resulting from Turbine Trip Core Flow Fraction vs Time 15.3.3-8 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Steam Generator Pressure vs Time 15.3.3-9 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip CE-1 Minimum DNBR vs Time 15.3.3-10 Single Reactor Coolant Pump Rotor Seizure with Loss of Offsite Power Resulting from Turbine Trip Steam Generators Water Mass vs Time
)
%d Amendment No. 7 xxiii March 31,1982
LIST OF FIGURES (Continued) Chapter 15 Fiqure Subject 15.4.1-1A Sequence of Events for Uncontrolled Control Element Assembly Withdrawal from a Subcritical or Low Power Condition 15.4.1-1B Sequence of Events for Uncontrolled Control Element Assembly Withdrawal from a Subcritical or Low Power Condition 15.4.1-1C Seouence of Events for Uncontrolled Control Element Assembly Withdrawal from a Subcritical or low Power Condition 15.4.1-2 Sequential CEA Withdrawal at Low Power rore Power vs Time 15.4.1-3 Seouential CEA Withdrawal at Low Power Core Average Heat Flux vs Time 15.4.1-4 Sequential CEA Withdrawal at Low Power Reactor Coolant System Pressure vs Time 15.4.1-5 Sequential CEA Withdrawal at Low Power Minimum DNBR vs Time 15.4.1-6 Sequential CEA Withdrawal at Low Power Core Average Coolant Temperatures vs Time 15.4.1-7 Sequential CEA Withdrawal at Low Power Steam Generator Pressure vs Time 15.4.1-8 Sequential CEA Withdrawal at low Power Linear Heat Generation Rate vs Time 15.4.2-1A Sequence of Events Diagram for Uncontrolled Control Element Assembly Withdrawal at Power 15.4.2-1B Sequence of Events Diagram for Uncontrolled Control Element Assembly Withdrawal at Power 15.4.2-1C Sequence of Events Diagram for Uncontrolled Control Element Assembly Withdrawal at Power 15.4.2-1D Sequence of Events Diagram for Uncontrolled Control Element Assembly Withdrawal at Power 15.4.2-2 Sequential CEA Withdrawal at Power Core Power vs Time 15.4.2-3 Sequential CEA Withdrawal at Power Core Average Heat Flux vs Time xxiv Amendment No. 7 March 31, 1982
LIST OF FIGURES (Continued) i Chapter 15 Figure Subject 15.4.2-4 Sequential CEA Withdrawal at Power Reactor Coolant System Pressure vs Time 15.4.2-5 Sequential CEA Withdrawal at Power Minimum DNBR vs Time 15.4.2-6 Sequential CEA Withdrawal at Power , Core Average Coolant Temperatures vs Time 15.4.2-7 Sequential CEA Withdrawal at Power Steam Generator Pressure vs Time 15.4.2-8 Sequential CEA Withdrawal at Power Peak Linear Heat Generator Rate 15.4.?-9 Sequential CEA Withdrawal at Power Feedwater Enthalpy vs Time 15.4.2-10 Sequential CEA Withdrawal at Power Feedwater Flow vs Time
, 15.4.2-11 Sequential CEA Withdrawal at Power b Main Steam Safety Valve Flow vs Tim.:
i t j 15.4.2-12 Sequential CEA Withdrawal at Power Total Steam Flow vs Time 15.4.3-2 Single Full Length CEA Drop Core Power vs Time 15.4.3-3 Single Full Length CEA Drop Core Average Heat Flux *is Time 15.4.3-4 Single Full Length CEA Drop Hot Channel Heat Flux vs Time l 15.4.3-5 Single Full Length CEA Drop Pressurizer Pressure vs Time 15.4.3-6 Single Full Length CEA Drcp Minimum DNBR vs Time l 15.4.3-7 Single Full Length CEA Drop
; Core Average Coolant Temperatures vs Time 15.4.3-8 Single Full Length CEA Drop 1
Steam Generator Water Level vs Time xxv Amendment No. 7 March 31,1982 '
LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.4.3-9 Single Full Length CEA Drop Steam Generator Pressure vs Time 15.4.3-10 Single Full Length CEA Drop Total Steam Flow vs Time 15.4.3-11 Single Full Length CEA Drop Feedwater Flow vs Time 15.4.3-12 Single Full Length CEA Drop Feedwater Enthalpy vs Time 15.4.3-13 Single Full Length CEA Drop Linear Heat Generation Rate vs Time 15.4.6-1 Sequence of Events Diagram for inadvertent Deboration 15.4.7-1 P anar Average Power Distribution Corresponding to Maximum F Produced by a Fuel Assembly Misloading that is U detectable During Startup at B0C 15.4.R-1A Sequence of Events Diagram for CEA Ejection with Loss of Offsite Power 15.4.8-1B Sequence of Events Diagram for CEA Ejection with Loss of Offsite Power
- 15.4.8-lC Sequence of Events Diagram for CEA Ejection with Loss of Offsite l Power 1
15.4.8-10 Sequence of Events Diagram for CEA Ejection with Loss of Offsite Power 15.4.8-1E Seouence of Events Diagram for CEA Ejection with Loss of Offsite l Power 15.4.8-1F Sequence of Events Diagram for CEA Ejection with Loss of Offsite Power l 15.4.8-2 CEA Ejection - Core Power vs Time l 15.4.8-3 CEA Ejection - Peak Core Power Density vs Time 15.4.8 4 CEA Ejection - Core Averace Heat Flux vs Time Amendment tio. 7 xxvi March 31, 1982
LIST OF FIGURES (Continued) Chapter 15 Figure Subject b V 15.4.8-5 CEA Ejection - Peak Hot Channel Heat Flux vs Time 15.4.8-6 CEA Ejection - Hot and Average Channel Fuel and Clad Temperature vs Time 15.4.8-7 CEA Ejection - Reactivity vs Time 15.4.8-8 CEA Ejection - RCS and Pressurizer Pressure vs Time 15.4.8-9 CEA Ejectio, - RCS and Pressurizer Pressure vs Time 15.4.8-10 CEA Ejection - Pressurizer Pressure vs Time 15.4.8-11 CEA Ejection - Steam Generator Pressure vs Time 15.4.8-12 CEA Ejection - Steam Generator Pressure vs Time 15.4.8-13 CEA Ejection - Main Steam Safety Valve Flow vs Time 15.5.2-1A Sequence of Events Diagram for Pressurizer Level Control System Malfunction with Loss of Offsite Power Following the Turbine Trip 15.5.2-1B Sequence of Events Diagram for Pressurizer Level Control System Malfunction with Loss of Offsite Power Following the Turbine Trip 15.5.2-1C Sequence of Events Diagram for Pressurizer Level Control System Malfunction with Loss of Offsite Power Following the Turbine Trip Sequence of Events Diagram for Pressurizer Level Control System 15.5.2-1D Malfunction with Loss of Offsite Power Following the Turbine Trip 15.5.2-2 PLCS Malfunction with Loss of Offsite Power Core Power vs Time 15.5.2-3 PLCS Malfunction with Loss of Offsite Power Core Average Heat Flux vs Time 15.5.2-4 PLCS Malfunction with Loss of Offsite Power Pressurizer Pressure vs Time 15.5.2-5 PLCS Malfunction with Loss of Offsite Power Core Average Coolant Tenperature vs Time 1 15.5.2-6 PLCS Malfunction with Loss of Offsite Power l Pressurizer Water Volume vs Time I 15.5.2-7 PLCS Malfunction with Loss of Offsite Power Steam Generator Water Level vs Time 15.5.2-8 PLCS Malfunction with Loss of Offsite Power Steam Generator Pressure vs Time 15.5.2-9 PLCS Malfunction with Loss of Offsite Power Total Steam Flow vs Time Amendment No. 7 xxvii March 31,1982
LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.5.2-10 PLCS Malfunction with Loss of Offsite Power Feedwater Flow vs Time 15.5.2-11 PLCS Malfunction with Loss of Offsite Power Feedwater Enthalpy vs Time 15.6.2-1A Seouence of Events Diagram for Double-Ended Letdown Line Break, Outside Containment, Upstream of Letdown Control Valve 15.6.2-1B Sequence of Events Diagram for Double-Ended Letdown Line Break, Outside Containment, Upstream of Letdown Control Valve 15.6.2-1C Sequence of Events Diagram for Double-Ended Letdown Line Break, Outside Containment, Upstream of Letdown Control Valve 15.6.2-2 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Core Power vs Time 15.6.2-3 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Core Average Heat Flux vs Time 15.6.2-4 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Pressurizer Pressure vs Time 15.6.2-5 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Core Coolant Temperatures vs Time 15.6.2-6 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Steam Generator Pressure vs Time 15.6.2-7 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Integrated Primary Coolant Discharge vs Time 15.6.2-8 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Pressurizer Water Level vs Time 15.6.2-9 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Reactor Coolant System Inventory vs Time 15.6.2-10 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Steam Generator Water Level vs Time
... Amendment No. 7
"" March 31,1982
i i I LIST OF FIGURES (Continued) Chapter 15
; Figure Subject 15.6.2-11 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve )
Total Steam Flow vs Time l 15.6.2-12 Letdown Lins Break, Outside Containment, Upstream of Letdown Line i Control Valve Feedwater Flow vs Time ! 15.6.2-13 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Feedwater Enthalpy vs Time l 1 15.6.2-14 Letdown Line Break, Outside Containment, Upstream of Letdown Line Control Valve Minimum DNBR vs Time 15.6.3-1A Sequence of Events Diagram for Steam Generator Tube Rupture 15.6.3-1B Sequence of Events Diagram for Steam Generator Tube Rupture ^ 15.6.3-1C Sequence of Events Diagram for Steam Generator Tube Rupture 15.6.3-1D Sequence of Events Diagram for Steam Generator Tube Rupture 15.6.3-2 Steam Generator Tube Rupture without Loss of Offsite Power Core Power vs Time i 15.6.3-3 Steam Generator Tube Rupture without loss of Offsite Power l Core Heat Flux vs Time I 15.6.3-4 Steam Generator Tube Rupture without Loss of Offsite Power RCS Pressure vs Time 15.6.3-5 Steam Generator Tube Rupture without Loss of Offsite Power RCS Temperatures vs Time 15.6.3-6 Steam Generator Tube Rupture without loss of Offsite Power Pressurizer Water Volume vs Time 15.6.3-7 Steam Generator Tube Rupture without loss of Offsite Power Steam Generator Pressure vs Time 15.6.3-8 Steam Generator Tube Rupture without loss of Offsite Power
- Total Steam Flow vs Time 15.6.3-9 Steam Generator Tube Rupture without Loss of Offsite Power Feedwater Flow vs Time
**i
- Amendment No. 7
. March 31, 1982 i
, - - . - . - . - - , , . , - - , , ,..a . , . .n~-.--.-.-v.---. , - - - , ,,- . , - , , - - - - - - n
LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.6.3-10 Steam Generator Tube Rupture without Loss of Offsite Power Feedwater Enthalpy vs Time 15.6.3-11 Steam Generator Tube Runture without Loss of Offsite Power Steam Generator Liquid Mass vs Time 15.6.3-12 Steam Generator Tube Rupture without Loss of Offsite Power Main Steam Safety Valve Integi ped Flow vs Time 15.6.3-13 Steam Generator Tube Rupture without Loss of Offsite Power RCS Inventory vs Time 15.6.3-14 Steam Generator Tube Rupture without Loss of Offsite Power Tube Leak Rate vs Time 15.6.3-15 Steam Generator Tube Rupture without loss of Offsite Power Integrated Leak Flow vs Time 15.6.3-16 Steam Generator Tube Rupture without Loss of Offsite Power Liquid Volume Above Top of Hot Leg vs Time 15.6.3-17 Steam Generator Tube Rupture without Loss of Offsite Power Minimum DNBR vs Time 15.6.3-18A Sequence of Events Diagram for Steam Generator Tube Rupture with Loss of Offsite Power on Reactor Trip 15.6.3-18B Sequence of Events Diagram for Steam Generator Tube Rupture with loss of Offsite Power on Reactor Trip 15.6.3-18C Sequence of Events Diagram for Steam Generator Tube Rupture with Loss of Offsite Power on Reactor Trio 15.6.3-18D Seouence of Events Diagram for Steam Generator Tube Rupture with Loss of Offsite Power on Reactor Trip 15.6.3-19 Steam Generator Tube Rupture without loss of Offsite Power Core Power vs Time 15.6.3-20 Steam Generator Tube Rupture without loss of Offsite Power Core Heat Flux vs Time 15.6.3-21 Steam Generator Tube Rupture without Loss of Offsite Power RCS Pressure vs Time 15.6.3-22 Steam Generator Tube Rupture without loss of Offsite Power Core Coolant Temperature vs Time Amendment No. 7
- March 31, 1982
I 1 LIST OF FIGURES (Continued) Chapter 15 Figure Subject 15.6.3-23 Steam Generator Tube Rupture without Loss of Offsite Power Pressurizer Water Volume vs Time 15.6.3-24 Steam Generator Tube Rupture without Loss of Offsite Power Steam Generator Pressure vs Time 15.6.3-25 Steam Generator Tube Rupture without Loss of Offsite Power Total Steam Flow Per Steam Generator vs Time 15.6.3-26 Steam Generator Tube Rupture without loss of Offsite Power Feedwater Flow Per Steam Generator vs Time 15.6.3-27 Steam Generator Tube Rupture without Loss of Offsite Power Feedwater Enthalpy vs Time 15.6.3-28 Steam Generator Tube Rupture without Loss of Offsite Power Steam Generator Mass vs Time 15.6.3-29 Steam Generator Tube Rupture without Loss of Offsite Power MSSV Integrated Flow Per Steam Generator vs Time 15.6.3-30 Steam Generator Tube Rupture without Loss of Offsite Power Reactor Coolant System Inventory vs Time 15.6.3-31 Steam Generator Tube Rupture without Loss of Offsite Power Tube Leak Rate vs Time 15.6.3-32 Steam Generator Tube Rupture without loss of Offsite Power Integrated Leak Flow vs Time 15.6.3-33 Steam Generator Tube Rupture without Loss of Offsite Power Liquid Volume Above Top of Hot Legs vs Time j 15.6.3-34 Steam Generator Tube R"pture without Loss of Offsite Power t Minimum DNBR vs Time 4 xxxi Amendment No. 7 March 31, 1982
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1
- 15. ACCIDENT ANALYSES 15.0 ORGANIZATION AND METHODOLOGY i
This chapter presents analytical evaluations of the Nuclear Steam Supply System > (NSSS) response to postulated disturbances in process variables and to postulated malfunctions or failures of equipment. Such incidents (or events) are postulated and their consequences analyzed despite the many precautions which are taken in the design, construction, quality assurance, and plant
- operation to prevent their occurrence. The effects of these incidents are j examined to determine their consequences and to evaluate the capability built
; into the plant to control or accommodate such failures and situations. l
, 1 15.0.1 CLASSIFICATION OF TRANSIENTS AND ACCIDENTS 15.0.1.1 Format and Content i This chapter is structured according to the format and content suggested by Reference 1 and required by Reference 26. 15.0.1.2 Event Categories Each postulated initiating event has been assigned to one of the following I categories;
- a. Increased Heat Removal by Secondary System,
- b. Decreased Heat Removal by Secondary System,
) c. Decreased Reactor Coolant Flow, l d. Reactivity and Power Distribution Anomalies, 1 l e. Increase in RCS Inventory,
! f. Decrease in RCS Inventory,
- g. Radioactive Release from a Subsystem or Component, or
- h. Anticipated Transients Without Scram ( ATWS).
Definition of an appropriate evaluation basis and acceptance criteria does not presently exist for ATWS, therefore, these events are not addressed in this chapter. The assignment of an initiating event to one of these eight categories is made according to Reference 26. 15.0.1.3 Event Frequencies Reference 26 subjectively classifies initiating events in the following qualitative frequency groups: 15.0-1 Amendment No. 7 March 31, 1982
A. Moderate Frequency Events B. Infrequent Events C. Accidents 15.0.1.4 Events and Event Combinations The events and event combinations in this chapter are those identified by Reference 26, and are presented with respect to the event specific acceptance criteria specified therein. For each applicable acceptance criterion in an event category, only the limiting event or event combination is presented in analytical detail. Qualitative discussions are provided for all other events or event combinations explaining why they are not limiting. For event combinations which require consideration of a single failure, the limiting failure is selected from those listed in Table 15.0-6. Only low probability dependent failures (e.g., loss of offsite power following turbine trip) and independent pre-existing failures are considered credible and included in the table. Pre-existing failures are equipment failures existing prior to the event initiation which are not revealed until called upon during the event (e.g. , a failure of an emergency feedwater pump). High probability dependent occurrences are always included in the event analysis, if they have an adverse impact (e.g., loss of main feedwater pumps following a loss of electric power) . 15.0.1.5 Section Numbering The incidents analyzed in this chapter are presented in sections in accordance with Reference 26 and are numbered as described in Table 15.0-2. 15.0.1.6 Sequence of Events Analysis The purpose of the Sequence of Events and Systems Operation section provided for each limiting event in this chapter is to provide:
- 1. "The step-by-step sequence of events from event initiation to the final stabilized condition,
- 2. The extent to which normally operating plant instrumentation and controls are assumed to function,
- 3. The extent to which plant and reactor protection systems are required to function,
- 4. The credit taken for the functioning of normally operating plant systems, (and)
- 5. The operation of engineered safety systems that is required, (1)" as well as O
Amendment No. 7 15.0-2 March 31, 1982
- 6. "A summary of a systematic functional analysis of components required for each event analyzed in Chapter 15. The summary should be shown in the form of simple block diagrams beginning with the event, branching out to the various possible protection sequences for each safety action required to mitigate the consequences of the event (e.g., core cooling, containment isolaion, pressure relief, scram, etc.), and ending with an identification of the specific safety actions being provided. (24)"
A detailed Sequence of Events Analysis (SEA) has been performed for each limiting event for which detailed results are presented in this chapter. SEA has been specifically omitted for those events which, though representing limiting events for their category do not result in the actuation of safety systems or for which a detailed, quantitative analysis was not presented. The results of the analysis are presented in the form of three tables and a figure for each event. The first table in each Sequence of Events and Systems Operation section (15.X.Y-1) presents a chronological list of events which occur during the transient and the time at which they occur, from the initiation of the event to the achievement of cold shutdown conditions. The second table (15.X.Y-2) is a matrix which describes the extent to which normally operating plant systems are assumed to function during the transient. The results of the SEA are summarized in the Sequence of Events Diagram (SED) and in a third 'able (15.X.Y-3) which specifies the reactor protection and engineered safety feature systems which are actuated, to accomplish safety functions, during the course of the transient. The SED together with the chronological list of events and the SEA symbol and acronym drawing (Figure 15.0.-1) may be used to trace the actuation and N interaction of the systems used to mitigate the consequences of each event. The SED is a block diagram, composed of several success paths which define a set of safety actions leading from the initiating event to the accomplishment of a specific safety function. All of the safety functions used in the SED's are defined in Figure 15.0-1. A success path may be composed of two branches, one indicated by a solid line, describing the Sequence of Eve-ts which occur in the transient analysi , and the other, indicated by a dotted line, describing an alternative or back-up path to a given means of accomplishing a safety function. An alternate dotted path is specified if the analysis assumed the action of a non-safety system in achieving a particular safety function. Non-safety systems are indicated by an "NS" in the upper right-hand corner of the system block. The redundancy of a system or component is indicated by a fraction (e.g.,1/2, 2/4) placed beneath the system block. The numerator specifies the number of trains or components required to perform the action and the denominator specifies the number of trains or components available. In cases where no alternate path exists and a single system or component is included in a success path, the symbol "S.F." will be used to indicate that no single active failure will prevent the accomplishment of the safety action. Components or systems which require no active initiation or actuation to perform their function are considered to be passive and are marked as such with a "P" in the lower left-hand corner .of the system block. The absence of a passive label implies that a component is considered to be active and must be y actively initiated to perform its function. Amendment No. 7 March 31, 1982 15.0-3
Manual operations performed on a given system or component are indicated by placing an "M" in the lower lef t-hand corner of the system block. When a manual action is required, the sensed variables necessary to perform the action are shown as inputs and the location of the input signal is shown above the input signal circle. The system setpoint values assumed in the transient analysis, e.g., trip signal setpoints, will be noted along the success path. Time delays or the time required to perform an action are shown as a number with square brackets. All events presented in Sequence of Events Diagrams (SED) in this chapter are shown from event initiation to achievement of the Cold Shutdown operating mode (see Chapter 16). Not all events require that the plant be taken to Cold Shutdown. The SED's only demonstrate that for any event presented here it is possible to take them to Cold Shutdown by means of the safety actions indicated. 15.0.2 SYSTEMS OPERATION During the course of any event various systems may be called upon to function. Some of these systems are described in Chapter 7 and include those electrical, instrumentation, and control systems designed to perform a safety function (i.e., those systems which must operate during an event to mitigate the consequences) and those systems not required to perform a safety function (see Sections 7.2 through 7.6 and 7.7, respectively). The Reactor Protection System (RPS) is described in Section 7.2. Table 15.0-4 lists the RPS trips for which credit is taken in the analyses discussed in this section, including the setpoints and the trip delay times associated with each trip. The analyses take into consideration the response times of actuated devices after the trip setting is reached. The reactor trip delay times shown in Table 15.0-4 are defined as the elapsed time from the time the sensor output reaches the trip setpoint to the time the trip breakers open. The sensor response is modeled by using the transfer function for the particular sensor used. The interval between trip breaker opening and the time at which the magnetic flux of the Control Element Assembly (CEA) holding coils has decayed enough to allow CEA motion is conservatively assumed to be 0.34 seconds. Finally, a conservative value of 3.66 seconds is assumed for CEA insertion, defined as the elapsed time from the beginning of CEA motion to the time of 901 insertion of the CEAs in the reactor core. The Engineered Safety Feature Actuation Systems (ESFAS) and electrical, instrumentation, and control systems required for safe shutdown are described in Sections 7.3 and 7.4, respectively. The manner in which these systems function during events is discussed in each event description. The instrumentation which is required to be available to the operator in order to assist him in evaluating the nature of the event and determining required action is described in Section 7.5. The use of this instrumentation by the operator is discussed in each event description. O Amendment No. 7 15.0-4 March 31, 1982
Other systems called upon to function are described in Chapters 6, 9, and in m') the Applicants SAR. The utilization of these systems is described in the
,/ Sequence of Events section of each presentation.
4 Systems which may but are not required to perform safety functions are described in Section 7.7. These include various control systems and the Core Operating Limit Supervisory System (COLSS). In general, normal automatic operation of these control systems is assumed unless lack of operation would make the consequences of the event more adverse. In such cases, the particular control system is assumed to be inoperative, in the manual mode, until the time of operator action. 15.0.3 CORE AND SYSTEM PERFORMANCE 15.0.3.1 Mathematical Model The Nuclear Steam Supply System (NSSS) response to various events was simulated using digital computer programs and analytical methods most of which are documented in Reference 2 and have been approved for use by the NRC by Reference 3. 15.0.3.1.1 Loss of Flow Analysis Method The method used to analyze events which are initiated by failures which cause a decrease in reactor coolant flowrate is discussed in Appendix 15A.
/~~T 15.0.3.1.2 CEA Ejection Analysis Method The method used fcr analysis of the reactivity and power distribution anomalies initiated by a CEA ejection (Section 15.4.5) is documented in Reference 16, Topical Report CENPD-190A, which was approved by the NRC for reference in license applications on June 10, 1976.
15.0.3.1.3 CESEC Computer Program The CESEC 11 computer program is used to simulate the NSSS (unless specified otherwise for an event). CESEC II is a version of CESEC which incorporates the ATWS model modifications documented in Reference 8 through 12 and includes additional improvements which extend the range of applicability of the models. The CESEC computer code is documented in Reference 7. CESEC II computes key system parameters during a transient including core heat flux, pressures, temperatures, and valve actions. A partial list of the dynamic functions included in this NSSS simulation includes: point kinetics neutron behavior, Doppler and moderator reactivity feedback, boron and CEA reactivity effects, multi-node average and hot channel reactor core thermal hydraulics, reactor coolant pressurization and mass transport, reactor coolant system safety valve behavior, steam generation, steam generator water level, turbine bypass, main steam safety and turbine admission valve behavior, as well as alarm, control, protection, and engineered safety feature systems. The steam turbines, condensers and their associated controls are not included in the simulation. Steam generator feedwater enthalpy and flowrate are provided O as input to CESEC II. 15.0-5 Amendment No. 7 j March 31, 1982 '
During the course of execution, CESEC II obtains steady-state and transient solutions to the set of equations that mathematically describe the physical models of the subsystems mentioned above. Simultaneous numerical integration of a set of nonlinear, first-order differential equations with time-varying coefficients is carried out by means of a simultaneous solution. As the time variable evolves, edits of the principal systems parameters are printed at prospecified intervals. An extensive library of the thermodynamic properties of uranium dioxide, water, and zircaloy is incorporated into this program. Through the use of CESEC-II, symmetric and asymmetric plant response over a wide range of operating conditions can be determined. The CESEC-III version of CESEC used in some of the analyses explicitly models the steam void formation and collapse in the upper head region of the reactor vessel and is documented in Reference 27. Other improvements to this version of CESEC include: a more detailed thermalhydraulic model which explicitly simulates the mixing in the reactor vessel from asymmetric transients, an RCS flow model which calculates the time dependent re3ctor coolant mass flow rate in each loop, a wall heat model, 3-D reactivity f eedback model, a safety injection tank model, and a primary-to-secondary heat transfer model which calculates the heat transfer for each generator node rather than for a steam generator as a whole. 15.0.3.1.4 C0AST Computer Program The C0AST computer program is used to calculate the reactor coolant flow coastdown transient for any combination of active and inactive pumps and fonvard or reverse flow in hot or cold legs. The program is described in Reference 13 and was referenced in Reference 2. The equations of conservation of momentum are written for each of the flow paths of the C0AST model assuming unsteady one-dimensional flow of an incompressible fluid. The equation of conservation of mass is written for the appropriate nodal points, pressure losses due to friction, and geometric losses are assumed proportional to the flow velocity squared. Pump dynamics are modeled using a head-flow curve for a pump at full speed and using four-i quadrant curves, which are parametric diagrams of pump head and torque on l coordinates of speed versus flow, for a pump at other than full speed. 15.0.3.1.5 STRIKIN-II Computer Program The STRIKIN-II computer program is used to simulate the heat conduction within reactor fuel rods and its associated surface heat transfer. The STRIKIN-II program is described in Reference 14. The STRIKIN-II computer program provides a single, or dual, closed channel model of a core flow channel to calculate the clad and fuel temperatures for an average or hot fuel rod, and the extent of the zirconium water reaction for a cylindrical geometry fuel rod. STRIKIN-II includes: A. Incorporation of all major reactivity feedback mechanisms B. A maximum of six delayed neutron groups O 15.0-6 Amendment No. 7 March 31, 1982
C. Both axial (maximum of 20) and radial (maximum of 20) segmentation of the fuel element D. Control rod scram initiation on high neutron power. 15.0.3.1.6 TORC Computer Program The TORC computer program is used to simulate the fluid conditions within the reactor core and to calculate fuel pin DNBR. The TORC program is described in References 18 and 21 and was referenced in Reference 2. 15.0.3.1.7 Reactor Physics Computer Programs Numerous computer programs are used to produce the input reactor physics parameters required by the NSSS simulation and reactor core programs previously described. These reactor physics computer programs are described in Chapter 4. 15.0.3.2 Initial Conditions The events discussed in this chapter have been analyzed over a range of initial values for the principal process variables. The ranges were chosen to encompass all steady state operational configurations (with the exception of part loop operation). Analysis over a range of initial conditions is compatible with the monitoring function performed by the COLSS which is described in Section 7.7 and the flexibility of plant operation which the COLSS allows. This flexibility is produced by allowing parameter trade-offs by monitoring the prinicipal process variables, synthesizing the margin to fuel thermal design limits, and displaying to the reactor operator the core power operating limit. The required margin to DNB incorporated in COLSS is currently established by the total loss of forced reactor coolant flow as described in Appendix 15A. The required margin to DNB is based on the total loss of forced reactor coolant flow since this initiating event produces the most rapid loss of margin to DNB before reactor trip and the maximum loss of margin to DNB after reactor trip. The peak linear heat generation rate incorporated in COLSS is established by the loss of coolant accident (LOCA). The range of values of each of the prinicipal process variables that was considered in analyses of events discussed in this chapter is listed in Table 15.0-5. 15.0.3.3 Input Parameters The parameters used in the analyses are consistent with those listed in the preceding section and are primarily based on first-core values. 15.0.3.3.1 Doppler Coefficient The effective fuel temperature coefficient of reactivity (Doppler Coefficient) as shown in Section 4.3 is multiplied by a weighting factor to conservatively account for higher feedback effects in the higher power density portions of the core and to account for uncertainties in determining the actual fuel temperature reactivity effects. The Doppler weighting factor, which is Amendment No. 7 15.0-7 March 31, 1982
specified for each analysis, is 0.85 for cases where a less negative Doppler feedback produces more adverse results and 1.15 for cases where a more negative Doppler feedback produces more adverse results. The effective fuel temperature correlation is discussed in Section 4.3. This correlation relates the effective fuel temperature, which is used to correlate Doppler reactivity, to the core power. 15.0.3.3.2 Moderator Temperature Coefficient The events analyzed in this Chapter model moderator reactivity as a function of moderator temperature instead of a moderator temperature coefficient. Thi s method is used in order to more accurately calculate reactivity feedbacks due to the large moderator temperature variations which may occur during these events. The moderator temperature coefficients corresponding to these moderator reactiv ty functions at n =594 F) range from 0.0*10-{Ap /F to -3.5*10 Ap gminal
/F. full power conditions (TThesevaluesincludeaiYeun and bound the expected moderator temperature coefficients for all first cycle burnups, power levels, CEA configurations, and boron concentrations.
The most conservative, allowable value for the moderator temperature coefficient is assumed for each individual analysis. 15.0.3.3.3 Shutdown CEA Reactivity The shutdown reactivity is dependent on the CEA worth available on reactor trip, the axial power distribution, the position of the regulating CEAs, and the time in core lite. For transient analyses other than CEA ejection and Increase in Heat Removal (Sections 15.1), conservative. CEA worths of 10.0 percent and 6.4 percent LP were used for hot full power (HFP) and hot zero power (HZP), respectively. For CEA ejection events a conservative value of 3.81 percent Ao was used for HFP and conditions. The foregoing values include uncertainties, the most reactive CEA stuck in the fully withdrawn position, and the effect of cooldown to HZP temperature conditions (Sub-section 4.3.2.4.3). For Section 15.1 analyses at full power, a conservative CEA worth of 8.8 percent was used. This value is appropriate for end of equilibrium core, self-generated plutonium re-cycle (SGR) and includes uncertainties and the penaltic.s appropriate to HFP as indicated in Table 4.3-7. For Section 15.1 events initiated from HZP, a conservative CEA worth of 6.0 percent was sufficient to preclude significant post-trip return-to-power. This value covers uncertainties, the most reactive CEA stuck in the fully withdrawn position, and the penalties appropriate to HZP as indicated in Table 4.3.6. The power dependent insertion limit (PDIL) which will be included in the Technical Specifications assures that these worths are available upon reactor trip. The shutdown reactivity worth versus position curve which is employed in the Chapter 15 analyses, except where noted in individual discussions of events, is shown in Figure 15.0-2. This shutdown worth versus position curve was calculated assuming a more conservative rate of negative reactivity insertion than is expected to occur during the majority of operations, including power 15.0-8 Amendment No. 7 March 31, 1982
maneuvering. Accordingly, it is a conservative representation of shutdown g reactivity insertion rates for reactor trips which occur as a result of the
- ) events analyzed.
15.0.3.3.4 Effective Delayed Neutron Fraction The effective neutron lifetime and delayed neutron fraction are functions of fuel burnup. For each analysis, the values of the neutron lifetime and the delayed neutron fraction are selected consistent with the time in life analyzed. 15.0.3.3.5 Decay Heat Generation Rate Analyses assume decay heat generation based upon an infinite reactor operation at the initial core power level identified for each event. 15.0.4 RADIOLOGICAL CONSEQUENCES teveral of the events discussed are accompanied by the release of steam or liquid from the reactor coolant system or main steam system. The methodology and important input parameters used to assess the radiological consequences of these releases are discussed below. The CESEC computer code (described in Section 15.0.3.1.3), in combination with hand calculations, were used to determine the mass and energy releases as a function of time. These data are then used as input to the calculation of p radiological release to the atmosphere for determining thyroid and whole body doses at the exclusion area boundry. The assumptions used for calculating radiological releases to the atmosphere follow.
- 1. The initial primary system activity level is based on the maximum activity in the reactor coolant due to continuous full power operation with 1%
fai}edfuel. This activity level corresponds to a concentration of 2.09 x 10- Curies /lbm dose equivalent I-131.
- 2. The initial secondary system activity level is equal to 4.54 x 10-5 Ci/lbm dose equivalent I-131.
- 3. Primary-to-secondary steam generator tube leakage is included in the calculation of activity releases to atmosphere from the steam generators.
The " technical specification leakage" discussed in the analyses of Chapter 15 is a 1 gpm primary-to-secondary tube leak.
- 4. Events for which Reference 26 requires consideration of " iodine spiking" the following are used:
A. For iodine spiking generated by the event, the iodine appearance rate is increased by a factor of 500. B. For an abnormally high iodine concentration du to a previous iodine Cj spike, a reactor coolant activity of 2.72 X 10-2 Ci/lbm dose equivalent I-131 is assumed. 15.0-9 Amendment No. 7 March 31, 1982
The dose at the site exclusion area boundary (EAB) is calculated as follows:
- 1. Multiply the total primary system mass release by the primary system activity level and divide by the appropriate Decontamination Factor (DF).
This gives the total number of dose equivalent I-131 curies released from the primary system.
- 2. For the applicable secondary system releases, multiply the total secondary system mass release by the secondary system activity level and divide by the appropriate DF to obtain the equivalent I-131 curies released to the environment.
- 3. The curies of dose equivalent I-131 released to the environment can be converted to a thyroid dose by multiplying by the following factors:
- a. Breathing rate = 0.347 x 10-3 m 3/sec(Reference 2)
- b. Atmospheric dispersion factor (X/Q) = 2.00 x 10-3 sec/m 3
- c. 1-131 dose conversion factor = 1.48 x 10 6rem /Ci Combining these parameters gives an effective dose conversion factor equal to 1.027 rem /Ci. Thus, the total thyroid dose is calculated by multiplying the total activity release (dose equivalent I-131 curies) by the effective dose conversion factor (1.027 rem /Ci).
- 4. Additional assumptions used in the determination of radiological releases to the atmosphere for certain events are:
- a. For pipe breaks outside containment in piping connected to the reactor coolant system, the release to atmosphere accounts for the formation of steam resulting from depressurization of the reactor coolant.
- b. For pipe breaks or valve malfunctions outside containment in the main steam system which result in eventual dry-out of a steam generator, radioactive nuclides within the steam generator are assumed to be released to atmosphere with a decontamination factor (DF) equal to 1.
O Amendment No. 7 15.C-10 March 31, 1982
REFERENCES FOR SECTION 15.0_ O 1. NRC Regulatory Guide 1.70, Revision 2, " Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants," September 1975.
- 2. " Combustion Engineering Standard Safety Analysis Report," CESSAR Docket No. STN-50-470, December 1975.
- 3. Combustion Engineering Standard Safety Analysis Report (CESSAR) " System 80 Nuclear Steam Supply System Standard Nuclear Design Preliminary Design Approval," PDA-2, Docket No. STN 50-470, NRC, December 31, 1975.
; 4. "C-E Methods for Loss of Flow Analysis," CENPD-183, July 1975.
- 5. Typical Balance of Plant Design. See Applicants SAR
- 6. Revision 1, " Analyses of Anticipated Transients Without Reactor Scram in Combustion Engineering NSSSs," CENPD-158, May 1976.
- 7. "CESEC Digital Simulation of a Combustion Engineering Nuclear Steam Supply System," CENPD-107, April 1974, Proprietary Information.
- 8. "ATWS Model Modifications to CESEC," CENPD-107, Supplement 1, September
; 1974, Proprietary Information.
- 9. "ATWS Models Modification to CESEC" CENPD-107, Supplement 1, Amendment 1-P, November 1975, Proprietary'Information.
- 10. "ATWS Model for Reactivity Feedback and Effect of Pressure on Fuel,"
CENPD-107, Supplement 2, September 1974, Proprietary Information.
- 11. "ATWS Model Modifications to CESEC," CENPD-107, Supplement 3, August 1975.
- 12. "ATWS Model Modi fications to CESEC " CENPD-107, Supplement 4-P, December 1975, Proprietary Information.
- 13. "C0AST Code Description," CENPD-98, April 1973, Proprietary Information.
- 14. "STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program,"CENPD-135, April 1974 (Proprietary).
"STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program (Modification)," CENPD-135, Supplement 2, December 1974 (Proprietary).
i "STRIKIN-II, A Cylindrical Geometry Fuel Rod Heat Transfer Program," CENPD-135, Supplement 4, August 1976 (Proprietary).
- 15. " Calculative Methods for the C-E Large Break LOCA Evaluation Model," CENPD-132, Supplement 1, December 1974 (Proprietary).
- 16. "C-E Method for Control Element Assembly Ejection Analysis," CENPD-j 190-A, January 1976.
Amendment No. 7 15.0-11 March 31,1982
+
-c mi -y v--4i - ,--- - -_ -,- , - e-r ~ w r, ,g--. y -,
- 17. "HERMITE A Multi-Dimensional Space-Time Kinetics Code for PWR Transients,"
CENPD-188, March 1976, Proprietary Information.
- 18. " TORC Code - A Computer Code for Determining the Thermal Margin of a Reactor Core," CENPD-161-P, July 1975, Proprietary Information.
- 19. "CE Critical Heat Flux - Critical Heat Flux Correlation for CE Fuel Assemblies with Standard Space Grids," CENPD-162-P, April 1975, Proprietary Informa tion.
- 20. " Loss of Flow - CE Methods for Loss of Flow Analysis," CENPD-183, July 1975, Proprietary Information.
- 21. " TORC Code-- Verification and Simplified Modeling Methods," CENPD-206-P, January 1977, Propietary Information.
l
- 22. " Iodine Spiking," CENPD-180, March 1977.
- 23. " Radioactive Behavior in the RCS During Transients operations," Supplement 1 to CENPD-180 March 1977.
- 24. "RESAR 3-S Round 1 Questions"
- 25. Wash - 1400, " Reactor Safety Study - An Assessment of Accident Risks in U.S. Commercial Nuclear Power Plants," October,1975.
- 26. NUREG-75/087, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," as revised through December 31, 1978.
- 27. LD-82-001 (dated 1/6/82), "CESEC Digital Simulation of a Combustion Engineering Nuclear Steam Supply System", Enclosure 1-P to letter from A. E. Scherer to D. G. Eisenhut, December,1981.
l l O Amendment No. 7 15.0-12 March 31,1982
TABLE 15.0-1 O (This table intentionally blank) O l l Amendment No. 7 March 31, 1982
TABLE 15.0-2 CHAPTER 15 SUBSECTION DESIGNATION Each subsection is identified as 15.W.X.Y. With trailing zeros omitted where: W=1 Increase in heat removal by the secondary system 2 Decrease in heat removal by the secondary system 3 Decrease in reactor ccolant system flowrate 4 Reactivity and power distribution anomalies 5 Increase in reactor coolant inventory 6 Decrease in reactor coolant inventory 7 Radioactive release from a subsystem or component X = 1,2, etc. Event Title from Ref. 26 Y=1 Identification of causes and frequency classifications 2 Sequence of events and systems operation 3 Analysis of effects and consequences 4 Conclusions O O Amendment No. 7 March 31, 1982
___7 l TABLE 15.0-3 (This table intentionally blank) l I i i l l Amendment tio. 7 March 31, 1982 i
TABLE 15.0-4 REACTOR PROTECTION SYSTEM TRIPS USED IN THE SAFETY ANALYSIS Analysis Trip Event RPS Setpoint Delay Time High logarithmic Power Level 2% 550 ms Variable Overpower 17% or 130%(a) High Pressurizer Pressure 2450 psia 550 ms Low Pressurizer Pressure 1580 psia 550 ms Events not Low Steam Generator Pressure 820 psia Mentioned Below Low Steam Generator Water Level 40% wide range (b) 550550 ms ms High Steam Generator Water Level 99% ngr ow 550 ms ra ngele(i Low DNBR 1.19 .. 150 ms High Local Power Density 21 kw/ft("> 150 ms Variable Overpower 17% or 130%(a) Feedwater and High Pressurizer Pressure 2475 psia 550 ms Steam Line Breaks Low Pressurizer Pressure 1600 psia 550 ms Low Steam Generator Pressure 810 psia Low Steam Generator Water Level 35% wide range (b) 550550 ms ms High Steam Generator Water Level 99% ngrrow 550 ms rangele) Low DNBR 1.19 150 ms High Local Power Density 21 kw/ft (d) 150 ms
- a. See discussion in Section 7.2.
O
- b. Percent of distance between the wide range instrument taps above the lower tap. See Chapter 5 for details,
- c. The trip de' 3y times are discussed in Section 7.2 and inclede signal and sensor del ay.
- d. Setpoint value is set below the value at which fuel centerline melting would l occur. See Section 4.4.
l e. Percent of distance between the narrow range instrument taps above the lower ta p . See Chapter 5 for details. i l O Amendment No. 7 March 31, 1982
TABLE 15.0-5 INITIAL C0H91TIONS I Parameter Units Range Core Power % of 3800 Mwt 0 - 102 Radial 1-pin peaking - 1.40 to 1.63 factor (with uncertainty) Axial Shape Index -0.3 < ASI < + 0.3 Reactor Vessel Inlet % of 445600 gpm 95 - 116 Coolant Flowrate Pressurizer Water % distance between 26 to 60 Level upper tap and lower tap above lower tap Core Inlet Coolant F 500 - 580 (2) Temperature Reactor Coolant System psia 1785 - 2400 Pressure Steam Generator Water % distance between 40 - 88 Level upper tap and lower tap above lower tap area under axial shape in lower half of core (1) ASI = - area under axial shape in upper half of core total area under axial shape (2) Additional restrictions were apglied to: Section 15.2.3, minimum core inlet coolant temperature equals 560 F; and Section 15.1.5, maximum core inlet coolant temperature equals 570 F. I l lO
- v Amendment No. 7 March 31, 1982 l . .. -
TABLE 15.0-6 SINGLE FAILURES STEAM BYPASS CONTROL SYSTEM
- 1. Failure to Modulate Open
- 2. Failure to Quick Open
- 3. One Bypass Valve Fails to Quick Close
- 4. Excessive Steam Bypass Flow
- 5. Failure to Generate Automatic Withdrawal Prohibit Signal During Steam Bypass Operation
- 6. Failure to Generate the Reactor Power Cutback Signal REACTIVITY CONTROL SYSTEMS
- 7. Regulating Group (s) Fail (s) to Insert or Withdraw
- 8. A Single CEA Stuck *
- 9. A CEA Subgroup Stuck *
- 10. Failure to Initiate or Execute the Reactor Power Cutback
- 11. CEA's Withdraw upon Automatic Withdrawal Prohibit and/or CEA Withdrawal Prohibit FEEDWATER CONTROL SYSTEM
- 12. Failure of Reactor Trip Override
- 13. Failure of High Level Override TURBINE-GENERATOR CONTROL SYSTEM
- 14. Setback w/o Cutback
- 15. Failure to Modulate the Turbine Control Valves
- 16. Failure to Setback Given a Cutback (100% > Initial Power > 75%)
- 17. Failure to Setback (75% > Initial Power >- 60%)
- 18. Failure to Runback (60% > Initial Power)
- 19. Failure to Trip the Turbine PRESSURIZER PRESSURE CONTROL SYSTEM (PPCS)
- 20. Failure of Spray Control Valves to Open
- 21. Failure of Spray Control Valves to Close
- 22. Failure of Backup Heaters to Turn On
- 23. Failure of Backup Heaters to Turn Off Control Element Drive Mechanism does not respond to control signal.
Release of CEA(s) on trip is not inhibited. O Amendment No. 7 March 31, 1982 _ _ _ _ _ - - ~
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SPECIAL SY".BOLS t
$#801 P44Al#4 OfGA DEPA8fuRE f R3e sRJCLEATE 80!Ltw RATIO LOP LOSS OF POWER aP Otif tstuf!AL Pet 55eRE ( ACROSS A StuAt SG) a7 OlF7tatRTIAL PRES $Utf (StfWEEE sgs 4 sgy. .P *P y g-Psg2) AFW5 Act!LI ART Fr[01sAft (im!$ 575ftM MAF 4 00 LEAL POWtB Otasiff auf MAv at compos E LOGARifelt POWER LtyEL C31P0ntef5 WlfMin 00 CVEE-POWER LEVEL SWT BORIC ACIO mat-up QS STAsfuP POWER LDEL M STEAM Gt4tuf0R SL RIA RtB IRittflom ALAR 4 gytt guS UNDERVOLfAGE A Rig ROD itst'flon 14MIRif C8 C01sfAltstut SUILD1 CCGC C04fAlseutui CCP41ui CCW CCPIPontsf COOLING SM 'b*a A CD Con 0ftstR EXATLES*- CIA CONTROL ELEML47 A5 MIGM RCACTOR LOGAalf>l'IC P0htm Livil E'N CFM ConfROL [LEMtNT 08 CIDMC5 ConfROL EttMint OR t@!CAft1 A :;tLAt ?!It.
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TCT URIM Confa0L Tant 575 FEN 1 tWICf On Ptse McCfian Pts. St @t utt a h5 Vatti et ) Sf 5f tp butatt plCD AIClltt n515 SIEaALS) l l Amendment No. 7 ilarch 31, 1982 C-E Figure ; SEQUENCE OF EVENTS -
$ SYl1BOLS, ACRONYl15 AND DEFINITIONS B
t I
t l I I d
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SAFETY FUNCil0N DEFINIT!0RS Safety fvaction fvaction Descriette - Safety funo I. atACTIT!TT CouTEDL L COETA!Ipluf Reactivity Castsel Aaptd inserttee of negative reactietty late the Cantatnment (Trip) core to produce subcritical*:y teamediately PN888re/f*I following an telttating event. Control Amecttetty Costsel Estabitshreat of s.ff ectent terea concentration Cantal meet (Neon) In the core to rsatatata sutcriticailty following Pressere/feu the event estag safety tajectten. Centrol (ametrculatt Banctivity Contret totablishment of cold shutdom morea concentratton (Shutdemm) petor ta cooldoma of te. ptart. 4 spears and is necessary only tf safety tajectim has not occurred. A CIBel5710Lt asectietty Castrel settchtng of safety injection systm from injectica f^stible (Lang Ters) to rectreviation mode. L REACTOR NEAT RDEDeAL esta al Convective ustatena**e of core cooltag t>y astural streetation senet Reeval in the primary loop, includirq aatural convectio* Castrol h in the Core suff tCie9% to prevent violattoa of ggggg g,gg j g the feel performance lietts spectfied ta Table 15.0-3. Run.4 Pump unat metatenance of core cooIIng by means of forced flos 8" E "N aumevel (other than nomal four pur p flow) suf f ectent to H481TASIL prevent violation af the f.el stants specified la Table 15.0-3. Spectf tcally ret ccestiered as part E"*I "'"dII" of this safety functtoa are t ese actions perforced "** ' L**l to accomplish the emergency care cooltag safety functions. S. SASIGACTITE CouTa0L Centanament f, ECC lajectten Passe ( Provtston of coolant ta the RC5 suffletent to main-tain a coolatle reactor seceetry tutore low refuel
- tag water tant level signal. % Syn l ECC ancirtstation 9 (snart Ters) Provtsion of water low refueltag adequate tsaa coolaat to the level stgaal andRCS fo11e'a'"tte estam Seco,,ndary I 3 t,gia,
' set tchover. Core coolant ts recircwisted back into the primary system af ter it leaks out. (CC tactrculatten Provistoa of coolant to tne aCs to acaseve cold *** ' l' (Lang Ters) l shutdoun condittons folle='a sa'et i ec t ion. Estan11shment of hotTcoht eg r'ecir atToC anacter heat Ammovat Trovtston of coolant to the ecs to achieve cold *** (Santdoma) shutdown conettions. vstag the shutaom cooling gg,,, g,,,) system.
- 3. SEConcAar SYSTDe St. NTIon IstEGRITT Amsteretten laceasary Systen Matateaance of secondary systeus pressure and steam Pressere/ Level / Meat stat geaerator water level withta l'rtts such that the Control secoadary system does not everpress rtae and can be used to recove heat from the ,rtmary system. w,g g (
lecondary systen Malatenance of secondary syates pressere and steam Pronsor e/tevel/Maat 51st generator water levet eithin lletts s.ch that a Cantrol heat stat is matataired for the primary system and (Long Ters) is not overpressurtred. 11. Wert futt aDevat
- 4. PatnAar 5f5fDI IRTEGalTY Wt g,,g fu,e,l Primary systse Pressere/ Level Castrol Matatenance of primary system pressure and level within timtts such that the primary trsten pressure does not esceed the acceptsace g=iee16aes given se Tatte 15.0-3.
Primary tysten Control of primary system pressere aad level, and Pressere/tevel Castrol required associated acttons ch,rtag cooldom from (Lang fers) hot shutdom er stanens to cold sn.tdo-a coaditions te preveat esceeding pressure-tensweature geteeltaes durtag the coeldoun 9focess.
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l ca Fuaction Descristies (KrtialTY sintatensace of contalmeat press re and tammerase peratore eithta limits such that the contatasaat lategrity to l es tata taed. Pala C0 tepera ' , . - est.tenggCe fa it.Its of,e,atet8W9 i.I, e.a tteat p'ess.ure a e, t and,r ao e, taro s.stotag tne contaiwat spray e sttem ta tae recer. ha) casetten mode felle tag generettes of a las refuel-tag meter tapa level signal. MS CasTact bs Castrol taentificattoa ef. and condittentag of post-eveat cantanarent atmosenere er treatseat of eve-t generated flammables. te prevent formatten of flamaale se esple-stee stateres. lea 41TAsttlTY CondIGeatag of the post-event control reen atmosrhere to ensure hatttattitty and contrel of personnel redle-eles espos.re. > SJftetes ITY l Bulldtag Candsttentag of the post-event fuel headttes lty tingidtag atmosphere to ensure habitability and castrol o' persennel radiattaa espesere.
;frLutiff 31stian isolatsoa of contaiement butidtag te present escape of radiosettetty to the eastrons.
3 Iselatten testattaa of primary systen to preveat costant less or escape of redleartivity to the eaetrees, ites toelatie of all oc part of the seconeary system te present coolant less ce escape of radiescttelty te the eastreas.
' tert 11 flechanical and/or cheelcal treatapat of redteacttwe estertels te reduce the quantity that escaset er is discharged to the enviroat.
bternal See e6 eve and add setechtag to rectec=1sttee mode. 1 F A.C. pega l f (SF Pouer Starttag and leadtag of en.stte, stamany A.C. passe s ei,. I Lu, fr.asfe, of ieads f,se a.siitar, t,sasfe-P t. r
.the ae. staa.t-we transformer.
ai operater etther avtamaticelty se attaa. MAT 31 Inset Cesitag of the spent feel pool fellastag a less of LC. semer. Amendment No. 7 flarch 31, 1982
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C-E SEQUENCE OF EVENTS - F S 15 0 - SYttBOLS, ACRONYt15 AND DEFINITIONS jc s t
15.1 INCREASE IN HEAT REMOVAL BY THE SECONDARY SYSTEM 15.1.1 DECREASE IN FEEDWATER TEMPERATURE 15.1.1.1 Identification of Event and Causes A decrease in feedwater temperature may result from a loss of high pressure feedwater heaters. Loss of one of two high pressure feedwater heater drain tank pumps interrupts the steam extraction from the high pressure turbine to one of two parallel feedwater trains and results in the loss of three of six high pressure heaters. No other single failure would result in the loss of more heaters. Since each of the two feedwater heater trains increases the' enthalpy of the feedwater by about 100 Btu /lbm, the loss of one train (three heaters) would cause an overall reduction in the feedwater enthalpy of approximately 50 Btu /lbm. 15.1.1.2 Sequence of Events and System Operations J A decrease in feedwater temperature causes a decrease in the temperature of the reactor coolant, an increase in reactor power due to the negative moderator temperature coefficient, and a decrease in the reactor coolant system (RCS) and steam generator pressures. Detection of these conditions is accomplished by the RCS and steam generator low pressure alarms and the high linear power alarm. If the transient were to result in an approach to specified acceptable fuel design limits, trip signals generated by the core protection calculators would assure that low departure from nucleate boiling ratio (DNBR) or high local power density limits are not exceeded. 15.1.1.3 Analysis of Effects and Consequences V A comparison of the RCS temperatures shows that the maximum RCS temperature decrease for the decrease in feedwater temperature event is less than that for the inadvertent opening of a steam generator atmospheric dump valve (IOSGADV). The smaller cooldown results in less power increase and, consequently, in less DNBR decrease during the transient. Therefore, the systems operation described above and the resulting sequence of events would produce a DNBR transient less adverse than that associated with the 10SGADV event presented in Section 15.1.4. The limiting single failure with respect to fuel performance is the loss of offsite power on turbine trip for the same reasons as given in Section 1 15.1.4. This event in combination with a loss of offsite power msults in an event similar to the 10SGADV event in combination with a loss of offsite power j which is also presented in Section 15.1.4. All increased heat removal events analyzed in this section are characterized by decreasing RCS pressure due to the cooldown of the primary system. Thus, this event, or this event plus a single failure, will result in an insignificant increase in RCS pressure. 15.1.1.4 Conclusions The decreased feedwater temperature event results in a DNBR greater than 1.19 throughout the transient. The event in combination with a loss of offsite power results in only a limited number of fuel pins in DNB. For both cases, the RCS pressure remains well below 2750 psia. 15.1-1 Amendment No. 7 March 31, 1982 l
15.1.2 INCREASE IN FEEDWATER FLOW 15.1.2.1 Identification of Event and Causes An increase in feedwater flow is caused by the further opening of a feedwater control valve or an increase in feedwater pump speed. The maximum increase at full power is approximately 10% above nominal for the normal feedwater system. 15.1.2.2 Sequence of Events and System Operations An increase in feedwater flow causes a decrease in the temperature of the reactor coolant, an increase in reactor power due to the negative moderator temperature coefficient, a decrease in the RCS and steam generator pressures and an increase in steam generator water level. Detection of these conditions is accomplished by the RCS low pressure alarm and steam generator low pressure and high water level alarms. Protection against the violation of specified acceptable fuel design limits, as a consequence of 61 increase in feedwater flow, is provided by the low DNBR and high local power density trips. Protection against high steam generator water level is provided by the high steam generator water level trip. 15.1.2.3 Analysis of Effects and Consequences A comparison of RCS temperatures shows that the maximum RCS temperature decrease for the increase in feedwater flow event is less than that for the inadvertant opening of a steam generator atmospheric dump valve (IOSGADV) event. The smaller cooldown results in less power increase and, consequently, in less DNBR decrease during the transient. Therefore, the systems operation described above and the resulting sequence of events would produce a DNBR transient no more adverse than that associated with the 10SGADV event presented in Section 15.1.4. The limiting single failure with respect to fuel performance is the loss of offsite power on turbine trip for the same reasons as given in Section 15.1.4. This event in combination with a loss of offsite power results in an event similar to, but less severe than, the IOSGADV event in combination with a loss of offsite power which is also presented in Section 15.1.4. All increased heat removal events analyzed in this section are characterized by decreasing RCS pressure due to the primary system cooldown. Thus, this event, or this event plus a single failure, will result in an insignificant increase in RCS pressure. 15.1.2.4 Conclusions The increased feedwater flow event results in a DNBR greater than 1.19 throughout the transient. The event in combination with a loss of offsite power results in only a limited number of fuel pins in DNB. For both cases, the RCS pressure remains below 2750 psia. O Amendment No. 7 15.1-2 March 31, 1982
15.1.3 INCREASED MAIN STEAM FLOW O Identification of Event and Causes Q 15.1.3.1 An increase in main steam flow is caused by an inadvertent increased opening of the turbine admission valves. This may be caused by operator error or turbine load limit malfunctions and will result in no more than an 11% increase over the nominal full power steam flow rate. An increase in main steam flow can also result from the inadvertent opening of a turbine bypass valve or an atmospheric dump valve; however, these events are discussed separately in Section 15.1.4. 15.1.3.2 Sequence of Events and System Operations An increase in main steam flow causes a decrease in the temperture of the reactor coolant, an increase in core power and heat flux, and a decrease in reactor coolant system and steam generator pressures. Detection of these conditions is accomplished by the RCS and steam generator low pressure alarms and the high reactor power alarm. If the transient were to result in an approach to specified acceptable fuel design limits, trip signals generated by the core protection calculators would assure that low departure from nucleate boiling ratio (DNBR) or high local power density limits are not exceeded. 15.1.3.3 Analysis of Effects and Consequences A comparison of the RCS temperatures shows that the maximum RCS temperature (~N decrease for the increased main steam flow event is identical to that for the
- I ) inadvertent opening of a steam generator atmospheric dump valve (IOSGADV) i V event. This is due to the fact that both events cause an increase in main steam flow of 11%. Thus, the resultant power increase and the subsequent DNBR transient are also identical. Therefore, the systems operation described above and the resulting sequence of events for the increased main steam flow event will be similar to the 10SGADY event presented in Section 15.1.4. The limiting single failure with respect to fuel performance is the loss of off-site power at the time of turbine trip for the same reasons as given in Section 15.1.4.
This event in combination with a loss of offsite power is similar to, but no more severe than, the 10SGADV event combined with a loss of off-site power which is also presented in Section 15.1.4. i All increased heat removal events analyzed in this section are characterized by decreasing RCS pressure due to the cooldown of the primary system. Thus, this event, or this event plus a single failure, will show an insignificant increase in RCS pressure. 15.1.3.4 Conclusions The increased main steam flow event results in a DNBR greater than 1.19 throughout the transient. The event in combination with a loss of off-site power results in only a limited number of fuel pins in DNB. For both cases, the RCS pressure remains well below 2750 psia. t ( Amendment No. 7 15.1-3 Marcn 31, 1982
15.1.4 INADVERTENT OPENING OF A STEAM GENERATOR RELIEF OR SAFETY VALVE 15.1.4.1 Identification of Event and Causes Case 1: Event (IOSGADV) An atmospheric dump valve ( ADV) or a turbine bypass valve may be inadvertently opened by the operator or may open due to a failure of the control system which operates the valve. A steam generator safety valve will remain open only as a result of a valve failure. The opening of any of these valves will result in similar consequences because they relieve steam at the same maximum flow rate (11% of full power turbine flow rate). The inadvertent opening of a steam generator atmosperic dump valve (IOSGADV) is presented here to illustrate these events. Case 2: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve plus a single failure (10SGADV + LOP) For the events of this section, the major parameter of concern is the minimum hot channel DNBR. This parameter establishes whether a fuel design limit has been violated and thus whether fuel cladding degradation might be anticipated. Those factors which cause a decrease in local DNBR are:
- a. increasing coolant temperature
- b. decreasing coolant pressure
- c. increasing local heat flux (including radial and axial power distribution effects)
- d. decreasing coolant flow The single failure (SF) which yields the minimum transient hot channel DNBR is the SF which combines the greatest decrease in DNBR after initiation of a reactor trip signal with the lowest possible pre-trip DNBR. An evaluation of the SFs listed in Table 15.0.6 shows that the limiting SF for the event of this section is the loss of offsite power concurrent with a turbine trip (LOP) which is assumed to occur at a point in the transient at which the minimum hot channel DNBR is just above that which would cause the core protection calculators (CPCs) to initiate a reactor trip signal on low DNBR. The DNBR is thus at the lowest possible pre-trip value. The loss of flow due to the four pump coast down which results from the assumption of LOP following turbine trip causes a greater decrease in DNBR af ter reactor trip than other possible SFs.
None of the other SFs can cause a significant change in DNBR in the time interval between the start of the flow coastdown and the time at which core heat flux begins to decrease due to CEA insertion. Therefore the event plus single failure presented in this section is the 10SGADV + LOP. In addition to the assumed single failure of loss of offsite power it is assumed that the most reactive CEA is held in the fully withdrawn position following reactor trip. 15.1.4.2 Sequence of Events and Systems Operation Case 1: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve (IOSGADV). The opening of a steam generator ADV increases the rate of heat removal by the steam generators, causing cooldown of the RCS, Due to the negative moderator 15.1-4 Amendment No. 7 March 31, 1982
temperature coefficient, core power increases from the initial value of 102% of rated core power, reaching a new stabilized value of 113%. The feedwater (O ') control system, which is assumed to be in the automatic mode, supplies feedwater to the steam generators such that steam generator water levels are maintained. Acting upon the large power mismatch between the reactor and turbine and the audible indication of steam blowdown, the reactor operator , recognizes that the plant is in an abnormal state and manually trips the reactor. The analysis presented herein assumes this initial operator action is delayed until after 30 minutes following the first indication of the event. Following the generation of a turbine trip on reactor trip the feedwater control system enters the reactor trip override mode and reduces feedwater flow to 5% of nominal, full power flow. Since the steam bypass control system is { assumed to be in the manual mode with all bypass valves closed, the main steam safety valves (MSSVs) open to limit secondary system pressure and remove heat stored in the core and RCS. The secondary system pressure then decreases due to the cooldown caused by flow through the MSSVs and the ADV and the MSSVs close. The secondary system pressure continues to decrease to the point where a main steam isolation signal (MSIS) is generated. This causes one steam generator to be isolated from the flow path through the open ADV and causes main feedwater flow to be terminated. The affected steam generator continues to blow down and the level falls below the emergency feedwater actuation signal (EFAS) setpoint. However, the EFAS logic, acting upon the fact that the pressure in the affected steam generator is much lower than in the intact steam generator, prevents actuation of emergency feedwater flow. As a result the affected steam generator eventually boils dry. During the period of blowdown following reactor trip, reactor coolant temperatures and pressure decrease O" sl owly. After dryout of the affected steam generator, decay heat and heat addition from the walls and structure of the primary coolant system cause a gradual increase in reactor coolant temperatures and pressure. Relief of steam by the safety valves on the unaffected steam generator provides cooling which limits reactor coolant temperatures. Reactor coolant pressure is limited by the pressurizer safety valves. 1 Subsequent to tripping the reactor, the operator manually closes the ADV which had been inadvertently opened, terminating steam release to the atmosphere from the affected steam generator. In the analysis presented herein it is
- conservatively assumed that this action to close the ADV is delayed 20 minutes beyond the operator's initial action to trip the reactor, or a total of 50
- minutes after event initiation. RCS heat removal for plant stabilization and
- cooldown is accomplished by using the turbine bypass valves. The operator is
! assumed to initiate plant cooldown 30 minutes after he manually trips the reactor. Case 2: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve with Loss of Offsite Power Following Turbine Trip (IOSGADV + LOP). Up until the time of the assumed turbine trip the transient due to the 10SGADV is identical with or without the loss of offsite power. For the 10SGADV + LOP event the turbine is assumed to trip at 45 seconds into the transient, with the minimum hot channel DNBR stabilized at a value just above that which would cause the CPCs to initiate a low DNBR reactor trip. Credit is not taken for the control grade reactor trip that would occur upon turbine trip. A loss of 15.1-5 Amendment No. 7 March 31,1982
offsite power is assumed to occur immediately following turbine trip. The resultant coastdown of all four reactor coolant pumps causes the initiation of a low DNBR reactor trip via the action of the CPC's after detection of decreasing pump speed. Following turbine trip the feedwater control system enters the reactor trip override mode and reduces feedwater flow to 57, of nominal full power flow. Since the steam bypass control system is assumed to be in the manual mode with all bypass values closed, the MSSVs open to limit secondary system pressure and remove heat stored in the core and RCS. The secondary system pressure then decreases, due to the cooldown caused by the flow through the MSSVs and the ADV; and the MSSVs close. The secondary system pressure continues to decrease to the point where a MSIS is generated. This causes one steam generator to be isolated from the flowpath through the open ADV and causes main feedwater flow to be terminated. The affected steam generator continues to blow down and the level falls below the EFAS setpoint. However, the EFAS logic, acting upon the fact that the pressure in the affected steam generator is much lower than that in the intact steam generator prevents actuation of emergency feedwater flow. As a result the affected steam generator eventually boils dry. During the period of blowdown following reactor trip, reactor coolant temperatures and pressure decrease slowly. After dryout of the affected steam generator, decay heat and heat addition from the walls and structure of the primary coolant system cause a gradual increase in reactor coolant temperatures and pressure. Relief of steam by the safety valves on the unaffected steam generator provides cooling which in turn maintains natural circulation flow through the core and limits reactor coolant temperatures. Reactor coolant pressure is limited by the pressurizer safety valves. Acting upon a variety of indications--including the initial large power mismatch between the reactor and turbine, the steady decrease in steam generator pressures and water levels af ter reactor trip, the continued decrease in pressure and level in the affected steam generator af ter MSIS, the low steam generator pressure and water level alarms, and the audible indication of steam blowdown--the reactor operator diagnoses the incident and manually closes the ADV which had been inadvertently opened, terminating steam release to the atmosphere from the affected steam generator. The analysis presented herein assumes that this initial operator action to close the open ADV is delayed until 30 minutes following the first indication of the event. RCS heat removal for plant stabilization and cooldown is accomplished by manual control of the ADVs on the unaffected steam generator. The operator is assumed to initiate plant cooldown 30 minutes after he manually closes the ADV which had been inadvertently opened. 15.1.4.3 Analysis of Effects and Consequences A. Mathematical Model The nuclear steam supply steam (NSSS) response to the 10$GADV and the IOSGADV + LOP was simulated using the CESEC-III computer program described in section 15.0.3. The time-dependent thermal margin on DNBR in the reactor core was calculated using the TORC computer program which uses the CE-1 critical heat flux correlation described in Chapter 4. O 15.1-6 Amndment No. 7 Marcn 31, 1982
B. Input Parameters and Inf ual Conditions O Table 15.1.4-3 lists the assumptions and initial conditions used for these analyses in addition to those discussed in section 15.0. Conditions were chosen such that the overpower condition caused by the increase in steam flow results in the closest approach to the specified acceptable fuel design limits i (SAFDL) without causing a reactor trip. If core power increases more than the 11% due to the increasing steam flow, the Core Protection Calculators (CPC) will initiate a reactor trip and there will be no further degradation in thermal margin. For transients initiated at other sets of initial conditions, a trip may or may not be required depending on whether the initial thermal margin is as low as for the combination of conditions used in these analyses. C. Resul ts Case 1: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve (10SGADV) The dynamic behavior of the salient NSSS parameters following the IOSGADV is presented in Figures 15.1.4-1.1 to 16.1.4-1.15. Table 15.1.4-1 summarizes the major events, times and results for this transient. The opening of an ADV increases the rate of heat removal by the steam generators causing cooldown of the RCS. Due to the negative moderator reactivity coefficient, core power increases from 1021 of rated core power, reaching a new, stabilized value of 113% af ter approximately 30 seconds. , The feedwater control system, which is assumed to be in the automatic mode j supplies feedwater to the steam generators such that the steam generator water 4 1 ( levels are maintained. l During the 10SGADV transient the minimum transient DNBR of 1.19 first occurs ! at approximately 30 seconds and remains there until 1850 seconds when the j operator manually trips the reactor. At 1850.55 seconds the trip breakers open. Af ter a 0.34 second coil decay delay the CEA's begin to drop into the
! core at 1850.89 seconds. At this point, both the local and core average power j decrease rapidly and DNBR increases. From 1858 seconds to 1886 seconds the j MSSV's release steam.
At 2150 seconds the steam generator pressure drops below the MSIS setpoint of 820 psia. The MSIS initiates closure of the MSIV's and MFIV's. The MFIV's and MSIV's close by 2155 seconds. The affected steam generator dries out at 2650 seconds. At 3000 seconds the operator manually closes the open ADV. The i operator initiates plant cooldown at 3600 seconds. t ! Case 2: Inadvertent Opening of a Steam Generator Atmospheric Dump Valve with Loss of Offsite Power after Turbine Trip (IOSGADV + LOP) The dynamic behavior of the salient NSSS parameters following 10SGADV with loss of offsite power is presented in Figures 15.1.4-2.1 to 15.1.4-2.15. Table l 15.1.4-2 summarizes the major events, times and results for this transient. I The opening of an ADV increases the rate of heat removal by the steam generators causing cooldown of the RCS. Due to the negative moderator reactivity coefficient core power increases from 102% of rated core i Amendment No. 7 15.1-7 March 31, 1982
power, reaching a new, stabilized value of 113% after approximately 30 seconds. The feedwater control system, which is assumad to be in the automatic mode, supplies feedwater to the steam generators such that the steam generator water levels are maintained until the time of loss offsite power. During the IOSGADV + LOP transient the minim!!m transient DNBR of 1.195 first occurs at approximately 30 seconds and remains there until the assumed turbinetrip followed by loss of offsite power at 45 seconds. Due to decreasing core flow following the loss of power to the reactor coolant pumps, conditions existfor a low DNBR trip. At 45.6 seconds a low DNBR trip signal is initiated by the core protection calculators. The reactor trip breakers open at 45.75 seconds and after a 0.34 second coil decay delay the CEA's begin to drop into the core at 46.09 seconds. At 46.1 seconds the minimum transient DNBR of 1.05 is calculated to occur, after which DNBR rapidly increases as shown by Figure 15.1.4-2.15. By 50.5 seconds the CEA's are fully inserted. At E? seconds the MSSV's open and release steam until 81 seconds. Voids begin to form in the upper head of the reactor vessel at 74 seconds. At 313 seconds the steam generator pressure drops below the MSIS setpoint of 820 psia. The MSIS initiates closure of the MSIV's and MFIV's. The MFIV's and the MSIV's close by 318 seconds. At 1150 seconds the affected steam generator dries out. At 1800 seconds the operator manually closes the open ADV. The operator initiates plant cooldown at 3600 seconds. Due to the coastdown of the reactor coolant flow a reduction of DNBR below 1.19 is calculated to occur. Approximately 8% of the fuel pins are predicted to experience DNB. However, within 3 seconds of reactor trip, the local and average core heat flux have decreased enough such that no pins remain in DNB. 15.1.4.4 Conclusions The 10SGADV event results in a DNBR greater than 1.19 throughout the transient. The event in combination with a loss of off-site power (IOSGADV + LOP) results in a small fraction of the fuel pins being predicted to be in DNB for a few seconds. Thus at the most a limited number of fuel rod cladding perforations could occur for the IOSGADV + LOP event. For both cases, the RCS pressure remains well below 2750 psia, ensuring that the integrity of the RCS is maintained. - 0 15.1-8 Amendment No. 7 March 31, 1982
l O i i ) 1 ; I i 1 i 4 3 1 I i i THIS PAGE INTENTIONALLY BLANK 1 i, i i
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i ; i i r i: I l l 15.1-9 Amendment No. 7 i March 31,1982 ' l
O THIS PAGE INTENTIONALLY BLANK. O O:
i l 4, I TABLE 15.1.4-1 SEQUENCE OF EVENTS FOR FULL POWER INADVERTENT OPENING OF A STEAM GENERATOR
; ATMOSPHERIC DUMP VALVE (IOSGADV) i ' Time _(sec) Setpoint Event or Value 1.0 One atmospheric dump valve opens fully --
30.0 Steady-state hot channel DNBR achieved 1.19 1850 Operator initiates manual trip signal -- 1850.55 Trip breakers open -- 1850.89 CEA's begin to drop -- j 1858 Main steam safety valves open, psia 1282 1886 Main steam safety valves close, psia 1218 t 1872 Void begins to form in RV upper head -- i i 2150 Main steam isolation signal, psia 820 1 2155 MFIV's close completely -- 2155 MSIV's close completely -- 2650 Affected steam generator dries out -- ! 3000 Operator manually closes ADV -- 3600 Operator initiates plants cooldown -- 1 i l Amendment No. 7 March 31, 1982 l
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TABLE 15.1.4-2 SEQUENCE OF EVENTS FOR FULL POWER INADVERTENT OPENING OF A STEAM GENERATOR ATMOSPHERIC DUMP VALVE WITH LOSS OF 0FFSITE POWER AFTER TURBINE TRIP Time (sec) Setpoint Event or Value 0.0 One atmosphcric dump valve opens fully -- 30.0 Steady state hot channel DNBR achieved 1.19 45.0 Turbirie trips -- 45.0 Loss of offsite power occurs -- 45.6 Low DNBR trip occurs -- 45.75 Trip breakers open -- 46.09 CEA's begin to drop -- 46.1 Minimum transient DNBR 1.05 48 Hot channel DNBR increases above 1.195 -- 50.5 CEA's fully inserted -- 52 Main steam safety valves open, psia 1282 81 Main steam safety valves close, psia 1218 74 Void begin to form in RV upper head -- 313 Main steam isolation signal, psia 820 318 MFIV's close completely -- 318 MSIV's close completely -- 1150 Af fected steam generator dries out -- 1800 Operator manually closes ADV 3600 Operator initiates plant cooldown -- O Amendment No. 7 March 31, 1982
TABLE 15.1.4-3 ASSUMPTIONS AND INITIAL CONDITION FOR FULL POWER INADVERTENT OPENING OF AN ATMO3PHERIC DUMP VALVE (IOSGADV AND 10SGADV + LOP Parameter Value Initial Core Power Level, MWt 3876 Initial Core Inlet Coolant 575 Temperature, F Ingtial Core Mass Flow rate, 146.8 10 lbm/hr Initial Pressurizer Pressure, psia 2120 Initial Pressurizer Water Volume, ft 3 1100 Initial Steam Generator Pressure, psia 1175 Initial Steam Generator Inventory, 182,000 lbm per SG CEA Worth on Trip,10-2 AD -8.8 Core Burnup End of cycle ASI .3 l s. Max. Radial Peaking Factor 1.4 i 1 1 l l i Amendment No. 7 March 31, 1982
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- March 31, 1982 C-E IOSGADV WITH LOSS OF 0FFSITE POWER Figure AFTER TURBINE TRIP 15.1.4-E CORE POWER VS TIME 2.1
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O , 500 , , . . 400 - UNAFFECTED AND AFFECTED - 3 STEAM GENERATORS
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O 250000 , . . . 200000 - - 3 5 ur 5 x Si 150000 - o IE f3 V f2 3: 100000 - - S u k W:!
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'gdggg'f/ AFTER TURBINE TRIP MINIMUM DNBR VS TIME 15.1.4-2.15
l 15.1.5 STEAM SYSTEM PIPING FAILURES INSIDE AND OUTSIDE CONTAINMENT S l 15.1.5.1 Identification of Event and Causes A steam line break (SLB) is defined as a pipe break in the main steam system. SLB cases are chosen to maximize potential for a post-trip return to power,
; to maximize potential for degradation in fuel cladding performance, and to maximize dose at the site Exclusion Area Boundary. The results show that fission power levels remain sufficiently low following reactor trip to preclude degradation in fuel performance as a result of post-trip return to power, that degradation in fuel performance prior to trip is of sufficiently limited extent 4
that the core will remain in place and intact with no loss of core cooling capability, and that doses are within 10CFkl00 guidelines. The steam line breaks presented are: A. Cases chosen to maximize potential for a post-trip return to power:
- 1. A large steam line break inside containment during full power operation with concurrent loss of offsite power in combination with a single failure, and a stuck CEA (SLBFPLOP).
- 2. A large steam line break inside containment during full power operation with offsite power available in combination with a single failure and a stuck CEA (SLBFP).
- 3. A large steam line break inside containment during zero power O operation with concurrent loss of offsite power in combination with a single failure, and a stuck CEA (SLBZPLOP).
- 4. A large steam line break inside containment during zero power operation with offsite power available in combination with a single failure and a stuck CEA (SLBZP).
I B. Cases chosen to maximize potential for degradation in fuel performance and dose at the site Exclusion Area Boundary:
- 5. A small steam line break outside of containment upstream of the main steam isolation valve (MSIV) during full power operation with offsite power available in combination with a single failure, technical specification steam generator tube leakage, and a stuck CEA (SSLBFP).
I
- 6. A large steam line break outside of containment upstream of the MSIV during zero power operation with concurrent loss of offsite power in combination with a single failure, technical specification steam i generator tube leakage, iodine spike, and a stuck CEA (SLBZPLOPD).
The largest possible steam line break size is the double ended rupture of a steam line upstream of the MSIV. In the System 80 design, an integral flow restrictor exists in each steam generator outlet nozzle. The largest effective steam blowdown area for each steam line, which is limited by the flow restrictor throat area, is approximately 30L of the steam line cross-section area, or 1.28 square feet. Amendment No. 7 15.1-10 March 31, 1982
Results are presented in Appendix C which demonstrate that the cases listed above bound the results obtained for a spectrum of break sizes, loss of offsite power times, and single failures. 15.1.5.2 Sequence of Events and Systems Operation Steam line breaks are characterized as cooldown events due to the increased steam flow rate, which causes excessive energy removal from the steam aenerators and the reactor coolant system (RCS). This results in a decrease in reactor coolant temperatures and in RCS and steam generator pressure. The cooldown causes an increase in cere reactivity due to the negative mcderator and Doppler reactivity coef ficients. Detection of the cooldown is accomplished by the pressurizer and steam generator low pressure alarms, by the high reactor power alarm and by the low steam generator water level alarm. Reactor trip as a consequence of a steam line break is provided by one of several available reactor trip signals including low steam generator pressure, low RCS pressure, low steam generator water level, high reactor power, low DNBR trip initiated by the core protection calculators and, for inside containment breaks, high containment pressure. For a SLB that occurs with a concurrent losr. of offsite power, the events of turbine stop valve closure, termination of feedwater to both steam generators and coastdown of the reactor coolant pumps are assumed to be initiated simultaneously. Following reactor trip the most reactive control rod is conservatively assumed to be held in the fully withdrawn position. The depressurization of the affected steam generator results in the actuation of a main steam isolation signal (MSIS). This closes the MSIVs, isolating the unaf fected steam generator from blowdown ,and closes the main feedwater isolation valves (MFIVS), terminating main feedwater flow to both steam generators. Af ter the reduction of steam flow that occurs with MSIV closure,the level in the intact steam generator falls below the emergency feedwater actuation signal (EFAS) setpoint. The resulting EFAS causes emergency feedwater (EFW) flow to be initiated to the intact steam generator. The EFAS logic prevents feeding the affected steam generator. The pressurizer pressure decreases to the point where a safety injection actuation signal (SIAS) is initiated. The isolation of the unaffected steam generator and subsequent emptying of the affected steam generator terminate the cooldown. The introduction of safety injection boron upon SIAS causes core reactivity to decrease. The operator, via the appropriate emergency procedures, may initiate plant couldown by manual control of the atmospheric steam dump valves, or, in the event that offsite power is available, by using the MSIV bypass valves associated with the unaffected steam generator and the turbine bypass valves, any time a f ter the a f fected steam generator empties. The analysis presented herein conservatively assumes operator action is delayed until 30 minutes af ter first indication of the event. The plant is then cooled to 350 F and 400 psia, at which point shutdown cooling is initiated. A parametric study of single failures (See Appendix C) that would have an adverse inpact on the SLB has determined that the failure of one of the high pressure safety injection (HPSI) puups to start following SIAS has the most adverse effect for the full power case with concurrent loss of of fsite power and all zero power cases (Cases 1,3,4, and f>). Consequently, one HPSI pump is conservatively assumed to fail for these cases. The evaluation shows that for the full power SLB without loss O Amendment iso . 7 15.1-11 March 31,1982
of offsite power (Case 2) the most adverse effect is caused by failure of a MSIV on one of the steam lines on the intact generator to close following O\_,/ MSIS. Consequently for this case steam is assumed to continue to be released from the intact steam generator after MSIS at a rate consistent with the interface requirement of a maximum of 11% design steam flow rate non-isolable steam flow. This open flow path is represented by an effective flow area for steam blowdown from the intact steam generator of 0.2556 square feet. For case 5 (SSLBFP) there is no single failure which increases the potential for degradation in fuel cladding performance or which increases the offsite dose. The sequence of events for Cases 1 through 5 above are presented in Tables 15.1.5-1 through 5, respectively. The sequence of events for Case 6 is the same as for Case 3.
- 15.1.5.3 Analysis of Effects and Consequences i
A. Mathematical Models i The mathematical models and data transfer between codes used in the SLB analysis are presented in Appendix C. B. Input Parameters and Initial Conditions The initial conditions assumed in the analysis of the NSSS response to Cases 1 through 5 are presented in Tables 15.1.5-6 through 10, respectively. T he initial conditions for Case 6 are the same as those for Case 3. Justification of the selection of initial conditions and input parameters is presented in Appendix C.
\
C. Resul ts Case 1: Large Steam Line Break During Full Power Operation with Concurrent loss of Offsite Power (SLBFPLOP) The dynamic behavior of the salient NSSS parameters following the SLBFPLOP is presented in Figures 15.1.5-1.1 through 15.1.5-1.16. Table 15.1.5-1 summarizes j the major events, times, and results for this transient. Concurrent with the steam line break, a loss of offsite power occurs. At this time an actuation signal for the emergency diesel generators is initiated. Due to decreasing core flow following loss of power to the reactor coolant pumps, conditions exist for a low DNBR trip. At 0.6 second a low DNBR trip signal is initiated by the core protection calculators. At 0.75 second the reactor trip breakers cpen. After a 0.34 second coil decay delay, the CEAs begin to drop into the core at 1.09 seconds. At 8.0 seconds voids begin to form in the upper 1 head of the reactor vessel . At 8.3 seconds the steam generator pressure drops below the MSIS setpoint of 810 psia. The MSIS initiates closure of the MSIVs , and MFIVs. The MFIVs and MSIVs close by 13.3 seconds. EFW is automatically l initiated to the intact steam generator, assuming no delay af ter the EFAS signal on low level in the intact steam generator, at 13.3 seconds. At 120 j seconds the pressurizer empties. At 178 seconds the pressurizer pressure has dropped below 1600 psia and initiates a SIAS. Within 30 seconds of SIAS the y operable HPSI pump is loaded on the diesels and reaches full speed and the HPSI
' valves are fully open. At 237 seconds the affected steam generator empties.
I Amendment No. 7 15.1-12 March 31,1982
At 259 seconds the maximum core reactivity (+ 0.09 % to ) occurs. Sa fe ty injection boron begins to reach the core at 280 seconds. As shown by Figure 15.1.5-1.16, the values of DNBR remain above those for which fuel damage would be indicated. At a maximum of 30 minutes the operator, via the appropriate emergency procedure, initiates plant cooldown by manual control of the atmospheric dump valves, assuming that offsite power has not been restored. Shutdown cooling is initiated when the RCS reaches 350 F and 400 psia. Case 2: Large Steam Line Break During Full Power Operation with Offsite Power Available (SLBFP) The dynamic behavior of the salient NSSS parameters following the SLBFP is presented in Figures 15.1.5-2.1 through 15.1.5-2.15. Table 15.1.5-2 summarizes the major events, times, and results for this transient. At 6.95 seconds af ter the initiation of the steam line break a trip signal is initiated by the core protection calculators on a projected DNBR of 1.19'. At 7.1 seconds the reactor trip breakers open. Af ter a 0.34 second coil decay delay, the CEAs begin to drop into the core at 7.44 seconds. At 11.9 seconds voids begin to form in the upper head of the reactor vessel. At 13.5 seconds the steam generator pressure drops below the MSIS setpoint of 810 psia. The MSIS initiates closure of the MSIVs and MFIVs. The MFIVs and the operable MSIVs close by 18.5 seconds. EFW is automatically initiated to the intact steam generator, assuming no delay af ter the EFAS signal on low level in the intact steam generator, at 18.5 seconds. At 67 seconds the pressurizer empties. At 90 seconds the pressurizer pressure drops below 1600 psia and initiates a SI AS. Within 30 seconds of SIAS the HPSI pumps reach full speed and the HPSI valves are fully open. At 149 seconds the affected steam generator empties. At 151 seconds the maximum core reactivity (-0.18T oo) occurs. Safety injection boron begins to reach the core at 160 seconds. The values of DNBR remain above 10 during the post-trip approach-to-criticality portion of this transient. At a maximum of 30 minutes the operator, via the appropriate emergency procedure, initiates plant cooldown by manual control of the turbine bypass valves. Shutdown cooling is initiated when the RCS reaches 0 350 F and 400 psia. Case 3: Large Steam Line Break During Zero Power Operation with Concurrent loss of Offsite Pcwer The dynamic behavior of the salient NSSS parameters following the SLBZPLOP is presented in Figures 15.1.5-3.1 through 15.1.5-3.15. Table 15.1.5-3 summarizes the major events, times, and results for this transient. . 1 Concurrent with the steam l' atcak, a loss of offsite power occurs. At this j time an actuation signal '.r e _mergency diesel generators is initiated. Due to decreasing core fle. i c- ng loss of power to the reactor coolant pumps, conditions exist for a trip. At 0.6 second a low DNBR trip signal is initiated by the core ,rotec.cn calculators. At 0.75 second the reactor trip breakers open. Af ter a 0.34 setend coil decay delay, the CEAs begin to drop l into the core at 1.09 seconds. At 5.7 seconds the steam generator pressure I drops below the MSIS setpoint of 810 psia. The MSIS initiates closure of the MSIVs and MFIVs. The MFIVs and MSIVs close by 10.7 seconds. EFW is automatically initiated to the intact steam generator, assuming no delay af ter the EFAS signal on low level in the intact steam generator, at 10.7 seconds. Amendment No. 7 15.1-13 March 31,1982
At 45 seconds the pressurizer pressure drops below 1600 psia and initiates a SIAS. Within 30 seconds of SIAS the operable HPSI pump is loaded on the diesels and reaches full speed and the HPSI valves are fully open. At 55 seconds voids begin to form in the upper head of the reactor vessel. At 59 3' seconds the pressurizer empties. Safety injection boron begins to reach the core at 120 seconds. At 189 seconds the maximum core reactivity (-0.06%Ap ) occurs. At 1240 seconds the affected steam generator empties. The values of
- DNBR remain above 10 during this transient. At a maximum of 30 minutes the operator, via the the appropriate emergency procedure, initiates plant cooldown 1
by manual control of the atmospheric dump valves, assuming that offsite power has not been restored. Shutdown cooling is initiated when the RCS resches 350 F and 400 psia. Case 4: Large Steam Line Break Zero Power Operation with Offsite Power i Available (SLBZP) The dynamic behavior of the salient NSSS parameters following the SLBZP is presented in Figures 15.1.5-4.1 through 15.1.5-4.15. Table 15.1.5-4 summarizes the major events, times, and results of this transient. At 6.24 seconds af ter initiation of the steam line break, the steam generator pressure drops below the low steam generator pressure trip and MSIS setpoint of 810 psia. At 6.79 seconds the reactor trip breakers open. After a 0.34 second coil decay delay, the CEAs begin to drop into the core at 7.13 seconds. The MSIS initiates closure of the MSIVs and MFIVs. The MFIVs and MSIVs close by 11.3 seconds. EFW is automatically initiated to the intact steam generator, assuming no delay af ter the EFAS signal on low level in the intact steam i generator, at 11.3 seconds. At 41 seconds the pressurizer pressure drops below 1600 psia and initiates a SIAS. Within 30 seconds of SIAS the operable HPSI pump reaches full speed and the HPSI valves are fully open. At 48 seconds voids begin to form in the upper head of the reactor vessel. At 52 seconds the pressurizer empties. Safety injection boron begins to reach the core at 110 seconds. At 310 seconds the maximum core reactivity (-0.02%Ap ) occurs. At 418 seconds the affected steam generator empties. The values of DNBR remain above 10 for this transient. At a maximum of 30 minutes the operator, via the appropriate emergency procedure, initiates plant cooldown by manual control of the MSIV bypass valves associated with the unaffected steam generator and turbine bypass valves. Shutdown cooling is initiated when the RCS reaches 350 F and 400 psia. Case 5: Small Steam Lbe Break Outside Containment During Full Power Operation with Offsite Powcr available (SSLBFP) I The dynamic behavior of the salient NSSS parameters following a typical i limiting SSLBFP is presented in Figures 15.1.5-5.1 through 15.1.5-5.8. Table I 15.1.5-5 summarizes the major events, times and results for this transient. The consequences of this transient -- fraction of fuel rods predicted to experience DNB -- are the same as those for SSLBFPs for a spectrum of break sizes, due to the protective action of the core protection calculators (CPCs). 1 The break size assumed for the transient presented here was 1.0 square foot. Not later than 28.4 seconds after initiation of the steam line break, a trip
! signal is initiated by the CPCs on a projected DNBR of 1.19. At 28.55 seconds Amendment No. 7 15.1-14 March 31, 1982 l l
l
the reactor trip breakers open. Af ter a 0.34 second coil decay delay, the CEAs begins to drop into the core at 28.89 seconds. At 29 seconds a minimum transient DNBR of 1.10 is calculated to occur, af ter which DNBR rapidly increases, as shown in Figure 15.1.5-5.9. At 60 seconds voids begin to form in the upper head of the reactor vessel. At 84 seconds the steam generator pressure drops below the MSIS setpoint of 810 psia.The MSIS initiates closure of the MSIVs and MFIVs. The MFIVs and the operable MSIVs close by 89 seconds. Subsequently, the events of this transient follow a sequence similar to those of the SLBFP (Case 2). Since the cooldown is less rapid, the potential for post-trip degradation in fuel cladding performance is less for this case (SSLBFP) than for Case 2 (SLBFP). At a maximum of 30 minutes the operator, using the appropriate emergency procedure, initiates plant cooldown by manual control of the turbine bypass valves. Shutdown cooling is initiated when the RCS reaches 350 F and 600 psia. At the point of the minimum transient DNBR no more than 0.4% of the fuel rods are predicted to experience DNB. However, as a bounding assumption, 0.7% of the fuel pins are assumed to fail. All of the activity in the fuel gap for fuel rods that are assumed to fail is assumed to be uniformly mixed with the reactor coolant. The activity in the fuel clad gap is assumed to be 10% of the iodines and 10L of the noble gases accumulated in the fuel at the end of core life, assuming continuous full power operation. This results in a primary coolant activi ty of 617 pCi/gm. Assuming one gpm steam generator tube leakage, during a period of two hours af ter initiation of the SSLBFP, the integral leakage from the RCS through the affected steam generator is 720 lbm, which is assumed to be released to the atmosphere with a DF of 1. This mass release results in a contribution to the inhalation thyroid dose at the Exclusion Area Boundary (EAB) of 220 rem. The total steam released from the affected steam generator is 210.000 lbm. The ai fected steam generator will empty in two hours; therefore all the mass release from the affected steam generator to the atmosphere has a DF of 1. The calculated inhalation thyroid dose is 9.8 rem for the blowdown originating from the secondary system fluid discharge from the affected steam generator. Less than 89,000 lbm of steam from the unaffected steam generator will be released trough the steam line break. During the SSLBFP the MSIVs will isolate the unaffected steam generator and prevent it from emptying. Therefore, a DF of 100 is assumed in calculating iodine activity released from the unaffected steam generator. The resulting contribution to the inhalation thyroid dose at the EAB is less than 0.1 rem. Should condensor vacuum be lost during this transient, up to an addi tional 750,000 lbm of steam from the unaffected steam generator would be released to the atmosphere through the atmospheric steam dump valves. This would result in an additional contribution to the dose of not more than 0.4 rem. The foregoingg doses are calculated by the methods outlined in Section 15.0.4. Table 15.1.5-11 presents the major assumptions, parameters, and radiological consequences for this transient. In summary, the total two-hour inhalation thyroid dose at the EAB as a consequence of the SSLBFP is no more than 231 rem. Amendment No. 7 15.1-15 March 31, 1982 1
Case 6: Large Steam Line Break Outside Containment from Zero Power Operation with Loss of Offsite Power (SLBZPLOPD) Case 6 is included in Case 3, since the break of the latter can be either inside or outside of containment. The Figures, Tables, and Discussion for Case 3 apply to Case 6. Assuming one gpm steam generator tube leakage, during a period of two hours after initiation of the SLBZPLOPD the integral leakage from the RCS through the affected steam generator is 720 lbm, which is assumed to be released to the atmosphere with a DF of 1. This mass release results in a contribution to the inhalation thyroid doses at the EAB of: (a) 1.6 rem, assuming technical specification primary coolant activity; (b) 20.1 rem, assuming a pre-existing iodine spike; or (c) 41.5 rem, assuming an event-induced iodine spike. The total steam released from the affected steam generator is 300,000 lbm, which is the total initial mass inventory. The affected steam generator will I empty in two hours; therefore all the mass release from the affected steam generator to atmosphere has a DF of 1. The calculated inhalation thyroid dose is 14.0 rem for the blowdown steam originating from the initial steam generator mass inventory. Less than 850,000 lbm of steam from the unaffected steam generator will be released through the atmospheric steam dump valves and through the steam line break within two hours. During the SLBZPLOPD the MSIVs will isolate the
} unaffected steam generator and prevent it from emptying. Therefore, a DF of U 100 is assumed in calculating iodine activity released from the unaffected steam generator. The resulting contribution to the inhalation thyroid dose at the EAB is 0.4 rem.
The foregoing doses are calculated by the methods outlined in Section 15.0.4. Table 15.1.5-11 presents the major assumptions, parameters, and radiological consequences for this transient. In summary, the total two-hour inhalation thyroid dose at the EAB as a consequence of the SLBZPLOPD is no more than 56 rem. 15.1.5.4 Conclusion For the large steam line break in combination with a single failure and stuck CEA, with or without a loss of offsite power, fission power remains sufficiently low following reactor trip to preclude fuel damage as a result of post-trip return to power. For a large steam line break during zero power operation in combination with a loss of offsite power and technical specification tube leakage the two-hour inhalation thyroid dose at the EAB is well within 10CFR100 guidelines: (a) 16 rem, assuming technical specification primary coolant activity; (b) 35 rem, assuming a pre-existing iodine spike; or (c) 56 rem, assuming an event-induced iodine spike. i l Amendment No. 7 15.1-16 March 31, 1982
The maximum potential for radiological releases due to tuel failure occurs for small steam line breaks outside containment in combination with a stuck CEA. For these cases the s 3ximum potential for degradation in fuel cladding performance occurs prior to and during reactor trip. The fraction of fuel predicted to experience DNB for these events is no more than 0.4%. With the assumption of one gallon per minute steam generator tube leakage and a bounding assumption of 0.7% fuel failure the two-hour inhalation thyroid dose at the EAB is calculated to be no more than 231 rem, which is within the 10 CFR100 guidelines. Potential fuel failure is sufficiently limited to ensure that the core will remain in place and intact with no loss of core cooling capabilities. O O Amendment No. 7 15.1-17 March 31, 1982
l TABLE 15.1.5-1 SEQUENCE OF EVENTS F0_R A LARGE STEAM LINE BREAK DURING FULL POWER j OPERATION WITH CONCURREliT LOSS OF 0FFSITE POWER (SLBFPLOP)
- Time (Sec) Event Setpoint or Value I 0.0 Steam Line Break and Loss of --
Offsite Power Occur 0.6 Low DNBR Trip Condition Occurs, 1.19 Projected DNBR
! 0.75 Trip Breakers Open --
1.09 CEAs Begin to Drop --
. 8.0 Voids Begin to Form in RV Upper --
l Head 8.3 Main Steam Isolation Signal, psia 810 13.3 MFIVs Close Completely -- i 13.3 MSIVs close completely --
! 13.3 EFW Initiated to Intact Steam --
l Generator i 120 Pressurizer Empties -- 178 Safety Injection Actuation Signal, psia 1600
- 208 Safety Injection Flow Begins --
l 237 Affected Steam Generator Empties -- f 259 Max { mum Transient Reactivity, +0.09 10~ Ap l 277 Minimum Post-Trip DNBR 2.7
; 280 Safety Injection Boron Begins to --
Reach Reactor Core 1800 Operator Initiates Cooldown -- i l Amendment No. 7 i March 31, 1982 1
,e - .-
TABLE 15.1.5-2 SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBFP) Time (Sec) Event Setpoint or Value 0.0 Steam Line Break Occurs -- 6.95 Low DNBR Trip Condition Occurs, 1.19 Projected DNBR 7.10 Trip Breakers Open -- 7.44 CEAs Begin to Drop -- 11.9 Voids Begin to Form in RV Upper -- Head 13.5 Main Steam Isolation Signal, psia 810 18.5 MFIVs Close Completely -- 18.5 MSIVs Close Completely -- 18.5 EFW Initiated to Intact Steam -- Generator 67 Pressurizer Empties -- 90 Safety Injection Actuation Signal, 1600 psia 120 Safety Injection Flow Begins -- 149 Affected Steam Generator Empties -- 151 Maximum Transiegt -0.18 Reac ti vi ty , 10- Ap 151 Minimum Post-Trip DNBR 26 160 Safety Injection Boron Begins to -- Reach Reactor Core 1800 Operator Initiates Cooldown -- O Amendment No. 7 March 31, 1982
TABLE 15.1.5-3
/ x l i SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DURING ZERO POWER V OPERATION WITH CONCURRENT LOSS OF 0FFSITE POWER (SLBZPLOP AND SLBZPLOPD)
Time (Sec) Event Setpoint or Value 0.0 Steam Line Break and Loss of -- Offsite Power Occur 0.6 Low DNBR Trip Condition Occurs, 1.19 Projected DNBR 0.75 Trip Breakers Open -- 1.09 CEAs Begin to Drop -- 5.7 Main Steam Isolation Signal, psia 810 10.7 MFIVs Close-Completely -- 10.7 MSIVs Close Completety -- 10.7 EFW Initiated to Intact Steam -- Generator 45 Safety Injection Actuation Signal, 1600 psia D' 55 Voids Begin to Form in RV Upper Head -- 59 Pressurizer Empties 75 Safety Injection Flow Begins -- 120 Safety Injection Boron Begins to -- Reach Reactor core 189 Max { mum Transient Reactivity, -0.06 10~ Ap 1240 Affected Steam Generator Empties -- 1800 Operator Initiates Cooldown -- V_- Amendment No. 7 March 31, 1982
TABLE 15.1.5-4 SEQUENCE OF EVENTS FOR A LARGE STEAM LINE BREAK DilRING 7ERO POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBZP) Time (Sec) Event Setpoint or Value 0.0 Steam Line Break Occurs -- 6.24 Low Steam Generator Pressure 810 Trip and Main Steam Isolation Signal, psia 6.79 Trip Breakers Open -- 7.13 CEAs Begin to Drop -- 11.3 MFIVs Close Completely -- 11.3 MSIVs Close Completely -- 11.3 EFW Initiated to Intact Steam -- Generator 41 Safety Injection Actuation Signal, 1600 psia 48 Voids Begin to Form in RV Upper Head -- 52 Pressurizer Empties 71 Safety Injection Flow Begins 110 Safety Injection Boron Begins to -- Reach Reactor Core 310 Maxjmum Transient Reactivity, -0.02 10- an 418 Affected Steam Generator Empties -- 1800 Operator Initiates Cooldown -- O Amendment No. 7 March 31,1982
i t TABLE 15.1.5-5 l SEQUENCE OF EVENTS FOR A SMALL STEAM LINE BREAK OUTSIDE CONTAINMENT DURING FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SSLBFP) Time (Sec) Event Setpoint or Value l ! 0.0 Steam Line Break Occurs -- l 28.4 Low DNBR Trip Condition 1.19 Occurs,-Projected DNBR ! 28.55 Trip Breakers Open -- 28.89 CEAs Begin to Drop -- l 29 Minimum Transient DNBR 1.10 ) l 60 Voids Begin to Form in RV -- j Upper Head , 84 Main Steam Isolation Signal, 810 t psia i 89 MFIVs Close Completely -- ! 89 MSIVs Close Completely -- i 1800 Operator Initiates Cooldown -- i i i I 4 i 4 I l. 2 I l l i } Amendment No. 7
; March 31, 1982
TABLE 5.1.5-6 ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING FULL POWER OPERATION WITH CONCURRENT LOSS OF 0FFSITE POWER (SLBFPLOP) Parameter Assumed Value Initial Core Power Leel, MWt 3876 Initial Core Inlet Coolant Temperature, F 570 Initial Core Mass Flow Rate,106 lbm/hr 148.8 Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, ft3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 Axial Shape Index +.3 CEA Worth for Trip,10-2 op -8.8 Initial Steam Generator Inventory, Ibm, affected 182000 intact 148000 One High Pressure Safety Injection Pump Inoperative Core Burnup End of Cycle Blowdown Fluid Saturated Steam 2 Blowdown Area for Each Steam Line, f t 1.283 O Amendment No. 7 Marcn 31, 1982
TABLE 15.1.5-7 ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING
- FULL POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBFP) i Parameter Assumed Value Initial Core Power Level, MWt 3876 Initial Core Inlet Coolant Temperature, F 570 l Initial Core Mass Flow Rate,106 lbm/hr 148.8 i Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, ft3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 Axial Shape Index +.3 CEA Worth for Trip,10-2 Ap -8.8 Initial Steam Generator Inventory, lbm, affected 182000 intact 148000
!, One Main Steam Isolation Valve on Intact Steam Inoperative Generator Core Burnup End of Cycle Blowdown Fluid Saturated Steam 2
Blowdown Area for Each Steam Line, ft 1.283 l I f f I i( l Amendment No. 7 March 31, 1982 l
TABLE 15.1.5-8 ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING ZERO POWER OPERATION WITH CONCURRENT LOSS OF 0FFSITE POWER (SLBZPLOP AND SLBZPLOPD) Parameters Assumed Value Initial Core Power Level, MWt 10 Initial Core Inlet Coolant Temperature, F 575 Initial Core Mass Flow Rate,106 lbm/hr 147.6 Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, ft3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 Axial Shape Index +.3 CEA Worth for Trip,10-2 ap -6.0 Initial Steam Generator Inventory, lbm, affected 279000 intact 143000 One High Pressure Safety Injection Pump Inopera ti ve Core Burnup End of Cycle Bl owdown Fluid Saturated Steam Blowdown Area for Each Steam Line, ft 2 1.283 O Amendment No. 7 March 31, 1982
TABLE 15.1.5-9 Ch (V ) ASSUMPTIONS AND INITIAL CONDITIONS FOR A LARGE STEAM LINE BREAK DURING ZERO POWER OPERATION WITH OFFSITE POWER AVAILABLE (SLBZP) Parameter Assumed Value Initial Core Power Level, MWt 10 Initial Core Inlet Coolant Temperature, F 575 Initial Core Mass Flow Rate,106 lbm/hr 147.6 l Initial Pressurizer Pressure, psia 2400 Initial Pressurizer Water Volume, ft 3 1100 Doppler Coefficient Multiplier 1.15 Moderator Coefficient Multiplier 1.10 Axial Shape Index +.3 CEA Worth for Trip,10-2 Ap -6.0 Initial Steam Generator Inventory, Ibm, affected 279000 intact 163000 One High Pressure Safety Injection Pump Inoperati ve Core Burnup End of Cycle Blowdown Fluid Saturated Steam blowdown Area for Each Steam Line, ft2 1.283 b
'q)
Amendment No. 7 March 31, 1982
TABLE 15.1.5-10 ASSUMPTIONS AND INITIAL C0f1DITIONS FOR A SMALL LINE BREAK OUTSIDE C0flTAINMENT D_URiflG Fill.L POWER OPERATION WITH OFFSITE POWER AVAILABLE (SSLBFP) Parameter Assumptions Initial Core Power Level, MWt 3876 Initial Core Inlet Coolant Temperature, F 570 Initial Core Mass Flow Rate,106 lbm/hr 148.4 Initial Pressurizer Pressure, psia 2250 Initial Pressurizer Water Volume, ft 3 1100 Doppler Coef ficient Multiplier 1.15 Moderate Coefficient Multiplier 1.10 Axial Shape Index -0.359 Radial Peaking Factor, F R I'4 CEA Worth for Trip,10-2 Ap -8.8 Initial Steam Generator Inventory, lba, affected 182000 intact 148000 Core Burnup End of Cycle Blowdown Fluid Saturated Steam Blowdown area for each steam line, ft2 1 l i l l 9l Amendment No. 7 March 31,1982
TABLE 15.1.5-11 (Sheet 1 of 3) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF STEAM LINE BREAKS OUTSIDE CONTAINMENT UPSTREAM OF MSIV Value Parameter SSLBFP (Case 5) SLBZPLOPD (Case 6) A. Data and Assumptions Used to Evaluate the Radioactive Source Term
- a. Power Level, Mwt 3876 10
- b. Burnup, years 2 2
- c. Percent of Fuel Assumed to Experience DNB, % 0.7 0
- d. Reactor Coolant 4.6 4.6*
Activity Before Event Table 11.1.1-2 Table 11.1.1-2 (based on 3876 MWt), pCi/gm pi i e. Secondary System Section 15.0.4 Section 15.0.4
'%) Activity Before Event
- f. Primary System Liquid 525,600 525,600 Inventory, lbm
- g. Steam Generator Inventory, lbm
- Affected Steam 182,000 300,000 Generator I - Intact Steam 148,000 143,000 '
Generator i B. Data and Assumptions Used to Estimate Activity Released from i the Secondary System
- a. Primary' to Secondary 1.0 (total) 1.0 ( total )
Leak Rate, gpm
- b. Total Mass Release from 210,000 300,000 4 the Affected Steam Generator O *Except for case assuming pre-existing iodine spike (see footnote on next page). j i
Amendment No. 7 March 31, 1982 1
TABLE 15.1.5-11 (Cont'd.) ( Sheet 2 of 3) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A STEAM LINE BREAKS OUTSIDE CONTAINMENT UPSTREAtt OF MSIV Value Parameters SSLBAP (Case 5) SLBZPLOPD (Case 6)
- c. Total Mass Release from 840,000 850,000 the Intact Steam Generator
- d. Reactor Coolant System Activi ty Af ter Event, Ci Isotope I-131 8.568(+4)*
I-132 1.217(+5) I-133 1.605(+5) I-134 1.680(+5) I-135 1.469(+5) Kr-85M 1.421(+4) ** Kr-85 3.903(+2) Kr-87 2.400(+4) Kr-88 3.475(+4) Xe-131M 6.018(+2) Xe-133 1.618(+5) Xe-135 9.724(44) Xe-138 2.557(+4)
- e. Percent of Core Fission **
Products Assumed Released 10 to Reactor Coolant
- f. Iodine Decontamination 1.0 1.0 Factor in the Affected Steam Generator
- g. Iodine Decontamination 100 100 Factor in the Intact Steam Generator
- h. Credit for Radioactive No No Decay in Transit to Dose Point
- i. Loss of Offsite Power No Yes
- Numbers in parenthesis refer to the power of ten; e.g. 3.568(+4)=8.568x10 4
- lhree sub-cases are presented sub-case RC5 activity after event, pCi/gm a) technical specification activity 4.6 b) pre-existing iodine spike 60 /.oendaent . .c . /
c) event-induced iodine spike 124 ria rc h 11, 108'
TABLE 15.1.5-11 (Cont'd.) (Sheet 3 of 3) PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSE0VENCES
.0F A STEAM LINE BREAKS OUTSIDE CONTAINMENT UPSTREAM OF MSIV Value
} Parameter SSLBFP (Case 5) SLBZPLOPD (Case 6) l C. Dispersion Data
- 1. Distance to Exclusion 500 500 Area Boundary, m
- 2. Distance to Low 3000 3000 j Population Zone Outer l Boundary, m i 3. AtmosphericDjspersion Factor, sec/m 2.00 x 10-3 2.00 x 10-3 D. Dose Data i
l 1. Method of Dose Section 15.0.4. Section 15.0.4 Calculation
- 2. Dose Conversion Section 15.0.4 Section 15.0.4 j Assumptions j 3. Control Room Design See Applicant's See Applicant's Parameters SAR SAR a
i 1 1 I i i i 2 Amendment No. 7 March 31, 1982 1
O THIS PAGE INTENTIONALLY BLAl4K. g O
O 150 i i i I 125 - 5
-j 100 - -
e b M d ce 75 p et 50-- -
=
8 25 -- - I I 0 i 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 O C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure l l CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-E CORE POWER vs TIME 1.1
O 150 i i i i s d 125 - - s b x g 100 - - d 2 6 g 75 - - u 5 o_ O x' 50 -- - b i e u e 25 -- - 8 0 l ' ~' ' 0 100 200 300 400 500 TIME, SECONDS t l I Amendment No. 7 March 31, 1982 c-e FULL POWER LARGE STEAM LINE BREAK WITH Figure i CONCURRENT LOSS OF 0FFSITE POWER 15,1,5-S CORE HEAT FLUX vs TIME 1.2
O 2500 i i i i t 2000 m
' 1500 - -
N' a m E n_ 1000 - - O- $ e 500 - -
' ' ' I 0
0 100 200 300 400 500 TIME, SECONDS i Amendment flo. 7 March 31, 1982 O C-E FULL POWER LARGE SEAM LINE BREAK WITH Figure i 1 CONCURRENT LOSS OF 0FFSIE POWER 15,1,5-S RCS PRESSURE vs TIME 1,3
O 50000 , , , , j 40000 - - ! 8 e 5
- " 30000-- -
3:
@20000-. CORE _
M s 8 AFFECED SG LOOP - \ " 10000 y - R o 5 m e 0 - INTACT SG LOOP
-10000 I I I I i 0 100 200 300 400 500 l TIME, SECONDS Amendment fio. 7 March 31, 1982 V C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure S CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-REACTOR COOLANT FLOW RAE vs TIME 1.4
O 700 ; i i i 8 600 CORE OUTLET - vi b u 5 CORE AVERAGE r sm - -
- E -
z 5 o 400 - CORE INLET 8 O $ t; l
$300 - -
l I I I I 200 0 100 200 300 400 500
- TIME, SECONDS i
i Amendment No. 7
~' """ ' ' ' ' '
('d C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure l S REAC COC NT RA S A)vs TIME i 5A
b N~)) 700 i i 1 ' INTACT SG HOT LEG o' 600 - d c INTACT SG COLD LEGS E e 83 500 - N E AFFECTED SG HOT LEG <
@400 Uq 8 g
AFFECTED SG COLD LEGS 300 _ _ m 200 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER lARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S REACTOR COOLANT TEMPERATURES (B) vs TIME 1,5B
O V 10 i i i i MODERATOR 6 - N - D0PPLER g2 \ - I 0 4
-2
( Y (_/ E TOTAL SAFETY g INJECTION
-6 -
T CEA
-10 0 100 200 300 400 500 TIME, SECONDS
_ Amendment No. 7 March 31,1982 C-E FULL POWER lARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSITE POWER 15,1'5-S REACTIVITY CHANGES vs TIME 1.6
O 1200 i i i I 1000 -- - Su_ g' 800 -- B 3
$600-- -
a e N O a 5 m 400 - - u c_ 200 - I ' ' 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER lARGE SEAM LINE BREAK WITH rigure CONCURRENT LOSS OF 0FFSIE POWER 15.1.5-S PRESSURIZER WAER VOLUME vs TIME 1. 7
1200 i i i ' IWO - - f y
~ ~
INTACT STEAM GENERATOR a
% 600 - -
e o 400 - M s [ AFFECTED STEAM GENERATOR 200 - - 0 I I 0 100 200 300 400 500 TIME, SECONDS Amendtrent tio. 7 March 31,1982 C-E FULL POWER [ARGE STEAM LINE BREAK WITH Figure S CONCURRENT LOSS OF OFFSITE POWER 15.1.5-STEAM GENERATOR PRESSURES vs TIME 1.8
7000 i i i i o 5
- E g- 5000 -
M a S g 4000 -- - B 3 o E! 3000 - - O a
$ 2000 - -
k INTACT STEAM GENERATOR U 1000 7 f - g AFFECTED STEAM GENERATOR 1 I I ' 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POER LARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S STEAM GENERATOR BLOWDOWN RATES vs TIME 1.9
O 2500 , , , , g 2000'- - e
- E h1500-- -
g d O s" e a tij 500 - INTACT SEAM GENERATOR _
\ .
- AFFECTED SEAM GENERATOR 0
0 100 200 300 400 500 i TIME, SECONDS Amendment No. / ) March 31, 1982 . C-E , FULL POWER lARGE STEAM LINE BREAK WITH sgure CONCURRENT LOSS OF 0FFSITE POWER 15,1,5_ SEl6P8 / FEEDWATER FLOW RATES vs TIME 1.10
O i l l l l _ 1 400 - - m
>- 300 - -
b I s 5 e 200 - - a 100 - - INTACT AND AFFECTED STEAM GENERATORS 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C C-E FULL POWER lARGE STEAM LINE BREAK WITH CONCURRENT LOSS OF 0FFSITE BREAK sgore ! SE FEEDWATER ENTHALPY vs TIME 151[1f, 5_ l
i O sooooo , > > >
% 250000 - -
x 5 a N200000 - - 8 E W U 150000 h - s INTACT STEAM GENERATOR O E:iooooo 5
$ AFFECTED STEAM GENERATOR
- s
@ 50000 m
I I i 0 I 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 D C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure
~
S STEA GE O S I VENT RI vs TIME 1.'12 l l __. ._. . -
350000 i I i i (^') LJ 300000 - - 250000 - - m Bi 9 200000 - -
- E b
m y150000 - - O M (V o
~ 100000 -- -
50000 -- - I I I I 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E , FULL POWER LARGE STEAM LINE BREAK WITH rigur, CONCURRENT LOSS OF 0FFSITE POWER 15,1,5_ S E P8 / INTEGRATED STM MASS RELEASE THRU BREAKvsTIME 1. 13
p V 200 i i i i a 160 - - 04 5 g'120 - - if 8 C
$ 80 - -
O E D if di 40 - - 0 0 100 200 300 400 500 TIME, SECONDS
^
Amendment No. 7 l March 31, 1982 C-E FULL POWER lARGE STEAM LINE BREAK WITH r; CONCURRENT LOSS OF 0FFSITE POWER 15!u,e1. 5 - S SAFETY INJECTION FLOW vs TIME 1, 14
2500 i i i i TOP 0F REACTOR VESSEL 2000 - - 1 LIQUID VOLUME N1500 - -
$5 x
5 8 4 g 1000 500 TOP 0F HOT LEG 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S REACTOR VESSEL LIQUID VOLUME vs TIME 1.15
I O 10 i i i ' I 8 - - e E a E6 - - M 2 g4 - - O i
- E 2
0 1 I I i 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 > FULL POWER LARGE STEAM LINE BREAK WITH C-E pigur. CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-
.9 MINIMUM POST-TRIP DNBR vs TIME 1.16
1 150 , , i i i 125 - - a: ' 2 ' a 100 -
=l u_
8 g 75 -. - 15 c. d O $ o_ 50 -- W 8 50 -- - 0 i ' ' ' 0 100 200 300 400 500 TIME, SECONDS f Amendmen t No. 7 i O C-E March 31,1982 FULL POWER LARGE STEAM LINE BREAK WITH rigur. ' 0FFSITE POWER AVAILABLE 15.1.5-S CORE POWER vs TIME 2,1
150 , , , , 5 d 125 - - s US x
$ 100 a.
2 25 - - s 75 5 e s' 50 d s b p 25 - - ! 8 l C ' 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 O C-E FULL POWER LARGE STEAM LINE BREAK WITH OFFSITE POWER AVAIIABLE rigur. 15.1.5-S CORE HEAT FLUX vs TIME 2.2
O 2500 , , , , 2000 --
@1500 u'
8 m W 1000 - O a: 500 -
- 0 I I I I
- O 100 200 300 400 500 l TIME, SECONDS l
Amendment No. 7 March 31, 1982 d C-E FULL POWER LARGE STEAM LINE BREAK WITH Figure OFFSITE POWER AVAILABLE 15.1.5-S RCS PRESSURE vs TIME 2.3
7_ () 50000 i i ; k CORE 4TM - - S w 3
$ 30000 - _
AFFECED SG LOOP
\E s:
9 20000 - INTACT SG LOOP l z 5 ( ) 10000 - - f? o 55 0
-10000 I I I '
0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E i F : P A B gggy REACTOR COOLANT FLOW RAE vs TIME 15-1[g,3
700 i i i I CORE OUTLET (600 9 y CORE AVERAGE e I i2 CORE INLET W@ s5 - - W 5 h400 -
~
O 8 6
" 300 - -
I ' I l 200 i 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH rigure OFFSIE POWER AVAILABLE 15-E REACTOR C001 ANT TEMPERATURES (A) vs TIME 155h 2 l 1
O 700 i i i i 1
& 6% - -
m AFFECED SG HOT LEG 5 AFFECED SG COLD LEG M 5% - - h INTACT SG HOT LEG 5
~
$ #* /
O e R o
/
INTACT SG COLD LEG b 3% - - I I I I 200 O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 i 's March 31, 1982 C-E FULL POWER LARGE SEAM LINE BREAK WITH rigu,, OFFSIE POWER AVAILABLE S REACTOR COOLANT TEMPERATURES (B) vs TIME 15.1.5-2.5B l
v 10 i i i i h
- ~
6 o. (MODERATOR
<3
$2 z
[ DOPPLER - 2 o
]l D
y -2 - N
\
s (m~) W g TOTAL SAFETY INJECTION
-6 - -
CEA
~
0 100 200 3 4b 500 TIME, SECONDS _ Amendment No. 7 March 31, 1982 FULL POWER LARGE STEAM LINE BREAK WITH C-E rigure OFFSITE POWER AVAILABLE S REACTIVITY CHANGES vs TIME 15'.1' 26 5_
1200 , , , ,
- 1000 - -
1
' 800 -- -
S 3 x (600-3: x N 400 - - m u o_ 200 - - 0 ' ' ' I O 100 200 300 400 500 TIME, SECONDS 1 Amendment No. 7 O C-E FULL POWER LARGE STEAM LINE BREAK WITH March 31, 1982 rigur. OFFSITE POWER AVAILABLE 15.1.5-S PRESSURIZER WATER VOLUME vs TIME 2.7 4 a ,.7.-- - - - - - ~ _
O 1200 i i i I 1000 r- - 5 E E 12
$ INTACT STEAM GENERATOR e M0 -
??
W AFFECTED STEAM GENERATOR pb d 400 -
- s b
m 2M - 1 I i i i 0 0 100 200 300 400 500 l TIME, SECONDS 1 1 Amendment No. 7 March 31,1982 C-E FULL POWER LARGE SEAM LINE BREAK WITH Figure OFFSIE POWER AVAllABLE S SEAM GENERATOR PRESSURES vs TIME 15 5-
E i i i i M)00 - M m 5 5000 - W d 4000 - s 8 s: i O 2d 3000 - e E g 2000 -
- s AFFECED SEAM GENERATOR b
w 1000 - INTACT STEAM GENERATOR 0 ' 1
\ ' '
0 100 200 300 400 500 TIME, SECONDS i Amendment flo. 7 March 31, 1982 C-E FULL POWER lARGE STEAM LINE BREAK WITH rigure ' OFFSIE POWER AVAILABLE 1515-S STEAM GENERATOR BLOWDOWN RAES vs TIME j,iy i
-,_w--- n,-- we ,,- e -m e -
----m-> ----- --c.- em-oeye- -, -w-m--- m-vem--+,y
)
O 2500 , i i i
\
a 2000 -- bi E vi 1500 - I! {1000 O ie if 500 - INTACT STEAM GENERATOR -
\
g AFFECED SEAM GENERATOR 0 i I ' ' 0 100 200 300 400 500 TIME, SECONDS l Amendment No. 7 March 31, 1982 O.. C-E FULL POWER LARGE STEAM LINE BREAK WITH rigure OFFSITE POWER AVAILABLE - S FEEDWAER FLOW RAES vs TIME 15'.1'O 21 -
500 , i i i 1 1 400 - - 3 ca 5
>' 300 - -
S I i-. 5 g200 - - F 'T $ v e it' 100 - - INTACT AND AFFECED SEAM GENERATORS 0 ' ' ' ' l 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER lARGE SEAM LINE BREAK WITH p
/ OFFSIE POWER AVAIlABLE 18; .o,,1.5-S I FEEDWAER ENTHALPY vs TIME 2,11
V 300000 i i i i
% 250000 - -
x 2
"I N200000 8
!E W
5 150000 - INTACT SEAM GENERATOR m, o: (J 100000 - -
!M g AFFECTED SEAM GENERATOR E /
g 50000 - - w 1 I I I 0 0 100 200 300 400 500 l TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH r;gure
-l E OFFSIE POWER AVAILABLE STEAM GENERATOR LIQUID MASS vs TIME 15 1 5-i l 2 12 l
l
350000 , i i O V 300000 - - 250000 - - w Bi 9 200000 - -
- s b
m S 150000 - - m :2 b) E M
~
100000 - - 50000 -- - i l i I 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER lARGE STEAM LINE BREAK WITH Figure OFFSIE POWER AVAILABLE
,0 INEGRAED SEAM RELEASE vs TIME 15'.1 2I3 5-
2* , , , i a 160 - - bi E 3 g'120 - - cd 5 i y 80 - - ' E h
!f Oi 40 - -
0 0 100 200 300 400 500 TIME, SECONDS l l l Amendment No. 7 March 31, 1982 l O C-E FULL POWER LARGE STEAM LINE BREAK WITH rigur. 0FFSITE POWER AVAILABLE 15.1.5-SE SAFETY INJECTION FLOW vs TIME 2.14
2500 i r i i
\
2000 - TOP 0F REACTOR VESSEL - LIQUID VOLUME y'1500 - -
$5
- z s'
8
$ 1M -
O g S 500 - TOP 0F HOT LEG 0 I I i i - 0 100 200 300 400 500 TIME, SECONDS ( Amendment No. 7 i March 31,1982 C-E FULL POWER LARGE STEAM LINE BREAK WITH rigur, OFFSITE POWER AVAILABlf 15.1.5-2 REACTOR VESSEL LIQUID VOLUME vs TIME 2.15
i 150 i i i i 125 - e 2 S 100 - 2 ci d e 75 - - E O !! g 50 - - u 8 25 - 0 O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 O C-E ZERO POWER LARGE STEAM LINE BREAK WITH March 31, 1982 p; CONCURRENT LOSS OF 0FFSITE POWER 15!o,,1.5-S CORE POWER vs TIME 3.1
O 150 i i i i i 1 5 : d 1 25 - - l n : c5 x fii s: - - 2 100 d : 2 b s 75 - - 5 g 50 - - d W 25 - - 8 0^ O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E ZERO POWER lARGE STEAM LINE BREAK WITH rigor. CONCURRENT LOSS OF 0FFSITE POWER 15,1,5-S3B CORE HEAT FLUX vs TIME 3.2 l l
i i j iO 2500
, , i i 2000 -- -
GI o- 1500 - - U{ 5?
!O -
E 1000 - - O e 500 - - 0 ' ' ' ' i 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-S RCS PRESSURE vs TIME 3.3
'v' 50000 i i i i 4WW - - a bi E O 30000, - - Ef M s: 3 - [z 20000 CORE C's 5 8 [ '~
$1 AFFECTED SG LOOP x
/
/
INTACT SG LOOP
-10000 O 100 200 300 400 500 TIME, SECONDS Amendinent No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF 0FFSITE POWER 15,1,5-S$3P8ls REACTOR COOLANT FLOW RATE vs TIME 3.4
I V 700 i i i i O g 6@ - - u {5 CORE OUTLET 500 CORE AVERAGE m , 5 (^~)
\v 5x 300 -
CORE INLET _ 0 1 2 3 400 500 Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH r; i CONCURRENT LOSS OF 0FFSITE POWER 15$or,1.5-S REACTOR COOLANT TEMPERATURES (A) vs TIME 3.5A
(7 '\ .) l l l 1 600 ~ -
- INTACT SG HOT LEG u
E ) 500 - INTACT SG COLD LEGS
- E W
M h4@ - - (') V 8 AFF CTED SG HOT LEG y 9
$300
/
AFFECED SG COLD LEGS I I I 1 200 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 _ March 31, 1982 C-E ZERO POWER lARGE STEAM LINE BREAK WITH p;gure CONCURRENT LOSS OF OFFSITE POWER 15*1 5-8$l5 REACTOR COOLANT EMPERATURES (B) vs TIME 3,5B
("'T %) 10 i i i i MODERATOR
\ -
6 - - a
<1 vr DOPPLER g2 - -
5 5 x ,, R TOTAL ('~') I3 SAFE y INJECTION
-6 CEA I I I I
-10 0 100 200 300 400 500 TIME, SECONDS Amendment fio. 7 March 31, 1982 9 C-E ZERO POWER LARGE STEAM LINE BREAK WITH CONCURRENT LOSS OF 0FFSITE POWER Fi ure 15 1 5-E REACTIVITY CHANGES vs TIME j,f
O 1200 i i i i 1000 - - - 1 Y 800 - - a S e W g 600 -- - e N O 5 y400- - u o. 2M - - i 0 I I ' ' 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE SEAM LINE BREAK WITH rigur. CONCURRENT LOSS OF 0FFSIE POWER SE PRESSURIZER WARR VOLUME vs TIME 15.1.5-3.7 4
O 1200 i i i ' 1000 - _ M n. 6 800 - - - E u INTACT STEAM GENERATOR I 600 _ _ s O E o 400 - - 200 - AFFECTED STEAM GENERATOR _ 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 O C-E ZERO POWER LARGE STEAM LINE BREAK WITH March 31, 1982 rigure CONCURRENT LOSS OF 0FFSITE POWER S STEAM GENERATOR PRESSURES vs TIME 15'.1' 38 5-
E i i i i 6000 - - S m E
$ 5000-- -
)i M
d 4000 - z a E: y 3000 -- O x f2 g AFFECED SEAM GENERATOR W 2000 -- - 8
- s
~ ~
INTACT SEAM GENERATOR
/
I I I 0 I O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 O C-E ZERO POWER LARGE SRAM LINE BREAK WITH CONCURRENT LOSS OF 0FFSIE POWER ng 15 1 5-SSE SEAM GENERATOR BLOWDOWN RAES vs TIME 3.4
O l l 1 1 I o 2000 - 04 M (1500 g s: 3
$ 1000 -
O ie if INTACT STEAM GENERATOR 500 - j AFFECTED STEAM GENERATOR 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 C-E ZERO POWER [ARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF 0FFSITE POWER S FEEDWATER FLOW RATES vs TIME 5_ 1l:0
O 450 i i i I s 360 -- 5 s g 270 -- S 1 s 5 x 180 -- W k e 90 INTACT AND AFFECTED STEAM GENERATORS 0' ! O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSITE POWER S FEEDWATER ENTHALPY vs TIME 15.1 5-
- 3. 0
() O 300000 , , , i g 250000 - vi hti g 200000 - z z
$ 150000 -
;;g a e -INTACT STEAM GENERATOR O
V h a 100000 a 5 k
$ 50000 -
AFFECTED STEAM GENERATOR _ I I 0 I I O 100 200 300 400 500 TIME, SECONDS
- Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE SlEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSITE POWER 2 STEAM GENERATOR MASS INVENTORIES vs TIME 15.1}5-3,1
O' 300000 i i i i i 250000 - _ El
> 200000 - -
N c'
- E
@150000 - -
m C W f's $ el y100000 - - 5 50000-- - 0 I I I i O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31,1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigure CONCURRENT LOSS OF OFFSITE POWER 15*1 5-S INTEGRATED STM MASS RELEASE THRU BREAKvsTIME 3,13
200 i i i i c3 160 - - M E
"3 g'120 - -
Et' 5 C S m - -
~
O D
!i' di 40 - -
0 l I I I 0 100 200 300 400 500 TIME, SECONDS 1 ^ DEI 3i!78427 C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigur. CONCURRENT LOSS OF OFFSITE POWER 15.1.5- i S SAFETY INJECTION FLOW vs TIME 3.14 l l l
O 2500 i i i i TOP 0F REACTOR VESSEL 2000 - - 1 f
$1500 LIQUID VOLUME
$5 x
5 8 1000 - B S SM - l
- TOP OF HOT LEG 1
0 ' ' ' ' 0 100 200 300 400 500 TIME, SECONDS i i Amendment No. 7 O' C-E March 31, 1982 ZERO POWER LARGE STEAM LINE BREAK WITH Figure CONCURRENT LOSS OF 0FFSITE POWER 15.1.5-l E REACTOR VESSEL LIQUID VOLUME vs TIME 3.15
O 150 i i i i 125 -- - x 2 g 100 -- - 2 25
!E O 75 -- -
!!i n.
O e
@ 50 - - -
o_ u 8 i
- 25 - -
0' I I I I 0 100 200 300 400 500 4 TIME, SECONDS Amendment No. 7 March 31, 1982 l C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigur. OFFSIE POWER AVAILABLE S CORE POWER vs TIME 15{f 1 5-
150 i i i I i sg 125 - - 83
@ l@
n. 2 8 75 - - 5 6 5 ( - 50 - - 5 u_ w 25 - - 8 o 0> I I I O 100 200 300 400 500 TIME, SECONDS i Amendment No. 7 March 31,1982 ! C-E ZERO POWER LARGE STEAM LINE BREAK WITH r; ur. l OFFSIE POWER AVAIlABLE 15.1.5-S CORE HEAT FLUX vs TIME 4.2 l
O 2500 i i i i 2000 -
$ 1500 - -
N O
$1000 -
O E 500 - - 0 1 1 I ' 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH Figure 0FFSITE POWER AVAllABLE E916P8 / RCS PRESSURE vs TIME 15.1.5- ! 4.3
t'^'s 50000 , , i CORE 4WN - - a 04 E
$ 30000 -
AFFECTED SG LOOP e f M - 5 d 20000 INTACT SG LOOP 5 o () SJ o 10000 8 ts 6 e 0
~
0 100 200 300 400 500 TIME, SECONDS Amendment fio. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigure OFFSITE POWER AVAILABLE SMB REACTOR COOLANT FLOW RATE vs TIME 15 1 5-f,f
700 i i i i m CORE OUTlfT
.6W - -
E o 1 CORE AVERAGE
$ SW -
I! E s y400 - CORE INLET - (3 x C) S W -- M 3W - 2% i i i i 0 100 200 300 400 500 TIME, SECONDS 1 i I Amendment tio. 7 March 31, 1982 C-E ZERO POWER lARGE SEAM LINE BREAK WITH Figure OFFSITE POWER AVAILABLE 15 1,5-S REACTOR COOLANT EMPERATURES (A) vs TIME 4.5A
O (G 700 i i i i O 600 - - y S INTACT SG COLD LEGS B INTACT SG HOT LEG h500 - _
- E
$ [ AFFECTED SG HOT LEG so 4T - -
O O V g y AFFECTED SG COLD LEGS g 300 - - 0 lb 2b0 30 4b0 500 TIME, SECONDS l l l _ Amendment No. 7 March 31, 1982 C-E ZERO POWER lARGE STEAM LINE BREAK WITH p;gure 0FFSITE POWER AVAIlABLE 15*1 5-S REACTOR COOLANT IEMPERATURES (B) vs TIME 4,55
\
10 i i i 1 MODERATOR 6 - ~ DOPPLER 2 - ~ g ,
~
~
p $ TOTAL O = SAF TY INJECTION u
-6 CEA
-10 0 1 2h 3 4 500 TIME, SECONDS i
Amendment No. 7 March 31,1982 L c-g ZERO POWER LARGE STEAM LINE BREAK WITH i p; ure l 0FFSITE POWER AVAILABLE ef2@Fif / REACTIVITY CHANGES vs TIME 15 15$j-t 4 l _. -. ___
j i 4 1200 , , , , 1000 - - 1 Y 800 -- - 5 3 e 600 -- - e N 400 - - 0 E 2@ - - l I I I ' 0 O 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 O C-E ZERO POWER LARGE SEAM LINE BREAK WITH r;gur, ,i 0FFSIE POWER AVAILABLE l S PRESSURIZER WATER VOLUME vs TIME 151}5-4,
O 1200 i i i ' 1000 - - 5 E vr 800 - - - u a u 600 - [ INTACT STEAM GENERATOR e O a e 400 - - E h tn 200 - - AFFECTED STEAM GENERATOR 0 1 I I I 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982
' ZERO POWER LARGE STEAM LINE BREAK WITH C-E rigor.
0FFSITE POWER AVAILABLE E STEAM GENERATOR PRESSURES vs TIME 1515-
7000 i i i i MW - _ S e
- E 5000 - _
W a 9 g 4000 - - _ 8 a o d 3000 -- _ O x G R f5
$2000 -- _
3 W AFFECTED STEAM GENERATOR 1000 -- - w INTACT STEAM GENERATOR 0 i i i i1 0 100 200 3W 400 500 : TIME, SECONDS l
\
Amendment No. 7 March 31, 1982 O C-E ZERO POWER LARGE STEAM LINE BREAK WITH OFFSITE POWER AVAILABLE g 8y,, E STEAM GENERATOR BLOWDOWN RATES vs TIME 15 1 5-
(3 V 2500 i i i I o 2000 - - M 3
$1500 s
s: 9
$1000 - -
(o~\ g i 500 - INTACT STEAM GENERATOR AFFECTED STEAM GENERATOR 0 100 200 300 400 500 TIME, SECONDS l l l t Amendment No. 7 March 31, 1982 C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigure 0FFSITE POWER AVAILABLE 15*1 5-E FEEDWATER FLOW RATES vs TIME 4,16
O v 450 i i i i 3 360 5 m
>-' 270 -
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(~'T 300000 i i i l l
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tn 0 I I I k 0 100 200 300 400 500 TIME, SECONDS _ Amendment No. 7 March 31, 1982 C-E ZERO POWER lARGE STEAM LINE BREAK WITH r; 0FFSITE POWER AVAILABLE 15!u,,1.5-S STEAM GENERATOR LIQUID MASS vs TIME 4.12
350000 i i i i b v 300000 - - m 250CCC - _ Bi 9 Q2CCCC0 - G w Q le g 15CCCC - o O b u - ICCCC0 _ 50000 -- _ I I I I 0 0 100 200 300 400 500 TIME, SECONDS
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5 m 8 80 - [ O lW 5 40 - - l I I i 1 0 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 p March 31,1S82 U C-E ZERO POWER LARGE STEAM LINE BREAK WITH rigure 0FFSITE POWER AVAILABLE E SAFETY INJECTION FLOW vs TIME 15.1.5-4,}4
, 2500 i i i I ( TOP 0F REACTOR VES 2000 - _ LIQUID VOLUME 1 w 1500 - W 8
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2 8 5 75 g - e ci O E o_ so - u 8 25 - k 0 i i i i 0 20 40 60 80 100 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E FULL POWER SMALL STEAM LINE BREAK WITH Fi "re g AC POWER AVAILABLE CORE POWER vs TIME 15.1.5 - 5.1
'l 150 , , , , 5 d 125 - _ e M E5 n. 100 _. _ d 2 u. 75 - - 5 a u O a 5 50 - - u_ e 25 - _ 8 0 l l \ \ l 0 20 40 60 80 100 ; TIME, SECONDS l Amendment No. 7 March 31,1982 C-E FULL POWER SMALL STEAM LINE BREAK WITH rigur. AC POWER AVAILABLE 15 1 S CORE HEAT FLUX vs TIME 5.2 5-
i O 2500 i i i i l 2000 - - w 1500 - - E 8 m O e 0 1000 - - m 5% - - 0 i i i i 0 20 40 60 80 100 TIME, SECONDS Amendment No. 7 March 31,1982 C-E FULL POWER SMALL STEAM LINE BREAK WITH r; u,, AC POWER AVAILABLE 15.'1. 5 - S RCS PRESSURE vs TIME 5. 3
V 50000 i i i i CORE 40000 T - S 5 s 30000 - -
- AFFECTED SG LOOP h
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SE REACTOR COOLANT FLOW RATE vs TIME 5.4
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,/"3 Na ] 10 i i i i
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- Amendment tio. 7 March 31,1982 C-E FULL POWER SMALL SlEAM LINE BREAK WITH Figure g AC POWER AVAILABLE REACTIVITY CHANGES vs TIME b51.5-6
l ' \ s_ ,/ 5000 , , , , W 5"
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0 l i I I 0 20 40 60 80 100 TIME, SECONDS Amendment No. 7 9 C-E CONCURRENT LOSS OF AC POWER March 31, 1982 FULL POWER SMALL SEAM LINE BREAK WITH p;8u,, 15,1,5-SE STEAM GENERATOR BLOWDOWN RAES vs TIME 5.7 j
O 2500
' TOP 0F REkCTOR VES$EL i
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i
- O t
2.0 , 1 , 1.8 - e m 1.6 - z - o E o - E 5 1.4 - ! E j - 1.2 - l.0 , i i i , i , i , 0 10 20 30 40 50 TIME, SECONDS a l i I i Amendment No. 7 - March 31, 1982 l C-E FULL POWER SMALL STEAM LINE BREAK WITH AC POWER AVAILABLE lb.'Yr3 - E DNBR vs TIME 5. 9
15.2 DECREASE IN HEAT ret 10 VAL BY THE SECONDARY SYSTEM 15.2.1 LOSS OF EXTERNAL LOAD 15.2.1.1 Identification of Event and Causes i The loss of external load event is caused by the disconnection of the turbine
! generator from the electrical distribution grid.
15.2.1.2 Sequence of Events and Systems Operation A loss of external load generates a turbine trip which results in a reduction in steam flow from the steam generators to the turbine due to the closure of the turbine stop valves. The steam bypass control system (SBCS) and reactor power cutback system (RPCS) are both normally in the automatic mode and would be available upon turbine trip to accommodate the load rejection without necessitating reactor trip or the opening of main steam safety valves. Should a turbine trip occur with these systems in manual mode, a complete termination of main steam flow results and reactor trip would occur on high pressurizer pressure. If no credit is taken for immediate operator action, the main steam safety valves will open to limit the secondary pressure increase and provide a j heat sink for the NSSS. The operator can initiate a controlled system cooldown using the SBCS any time after reactor trip occurs. 15.2.1.3 Analysis of Effects and Consequences g The results of the loss of load event are no more limiting with respect to RCS pressurization than those of the loss of condenser vacuum (LOCV) event presented in Section 15.2.3. The LOCV also results in a turbine trip, however, feedwater flow is assumed to terminate following LOCV whereas it is assumed to ramp down to 5% following the loss of load. This larger reduction in heat removal capability results in a higher peak RCS pressure for the LOCV. Like the LOCV, the DNBR increases during the loss of load due to the increasing pressure. Thus, the initial DNBR is also the minimum DNBR. For the loss of load, due to its similarity with the LOCV event, there are no concurrent single failures which when combined with the loss of external load result in consequences more severe than the LOCV event with respect to RCS pressur-ization. The limiting single failure with respect to fuel performance is the loss of offsite power on turbine trip. This event with a concurrent loss of offsite power results in an event identical to the loss of flow (LOF) event discussed in Section 15.3.1. Results of the LOF event are directly applicable to the loss of external load with loss of offsite power on turbine trip. 15.2.1.4 Conclusions For the loss of load event and the loss of load with a concurrent single failure, the RCS pressure remains below 2750 psia thus ensuring primary integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding integri ty. O Amendment No. 7 15.2-1 March 31, 1982
l 15.2.2 TURBINE TRIP 15.2.2.1 Identification of Event and causes A turbine trip may result from a number of conditions which cause the turbine generator control system (TGCS) to initiate a turbine trip signal. A turbine trip initiates closure of the turbine stop valves. 15.2.2.2 Sequence of Events and Systems Operation A turbine trip results in a reduction in steam flow from the steam generators to tae turbine due to the closure of the turbine stop valves. The steam bypass control system (SBCS) and reactor power cutback system (RPCS) are both normally in the automatic mode and would be available upon turbine trip to accomodate the load rejection without necessitating reactor trip or the opening of main steam safety valves. Should a turbine trip occur with these systems in the manual mode, a complete termination of main steam flow results and reactor trip would occur on high pressurizer pressure. If no credit is taken for immediate operator action, the main steam safety valves will open to limit the secondary pressure increase and provide a heat sink for the NSSS. The operator can initiate a controlled system cooldown using the SBCS any time after reactor trip occurs. 15.2.2.3 Analysis of Effects and Consequences The results of the turbine trip event are no more limiting with respect to RCS pressurization than those of the loss of condenser vacuum (LOCV) event presented in Section 15.2.3. The LOCV also results in a turbine trip, however, feedwater flow is assumed to terminate following LOCV whereas it is assumed to ramp down to 5% following the turbine trip. This larger reduction in heat removal capability results in a larger peak RCS pressure for the LOCV. Like the LOCV, the DNBR increases during the turbine trip due to the increasing pressure. Thus, the initial DNBR is also the minimum DNBR for the loss of load. Due to its similarity with the LOCV events, there are no concurrent single failures which when combined with the turbine trip result in consequences more severe than the LOCV event with respect to RCS pressurization. The limiting single failure with respect to fuel performance is the loss of offsite power on turbine trip. This event with a concurrent loss of offsite power results in an event nearly identical to the loss of AC power which initiates the loss of flow (LOF) event discussed in Section 15.3.1. Results of the LOF event are directly applicable to the turbine trip event with loss of offsite power. 15.2.2.4 Conclusions For the turbine trip event and the turbine trip with a concurrent single failure, the RCS pressure remains below 2750 psia thus ensuring primary system integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding i n tegri ty. O Amendment No. 7 15.2-2 March 31, 1982
________m _. _ ._.__. -
- l l l 15.2.3 LOSS OF CONDENSER VACUUM 15.2.3.1 Identification of Event and Cause l A loss of condenser vacuum (LOCV) may occur due to the failure of the
, circulating water system to supply cooling water, failure of the main condenser ( j evacuation system to remove noncondensible gases, or excessive in-leakage of f j air through a turbine gland. The turbine is assumed to trip immediately j coincident with the cause for the loss of condenser vacuum. i When in the automatic mode, the Steam Bypass Control System (SBCS), if it controls atmospheric bypass valves, and the Reactor Power Cutback System (RPCS) , will function to reduce the steam generator and RCS pressure increases during a ! , turbine trip. These systems may allow the NSSS to continue operating at a , i reduced power level. However, in this analysis both the SBCS and RPCS are l assumed to be in the manual mode and credit is not taken for their functioning. l
\
l Consideration of single failures is addressed in Section 15.2.3.3D. l l l 15.2.3.2 Sequence of Events and Systems Operation : Table 15.2.3-1 presents a chronological sequence of events which occur j following the LOCV until operator action is initiated. Figure 15.0-1 contains : a glossary of SEA symbols and acronyms which may be used with the Sequence of l l Events Diagram, Figure 15.2.3-1, to trace the actuation and interaction of the l systems utilized to mitigate the consequences of this event. l l I s Table 15.2.3-2 contains a matrix which describes the extent to which normally operating plant systems are assumed to function during the transient. The success paths in the Sequence of Events Diagram, Figure 15.2.3-1, are as follows: Reactivity Control: An automatic reactor trip occurs on high pressurizer pressure. The CEA's begin to fall and insert negative reactivity. After the reactor trip a SIAS is generated on low pressurizer pressure. Additional negative reactivity is inserted when the borated safety injection water reaches the core. The boron concentration is adjusted to insure that a proper negative reactivity shutdown ; margin is achieved prior to cooldown. The boron concentration is adjusted by manually controlling the CVCS. If letdown is used for boration, the letdown isolation valves, which were closed on the SIAS/CIAS, must be reopened. ; Reactor Heat Removal: [ A CI AS occurs on low pressurizer pressure, following which the component l cooling water to the RCP's is lost. The operator restores cooling water to the ! reactor coolant pumps and a normal RCS cooldown is conducted. The SCS is mangally actuated when RCS temperature and pressure have been reduced to 350 F and 400 psia. This system provides sufficient cooling to bring the RCS to cold shutdown. O \ 15.2-3 Amendment No. 7 March 31, 1982
)
Primary System Integrity: A large reduction in primary system heat removal occurs when the main feedwater pumps and the turbine all trip. This causes the RCS pressure to increase and open the Primary Safety Valves (PSVs). Steam is initially released from the PSVs to the Reactor Drain Tank (RDT). The total steam release (1634 lbm) exceeds the RDT capacity and will probably cause the rupture disc to fail. A CIAS generated on low pressurizer pressure isolates the RCP controlled bleedoff fl ow. The bleedoff relief valve opens and passes the bleedoff flow to the ruptured RDT. The containment building receives some of the PSV and bleedoff liquid released in this event. The pressurizer level is restored automatically by the safety injection flow, even though other means are available. During cooldown, the pressurizer pressure and level control systems are manually operated to regulate pressure and level in the primary system. To perform this rti::n, the letdown isolation valves (which were closed on CI AS and SIAS) must be opened. When the RCS pressure has been reduced to approximately 650 psia, the operator will vent or drain the SITS to reduce their pressure and will then isolate them. Secondary System Integrity: The turbine and main feedwater pumps automatically trip at time zero on the loss of condenser vacuum. The turbine stop valves close instantly and an SBCS interlock prevents the bypass valves from opening. The secondary system pressure increases and opens the main steam safety valves. Emergency feedwater flow reaches the steam generators and restores the levels. Cancelation and reactuation of emergency feedwater may occur since the main steam safety valves remain open until 346 seconds. Once the plant parameters are stabilized, the operator initiates cooldown by utilizing one feedwater pump designated as " auxiliary" and intended for normal startup and shutdown of the plant in conjunction with the ASDS. If this pump is part of a separate Auxiliary Feedwater System then he will first secure the Emergency Feedwater System. He may also let the ESFAS regulate the feedwater flow by issuing and withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown entry conditions. See Applicant's FSAR for details of the Emergency and/or Auxiliary Feedwater Sy stems . Control Room Habitability: CI AS, SI AS or B0P signals may actuate control room habitability sy*.tems. See Applicant's FSAR for details. Fuel Handling Building Habitability: CIAS, SIAS or B0P signals may actuate fuel handling building habitability systems. See Applicant's FSAR for details. Radioactive Effluent Control: CI AS isolates various systems to reduce or terminate radioactive releases. CIAS actuates primary, secondary, and containment isolation equipment. Other actions may be initiated by BOP systems. See Applicant's FSAR for details. O Amendment No. 7 15.2-4 March 31, 1982
15.2.3.3 Analysis of Effects and Consequences A. Mathematical Model The NSSS response to a LOCV was simulated using the CESEC-II computer program described in Section 15.0. The initial DNBR was calculated using the TORC computer code (see Section 15.0.3.1.6) which uses the CE-1 CHF correlation described in Reference 19 of Section 15.0. B. Input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the NSSS response to a LOCV are discussed in Section 15.0. Table 15.2.3-4 contains the initial conditions and assumptions used for this event. The initial conditions for the principal process variables were varied within the ranges given in Table 15.0-5 to determine the set of initial conditions that would produce the most adverse consequences following a LOCV. Various combinations of initial core inlet temperature, core inlet flow, pressurizer pressure, steam generator level ani pressurizer water level were considered in order to evaluate the effects on peak reactor coolant system (RCS) pressure. Decreasing the initial core inlet temperature reduces the initial steam generator pressure, thereby delaying the heat removal associated with the opening of the main steam safety valves. However, the initial0 inlet temperature for this event was restricted to a minimum of 560 F. Decreasing the initial inlet temperature (as well as increasing the initial core flow rate) also minimizes the core average coolant temperature which results in the most positive moderator temperature coefficient. n ( l Reduction of the initial pressurizer pressure delays the occurrence of reactor trip on high pressurizer pressure and allows the maximum reduction in steam generator heat removal prior to and following trip. As a result maximum RCS overpressurization occurs, provided that the delay does not allow the main steam safety valves to open prior to reaching the peak pressure condition. Decreasing the initial pressurizer water level produces similar trip delays. C. Resul ts The dynamic behavior of important NSSS parameters following the loss of condenser vacuum is presented in Figures 15.2.3-2 to 15.2.3-14. The sudden reduction of steam flow, caused by the LOCV leads to a reduction of the primary-to-secondary heat transfer. The moderator reactivity increases slightly prior to the reactor trip due to a positive MTC as the average core temperature increases from the initial conditions. This added reactivity causes the core power to reach a maximum at 6.8 seconds. The rapid heatup of the reactor coolant results in a high pressurizer pressure trip condition at 6.4 seconds. The CEAs begin dropping in at the core at 7.3 seconds and limit the maximum core power to 102% of full power. The pressurizer safety valves open at 6.9 seconds and the maximum RCS pressure of 2742 psia is reached at 8.6 seconds. The main steam safety valves open at 6.9 seconds and the maximum secondary pressure of 1353 psia is reached at 14.0 seconds. V) Amendment No. 7 15.2-5 March 31, 1982
1 The RCS pressure decreases rapidly due to the combined ef fects of reactor trip and primary and main steam safety valves. The pressurizer safety valves close at 12.0 seconds and the main steam safety valves close at 346.0 seconds. Emergency feedwater flow automatically begins at 42.3 seconds and continues to fill the stam generators until a normal level is reached at 1408 seconds. At 963.0 seconds a safety injection actuation signal is generated when the pressurizer pressure decreases below 1580 psia. Borated water enters the RCS at 1150.0 seconds from the high pressure injection pumps. Thirty minutes after initiation of the events, the operator commences a cooldown using the atmospheric dump valves to release steam. The DNBR during the event, remains above its initial value of 1.4; therefore, DNB does not occur. D. Single Failures The LOCV event is assumed to abruptly and completely terminate both main steam and feedwater flow. Considering peak pressure criteria, the only mechanisms for mitigation of the reactor coolant system (RCS) pressurization are the pressurizer safety valves, the reactor coolant flow and main steam safety valves. The last two influence the RCS-to-steam generator heat transfer rate. There are no credible failures which can degrade pressurizer safety valve or main steam safety valve capacity. A decrease in RCS-to-steam generator heat transfer due to reactor coolant flow coastdown can only be caused by a failure to fast transfer (FFT) to of fsite power or a loss of offsite power (LOP) following turbine trip (i.e., two or four pump coastdown, respectively). The two and four pump coastdowns result in an immediate reactor trip, generated by the Core Protection Calculators (CPC's). Due to the rapid reactor trip, both of these failures reduce the peak pressure relative to the LOCV itself. With regard to fuel performance, decreased coolant flow is the only parameter which can significantly reduce the minimum DNBR during the LOCV event. FFT and LOP are the only single failures which impact coolant flow. LOCV by itsel f, however, produces an increasing DNBR (see Figure 15.2.3-2). This results in a greater thermal margin than is required to preclude a DNBR below 1.19 for either single failure. Consequently neither will cause fuel failure. LOP, however, because of the more rapid flow coastdown, causes a greater degradation in DNBR and hence is more limiting. The decrease in DNBR is shown in Figure 15.3.1-9. 15.2.3.4 Conclusions For both the loss of condenser vacuum event, and LOCV with a single failure, the maximum RCS pressure remains below 2750 psia, thus ensuring primary system i ntegri ty . The minimum DNBR remains above 1.19, thus ensuring fuel cladding integrity. O 15.2-6 Amendment No. 7 March 31, 1982
TABLE 15.2.3-1
~ SEQUENCE OF EVENTS FOR THE LOCV Time Setpoint Success (Sec) Event or Value Path 0.0 Loss of Condenser Vacuum 6.4 High Pressurizer Pressure Trip 2450 Reactivi ty Signal, psia Control 6.7 Main Steam Safety Valves Open 1282 Secondary psia System Integrity 6.7 Low Steam Generator Water Level, 40 Reactivity percent of wide range Control 6.8 Maximum Core Power, % of Design 102 Reactivity Power Control 6.9 Pressurizer Safety Valves, 2525 Priamry Open, psia Integrity System 7.3 CEA's Begin To Drop Reactivi ty a Control
[U \ 8.6 Maximum RCS Pressure, psia 2742 12.0 Pressurizer Safety Valves Close, 2462 Primary psia System Integrity 14.0 Maximum Steam Generator Pressure, 1353 psia 33.0 Emergency Feedwater Actuation 15 Signal, percent of wide range 43.0 Emergency Feedwater Flow 875 Secondary Ini tia ted, gpm System Integri ty 346.0 Main Safety Valves Close, psia 1218 Secondary System Integri ty 963.0 Safety Injection Actuation 1580 Reactor Heat Signal, psia Removal 1005.0 Safety Injection Flow Initiated Primary System v/ Integri ty Amendment No. 7 March 31, 1982
TABLE 15.2.3-1 (Cont'd) SEQUENCE OF EVENTS FOR THE LOCV Time Setpoint Success (Sec) Event or Value Path 1150.0 Borated HPSI Flow Enters the Core Reactivity Control 1408.0 EFAS Withdrawn, percent of wide 80 Secondary range System Integrity 1800.0 Operator Initiates Plant Cooldown Reactor Heat Removal O O Amendment No. 7 March 31, 1982
TfABLE 15.2.3-2 (Sheet 1 of 2) DISPOSITIO.'i 0F fl0ff' ALLY OPERATIt:G SYSTEMS FOR LOCV
/ s
(% A'
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- 1. Main Feedwater Control System j
- 2. Main Feedwater Pump Turbine Control System
- j
- 3. Turbine-Generator Control Syst: .r.* /
- 4. Steam Bypass Control System /
,-- 5. Pressurizer Pressure Control Syste.r. / !g 6. Pressurizer Level Control Systcm /
- 7. Control Element Drive Mechanism Control System /
- 8. Reactor Regulating System /
- 9. Core Operating Limit Supervisory System /
- 10. Reactor Coolant Pumps /
- 11. Chemical and Volume Control System /
- 12. Secondary Chcmistry Control System * /
- 13. Condenser Evacuation System * /
l 14. Turbine Gland Sealing System * /
- 15. Iluclear Cooling Water System * /
- 16. Turbine Cooling Water System * /
- 17. Plant Cooling Water System * /
- 18. Condensate Storage Facilities * /
l 19. Circulating Water System * / l 20. Spent Fuel Pool Cooling and Clean-Up System * / ,
- 21. fion-Class lE (ficn-ESF) A.C. Power * /
- 22. Class lE (ESF) A.C. Power * / ;
- Balance-of-Plant Systems
'l
_] Amendment No. 7 March 31, 1982
TABLE 15.2.3 2 (C0l!Til UED) (Sheet 2 of 2) DISPOSITI0il 0F f:GP." ALLY OPERATf f;G SYSTEMS FOR LOCV O
\ . .oo $
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SYSTEM
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- 23. l'cn-Class 1E D.C. Power
- I/ 1 l
Class lE D.C. Power *
- 24. /
i l l l I
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I i i, Balance-of-Plant Systems . Amendment No. 7 March 31,1982
EBLE 15.2.3-3 UTILI7ATIO!! 0F SAFET_Y_SYSTEf15
^ '
F_0R 1QCy a Os T, c , $s e Q l 1, C 9 o 0 Ys ###,$*n#+&'
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- 1. Reactor Protection System /
- 2. DiiBR/LPD Calculator
- 3. Engineered Safety Features Actuation Systems /
- 4. Supplementary Protection System 1 I
- 5. Reactor Trip Switch Gear /
l ,
- 6. Main Steam Safety Valves * /
- 7. Primary Safety Valves /
- 8. Main Steam Isolation System * /
- 9. Emergency Feedwater System * /
- 10. Safety Injection System /
, 11. Shutdown Cooling System /
- 12. Atmospheric Dump Vaive System * /
i
- 13. Containment Isolation System * /
- 14. Containment Spray System
- i
- 15. Iodine Removal System
- l 16. Containment Combustible Gas Control System * ;
- 17. Diesel Generators and Support Systems
- l
~
- 18. Component (Essential) Cooling Water System * /
- 19. Station Service Water System * /
l'o_t es :
- 1. Safety grade back-up to a safety grade system. v l
*Calance-of-Plant Systrz -
it"0Mr i
,Y March 5T'F"=d82
TABLE 15.2.3-4 ASSUMED INITIAL CONDITIONS FOR LOCV Parame ter Assumed Value Initial Core Power Level, ftwt 3876 Core Inlet Coolant Temperature, OF 560 Core Mass Flow, 106 lbm/hr 193.7 Pressurizer Pressure, psia 2200 Initial Pressurizer Water Level, Percent 26 of wide range Initial Core Minimum DNBR 1.4 Radial Peaking Factor 1.62 Steam Generator Water Level, percent of 61 wide range Doppler Coefficient Multiplier 0.85 CEA Worth for Trip,10 -2 Ap -10.0 Amendment No. 7 March 31, 1982
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i s 1 i t055 ef C0'aDItila eACgus ll.3 3 #N"1 I_l A11813%Af 809 sturt esswt.C, 8tatfos staf BEquuAt V attuAft Sil. SYsat eagg a tPgt Sta$ Q, ya {3gghh' h V*II' t/3 a e Stan f0 Flou Ottistas; to sec. U aJit; elf te 10 eI ACfisiff Cosfaol I/3 f 5Aa a 3 (conos) #Afm f&a GifdaA!!05 Estal Of SIAS P, L 4 6anstatt Stal Ano Clas al0 lC l0 e onto 2/4 flaa F.3 y A ePSa l*10ff p(13: 17se pse* laettf thJf ttfos mafga LPSI lef0f f st13.175 psis not, ACE (LOUTED) U I ACfuaft sis staat uPts til tsaa 9. 3.4 Sla$ A & LPSI PWr$. OPEt $11 Otafloe gjg a e DAttfl a4 45&. alt int tiths g ggg 1/I f1AA 4.3 Sla$ fe ft0W 8ttistaf; se sgCs.
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15.2.4 MAIN STEAM ISOLATION VALVE CLOSURE 15.2.4.1 Identification of Event and Causes V The main steam isolation valve (MSIV) closure event is initiated by the closure l of all MSIV due to a spurious closure signal. l 15.2.4.2 Sequence of Events and Systems Operation i The closure of all MSIV's results in the termination of all main steam flow. The decreased heat removal results in increasing primary and secondary temperatures and pressure. Reactor trip occurs on high pressurizer pressure. The pressure increases in the primary and secondary systems are limited by the pressurizer and steam generator safety valves. The operator can initiate a controlled system cooldown using the steam bypass control system any time after reactor trip occurs. 15.2.4.3 Analysis of Effects and Consequences The results of the MSIV closure event are no more limiting with respect to RCS pressurization than those of the loss of condenser vacuum (LOCV) event presented in Section 15.2.3. The LOCV also results in the termination of all main steam flow. However, main steam flow is terminated more rapidly during the LOCV since the closure time for the turbine stop valves is much shorter than that for the MSIVs. The faster reduction in heat removal results in a higher peak RCS pressure for the LOCV event. Like the LOCV, the DNBR increases during the MSIV closure event due to the ^ p) t increasing pressure. Thus, the initial DNBR is also the minimum DNBR for the
'V MSIV closure event.
Due to it similarity with the LOCV event, there are no concurrent single > failures which when combined with the MSIV closure event result in consequences more severe than the LOCV event with respect to RCS pressurization. The limiting single failure with respect to fuel performance is the loss of offsite power on turbine trip. This event with a concurrent loss of offsite power results in an event nearly identical to the loss of AC power which initiates the loss of flow (LOF) event discussed in section 15.3.2. Results of the LOF event are directly applicable to the MSIV closure with loss of offsite power on turbine trip. 15.2.4.4 Conclusions For the MSIV closure event and the MSIV closure with a concurrent single failure, the RCS pressure remains below 2750 psia thus ensuring primary system integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding integri ty. 15.2.5 STEAM PRESSURE REGULATOR FAILURE This event does not apply to the CESSAR SYSTEM 80 design and therefore is not presented. O V Amendment No. 7 15.2-7 March 31, 1982
15.2.6 LOSS OF NON-EMERGENCY A-C POWER TO THE STATION AUXIllARIES 15.2.6.1 Identification of Event and Causes The loss of non-emergency AC power to the station auxiliaries (LOAC) may result from either a complete loss of the external grid or a loss of the onsite AC distribution system. The LOAC is presented as the initiating event for the four pump loss of flow event discussed in Section 15.3.1. 15.2.6.2 Sequence of Events and System Operation When all normal AC power is assumed to be lost to the plant, the turbine stop valves close, and it is assumed that the area of the turbine control valves is instantaneously reduced to zero. Also, the feedwater flow to both steam generators is instanteously assumed to go to zero. The reactor coclant pumps coast down and the reactor coolant flow begins to decrease. A reactor trip will occur as a result of a low DNBR condition as the flow coastdown begins. The pressure increases in the RCS and steam generators are limited by the pressurizer and steam generator safety valves. The loss of all normal AC power is followed by automatic startup of the standby diesel generators, the power output of which is suf ficient to supply electrical power to all necessary engineered safety features system and to provide the capability of maintaining the plant in a safe shutdown condition. Subsequent to the reactor trip, stored and fission product decay energy must be dissipated by the reactor coolant system and main steam system. In the absence of forced reactor coolant flow, convective heat transfer coolant flow. Initially, the residual water inventory in the steam generators is used as a heat sink, and the resultant steam is released to atmosphere by the spring-loaded steam generator safety valves. With the availability of standby diesel power, emergency feedwater is automatically initiated on a low steam generator water level signal . Plant cooldown is operator controlled via the atmospheric dump valves until offsite power is restored at which time the steam bypass control system and the condenser are utilized for the remainder of the cooldown. 15.2.6.3 Analysis of Effects and Consequences The results of the LOAC event are identical to those of the loss of reactor coolant flow event presented in Section 15.3.1 and are no more limiting with respect to RCS pressurization than the loss of condenser vacuum (LOCV) event discussed in Section 15.2.3. During the LOCV event the plant experiences simultaneous losses of steam and feedwater flow and condenser availability. In addition, the plant experiences a complete loss of forced reactor coolant flow during the LOAC event. The loss of forced reactor coolant flow results in an earlier reactor trip for the LOAC event (on projected low DNBR) compared to the reactor trip for the LOCV event (on high pressurizer pressure). The earlier trip promotes a less severe primary-to-secondary heat imbalance and hence a lower peak RCS pressure for the LOAC event. The fuel performance for the LOAC is no more limiting than that for the loss of flow (LOF) event discussed in Section 15.3.1. The LOAC is the initiating event for the LOF so the fuel performance results of the LOF event are directly applicable to the LOAC event. Amendment No. 7 March 31, 1982 15.2-8
15.2.6.4 Conclusions [D For the LOAC event and the LOAC with a concurrent single failure, the RCS ( pressure remains below 2750 psia thus ensuring primary system integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding integrity. 15.2.7 LOSS OF NORMAL FEEDWATER FLOW 15.2.7.1 Identification of Event and Causes The loss of normal feedwater flow (LFW) event may be initiated by losing one or both main feedwater pumps or by a spurious signal being generated by the feedwater control system resulting in a closure of the feedwater control valve (s). 15.2.7.2 Sequence of Events and Systems Operation LFW results in decreasing water level and increasing pressure and temperature in the steam generators. The RCS pressure and temperature also rise until a reactor trip occurs either due to low steam generator water level or high pressurizer pressure. Assuming the steam bypass control system (SBCS) is in the manual mode of operation, termination of main steam flow due to closure of the turbine stop valves following reactor trip temporarily causes steam generator and RCS pressurization. The decrease in core heat rate after insertion of the CEAs in combination with the main steam safety valves opening restores the RCS to a new steady state condition. Emergency feedwater flow is automatically initiated on a low steam generator water level assuring sufficient steam generator inventory for core decay heat removal and cooldown (j to shutdown cooling entrance conditions. The cooldown is operator controlled using the SBCS and the condenser. 15.2.7.3 Analysis of Effects and Consequences The maximum RCS pressure for the LFW event is less than that for the loss of condenser vacuum (LOCV) event discussed in Section 15.2.3. The LOCV event results in the termination of main steam flow prior to reactor trip in addition to the total loss of normal feedwater flow. This additional condition aggravates RCS pressurization by further reducing the rate of primary-to-secondary heat transfer below that of the LFW event. Like the LOCV, the DNBR increases during the LFW event due to the increasing RCS presure. Thus the initial DNBR is also the minimum DNBR for the LFW event. There are no concurrent single failures which when combined with LFW result in consequences more severe than the LOCV event with respect to RCS pressur-ization. The limiting single failure with respect to fuel performance is the loss of offsite power following turbine trip. For the LFW event, prior to turbine trip the DNBR increases due to the RCS pressure increase. DNBR then briefly decreases af ter turbine trip due to the reactor coolant flow coast down on loss of offsite power. The DNBR decreases similar to the DNBR transient associated b V 15.2-9 Amendment No. 7 March 31, 1982 l
- - ~ . _ - _ _ _ _ _ _ - _ - - . - _ - .
with the total loss of reactor coolant flow event shown in Section 15.3.1, however, the DNBR decrease for LFW is not as severe due to the earlier reactor trip relative to the initiation of the coolant flow coastdown. Therefore, the minimum DNBR remains above 1.19. 15.2.7.4 Conclusions For the loss of feedwater flow event and the loss of feedwater flow with a concurrent single failure the RCS pressure remains below 2750 psia thus ensuring primary system integrity, and the minimum DNBR remains above 1.19 thus ensuring fuel cladding integrity. 15.2.8 Feedwater System Pipe Breaks Appendix 15B describes the methods used to evaluate the feedwater pipe breaks, and the results of the evaluation. O Amendment No. 7 March 31, 1982
15.3 DECREASE IN REACTOR COOLANT FLOWRATE 15.3.1 TOTAL LOSS OF REACTOR COOLANT FLOW V 15.3.1.1 Identification of Events and Causes A complete loss of forced reactor coolant flow will result from the simultaneous loss of electrical power to all reactor coolant pumps (RCPs). The only credible failure which can result in a simultaneous loss of power is a complete loss of offsite power. In addition, since a loss of offsite power is assumed to result in a turbine trip and renders the steam dump and bypass system unavailable, the plant cooldown is performed utilizing the secondary valves and atmospheric dump valves. A total loss of forced reactor coolant flow will produce a minimum DNBR more adverse than any partial loss of forced reactor coolant flow event. The loss of offsite power event plus a single failure will not result in a lower DNBR than that calculated for the loss of offsite power event alone. For decreasing reactor coolant flow events, the major parameter of concern is the minimum hot channel DNBR. This parameter established whether a fuel design limit has been violated and, thus, whether fuel damage might be anticipated. Those factors which cause a decrease in local DNBR are:
- a. increasing coolant temperature
- b. decreasing coolant pressure
- c. increasing local heat flux (including radial and axial power distribution effects)
TN d. decreasing coolant flow
)
For the loss of offsite power event, the minimum DNBR occurs during the first few seconds of the transient and the reactor is tripped by the CPCs on the approach to the DNBR limit. Therefore, any single failure which would result in a lower DNBR during the transient would have to affect at least one of the above parameters during the first few seconds of the event. None of the single failures listed in Table 15.0-6 will have any effect on the transient minimum DNBR during this period of time. Additionally, none of the single failures listed in Table 15.0-6 will have any effect on the peak primary system pressure. The loss of offsite power will make unavailable any systems whose failure could affect the calculated peak pressure. For example, a failure of the steam dump and bypass system to modulate or quick open and a failure of the pressurizer spray control valve to open involve systems (Steam Dump and Bypass System and Pressurizer Pressure Control System (PPCS) which are assumed to be in the manual mode as a result of the loss of offsite power and, hence, unavailable for at least 30 minutes. Another example involving the PPCS would be the failure of the back-up heaters to turn off. Since the event is characterized by increasing RCS pressure, the back-up heaters will not be called upon to operate in such a transient. For the reasons stated in the above paragraphs the loss of offsite power event with a single failure is no more adverse than the loss of offsite power event in terms of the minimum DNBR and peak primary system pressure. I LJ Amendment No. 7 15.3-1 March 31, 1982
15.3.1.2 Sequence of Events and Systems Operation Table 15.3.1-1 presents a chronological list and time of systems actions which occur during the total loss of reactor coolant flow event. Refer to Table 15.3.1-1 while reading this and the following section. The success paths referenced in Table 15.3.1-1 are those given on the sequence of events diagram (SED), Figure 15.3.1-1. This figure, together with Figure 15.0-1, which contains a glossary of SED symbols and acronyms, may be used to trace the actuation and interaction of the systems used to mitigate the consequences of this event. The timings in Table 15.3.1-1 may be used to determine when, after event initiation each action occurs. The sequence presented demonstrates that the operator can cool the plant down to cold shutdown during the event. If offsite power can be restored, then the operator may elect instead to stabilize the plant at a mode other than cold shutdown. All actions required to stabilize the plant and perform the reouired repairs are not described here. The sequence of events and systems operations described below represents the way in which the plant was assumed to respond to the event initiator. Many plant responses are possible. However, certain responses are limiting with respect to the acceptance guidelines for this section. Of the limiting responses, the most likely one to be followed was selected. Table 15.3.1-2 contains a matrix which describes the extent to which normally operating plant systems are assumod to function during the transient. Table 15.3.1-3 contains a matrix which describes the extent to which safety systems are assumed to function during the transient. The success paths in the sequence of events diagram, Figure 15.3.1-1, are as foll ows: Reactivity Control: A loss of electrical power to all reactor coolant pumps produces a reduction of coolant flow through the reactor core. The reduction in coolant flow rate causes an increase in the core average coolant temperature with a concurrent decrease in the margin to DNB. A low DNBR reactor trip is generated by the core protection calculators, as described in Section 7.2. This prevents the minimum DNBR calculated with the CE-1 CHF correlation from decreasing to less than 1.19 at any time during the transient. The CEAs begin to drop into the core 1.09 seconds af ter the loss of electrical power to the RCPs inserting negative reactivi ty. The 1.09 second delay conservatively includes the largest possible delay times for sensor delays, CPC calculation period, CEDM dead time, and CEDM coil decay time. Prior to initiating or during manual cooldown the operator adjusts the boron concentration to insure that a proper negative reactivity shutdown margin is achieved. This is accomplished by using the HPSI pumps which also replace RCS volume shrinkage. The operator must also borate using the charging pumps by manually loading them on the diesel generators and then aligning them to the refueling water tank (RWT), the source of borated water. O Amendment No. 7 15.3-2 March 31,1982
Reactor Heat Removal: l/O Following the total loss of reactor coolant flow, reactor heat removal takes Q) place by means of natural circulation. The steam generators provide primary to secondary heat transfer. The Shutdown Cooling System (SCS) is manually actuated when RCS temperature and pressure have been reduced to 350 F and 400 psia, respectively. This system provides sufficient cooling flow to cool the RCS to cold shutdown conditions. Secondary System Integrity: The turbine is assumed to trip our loss of offsite power. The loss of offsite power produces a loss of load on the turbine which generates a turbine trip signal. The turbine stop valves are closed as a result of the trip. The steam bypass control system becomes unavailable due to the loss of offsite power and subsequent loss of condenser vacuum. Also, as a result of the loss of condensor vacuum, main feedwater flow to the steam generators is lost. This sequence of events results in opening of the Main Steam Safety Valves (MSSVs) which limits secondary system pressure and removes heat stored in the core and the RCS. Once the flow parameters are stablized, the operator initiates cooldown (assumed to be initiated 30 minutes after event initiation) utilizing the Auxiliary Feedwater System ( AFWS) and the atmospheric dump valves. The AFWS may be a separate system or may be one emergency feedwater pump designated as " auxiliary" and intended for normal startup and shutdown of the plant. The operator may let the ESFAS regulate the feedwater flow by p) (V issuing and withdrawing EFAS-1 and/or EFAS-2 signals down to cold shutdown entry conditions. See Applicant's FSAR for details of the Emergency and/or Auxiliary Feedwater Systems. As the cooldown proceeds, the operator reduces the main steam isolation actuation setpoint to prevent the inadvertent generation of an MSIS. Primary System Integrity: The pressurizer assists in the control of the RCS prssure and volume changes during the transient by compensating for the initial expansion of the RCS fluids. The combination of the loss of primary system heat sink (turbine stop valves close) with the reduction of reactor coolant flow results in an increase in RCS pressure which is limited by the primary safety valves. The reactor drain tank receives the released steam. During the cooldown, the operator may control RCS pressure and pressurizer level by turning on the HPSI pumps and throttling the HPSI discharge valves to control the rate of change of RCS pressure. The operator may also control RCS pressure and pressurizer level via manual actuation and control of the charging pumps and related auxiliary spray. As the cooldown proceeds, the operator will reduce the safety injection actuation setpoint to prevent the inadvertent generation of an SIAS. When the RCS pressure has been reduced to approximately 650 psia, the operator will vent or drain the safety injection tanks to reduce their pressure and will isolate them. l LC) , 15.3 3 Amendment No. 7 March 31, 1982
Restoration of AC Power: A low voltage on the 4.16 kV safety buses generates an undervoltage signal which starts the diesel generators. The non-safety buses are automatically separated from the safety buses and all loads are shed (except for load centers). Af ter each diesel generator set has attained operating voltage and frequency, its output breaktr closes connecting it to its safety bus. ESF equipment is then loaded in sequence on to this bus. Spent Fuel Heat Removal: Spent Fuel Pool (SFP) cooling is terminated on the loss of normal power to the ESF loads. Spent fuel heat removal is continuously accomplished by utilizing the heat capacity of the SFP water. Pool cooling is restored by manually loading the SFP cooling pumps onto the diesel generators and by alignir.g the SFP heat exchangers to receive essential cooling water. 15.3.1-3 Analysis of Effects and Consequences A. Mathematical Mode The NSSS response to a total loss of reactor coolant flow was simulated using the CESEC-II computer program described in Section 15.0.3. The minimum DNBR was calculated using the TORC computer code (see Section 15.0.3.) which uses the CE-1 CHF correlation described in Reference 19 of Section 15.0, and the HERMITE computer code described in Reference 17 of Section 15.0. B. Input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the HSSS response to a total loss of flow are discussed in Section 15.0. The parameters, which are unique to the analysis, discussed below, are listed in Table 15.3.1-4. The principal process variables that determine thermal margin to DNB in the core are monitored by COLSS. COLSS computes a power-operating limit which assists the operator in maintaining the thermal margin in the core equal to or greater than that needed to cause the minimum DNBR to remain greater than 1.19, for a four pump loss of flow, assuming immediate reactor trip. COLSS is described in Section 7.7. The set of initial conditions chosen for the analysis presor.ted in this section is one of a very large number of combinations within the reactor operating space given in Table 15.0-5 which would provide the minimum thermal margin required by the COLSS power operating li mi t. The consequences following a total loss of flow initiated from any one of these combinations of conditions would be no more adverse than those presented herein. C. Results The dynomic behavior of important NSSS parameters following a total loss of reactor coolant flow is provided in Figures 15.3.1-2 to 15.3.1-9. The loss of offsite power causes the plant to experience a simultaneous turbine trip, loss of main feedwater, condenser inoperability, and a four reactor coolant pump coastdown. The loss of steam flow due to closure of the turbine stop valves results in a rapid increase in the steam generator pressure. A 1S.3 4 Amendment No. 7 March 31, 1982
l sharp reduction in primary to secondary heat transfer follows which, in conjunction with the loss of forced reactor coolant flow, causes a rapid heat j up of the primary coolant. The pressurizer safety valves open at 4.3 seconds,
/
and the MSSVs open at 5.4 seconds. The RCS pressure reaches a maximum of 2576 psia at 5.3 seconds (Figure 15.3.1-4). This is less than 110% of design pressure. At 11.7 seconds the secondary pressure reaches its maximum value of 1338 psia (Figure 15.3.1-8) . This pressure is also less than 110% of design pressure. Subsequently, the RCS pressure decreases rapidly as the combination of reactor trip and primary and main steam safety valves opening reduce the reactor coolant system energy. The pressurizer safety valves close at 12.2 seconds. A second pressure increase occurs as a result of increasing RCS temperatures caused by the degrading primary to secondary heat transfer resulting from the continuously decreasing reactor coolant system flow rate. The rise in RCS temperatures increases the primary to secondary heat transfer until the heat removed by the secondary system exceeds the primary system heat generation. At this time the RCS temperatures, and subsequently the pressure, begin to decrease. After 30 minutes, the operator commences cooldown using the auxiliary feedwater system and the atmospheric dump valves. The minimum CE-1 DNBR calculated to occur during the transient is 1.19 (Figure 15.3.1-9); thus, no fuel pins are assumed to experienc DNB for this event. 15.3.1.5 Conclusions l %) The maximum RCS and secondary system pressures remain within 110% of their design values following the total loss of forced reactor coolant flow event. The minimum DNBR calculated to occur during the transient is 1.19 which ensures that the specified acceptable fuel design limit is not violated. h' , L 15.3-5 Amendment No. 7 March 31, 1982
O THIS PAGE INTENTI0f1 ALLY BLAf1K. O l 1 l l I l ? O
TABLE 15.3.1-1
! SEQUENCE OF EVENTS FOR TOTAL LOSS OF REACTOR COOLANT FLOW Time Setpoint Success (Sec) Event Or Value Path 0.0 Loss of Offsite Power
- Turbine Trip
- Diesel Generator Starting Signal
- Reactor Coolant )
Pumps Coast Down
- Main Feedwater is Lost 0.6 Low DNBR Trip Signal 1.19 Projected Reactivity Control l
Generated 1.09 CEA's Begin to Drop Reactivity Control 2.6 Minimum Transient DNBR 1.19 4.3 Pressurizer Safety Valves 2525 Primary System 4 Open, psia Integri ty 5.3 Maximum RCS Pressure, psia 2576 5.4 Steam Generator Safety 1282 Secondary System Valves Open, psia Integrity 11.7 Maximum Steam Generator 1338 Pressure, psia 12.2 Pressurizer Safety Valves 2463 Primary System
- Closed, psia Integri ty 1800.0 Operator Initiates Plant Cooldown 4
l i I 4 Amendment No. 7 March 31, 1982
- . . - . . ... .... ..~. . - - - . - . . - , - . - - . . , - - - . _ . - . . - - - . - - . - . . - - - , _ . - . _ _ _ _ .
TABLE 15.3.1-2 (Sheet 1 of 2) DISPOSITI0f10F fl0RMALLY OPERATIf!G SYSTEMS FOR THE TOTAL LOSS OF REACTOR COOLANT FLOW 6.
'oo 1;, 6'g e O
\ \ d,. M.g G 1,#o g
?. % b,Q % 'fs 5,) Q.Y... Es 3, ;s'-Jh Q o'% o.%. A g y'r / ~. c.~'c\. v ,. , 0,e oy <. < '? <m h *e
. s Q k'b -fg E1 %\ 11 0
'Q SYSTEll Cy$sYg 'g'e c i
- 1. liain feedwater Control System ,e
- 2. Main Feedwater Pump Turbine Control System * /
- 3. Turbine-Generator Control System * /
- 4. Steam Bypass Control Systcm /
- 5. Pressurizer Pressure Control System /
i
- 0. Frezurizer Level Control system /l (
- 7. Control Elcment Drive Mechanism Control System /
l
- 8. Reactor Regulating Systcm / ,
- 9. Core Operating Limit Supervisory System /
- 10. Reactor Coolant Pumps /
- 11. Chemical and Volume Control System /
- 12. Secondary Chcmistry control System * /
- 13. Condenser Evacuation Systcm+ /
l
- 14. Turbine Gland Sealing System * ,/
- 15. l'uclear Cooling !!ater System + /
- 16. Turbine Cooling l-later System * /
- 17. Plant Cooling 1later System * /
I P;. Condensate Storage facilities * /
- 19. Circulating !!ater System * /
- 20. Spent fuel Pool Cooling and Clcan-Up Systen* /
- 21. Ilon-Class lE (ficn-ESF) A.C. Power * / 1 Class lE (ESF) A.C. Pocr* / h lP2. k I
#Dalance-of-Plant Systems -
l'! L.-.=....-.-. .
- --- = ==- == ==:- =.== jgghyw g;g 7-. -
March 31, 1982
, TABLE 15.3.1-2 (Cont'd) (Sheet 2 of 2)
DISPOSITION OF NORMALLY OPERATING SYSTEMS f FOR THE TOTAL LOSS OF REACTOR COOLANT FLOW
\ \
t o%ss g>og O
c -;. Cff '
. r, ., ,, .. o, M/z 'e. 'Yo 1 QuAp % 9 o SYSTEM 'o -
- 23. tion-Class lE 0.C. Power
- r
/ l
- 24. Class lE D.C. Power * /
Notes:
- 1. Failure in this system is the initiating event.
1 (\ t i I i l l i li ; i O~' i: '-Balance-of-Plant Systems F1 <
- l
- g- ,------==.\ March 31, 1982 TABLE 15.3.1 -3 UTILIZATI0fl 0F SAFETY SYSTEfiS FOR THE TOTAL LOSS OF REACTOR C00LAf1T FLOW O "' 'O p, + h'd, */, &'O,, $9 't o e' o 's ?. x s A( ' b ). Q < ( b %, ?glcp(r'e e 'O p ,, . 'e .9..#f p ' i h 'e,% SYSTDi o
- i. Reactor Protection Systua /
/
- 2. DimR/LPD Calculator I /
, 3. Engineered Safety features Actuation Systems 1
- 4. Suppler..entary Protection System l
- b. Reat. tor Trip ' .iitch Gear /
f !4ain Steam Safety Valves * / 6. f /
- 7. Primary Safety Valves j / 2
! 8. 1'.ain Stcc:a Isolation System * / / l 9. D::erger.cy Feed. tater System *
- 10. Safety Injection System
/ 2
- 11. Shutdown Cooling Systcm
/ 2 .!12. Atmospheric Dump Valve Systcm*
- 13. Ccotan. ment Isolation System
- Contair. ment spray System
- j14.
- 15. Iodine Removal Systaa*
Contain: cent CcMustible Gas Control System + {16. Diesel Generators and Support Syster.s* / l17.
- 18. Cca.gonent (Essential) Cooling !!ater System + /
- 19. Station Service ',later Systea* /
f ; lb. .t.e_r_. : q Safety grade tack-up to a safety grade systcm. o l.
- 2. Manually actuated during normal cooldown.
I g Balance-ef-Plant Systens - ' , AEenilment tio. T March 31. 1987 TABLE 15.3.1-4 ASSUMED INITIAL CONDITIONS FOR TOTAL LOSS OF REACTOR COOLANT FLOW O- Parameter Value Core Power Level, MWt 3876 Core Inlet Coolant Temperature,*F 565 Reactor Coolant System Pressure, psia 2250 Steam Generator Pressure, psia 1070 Core Mass Flow, 10 6 lbm/hr 157.4 Core Minimum DNBR 1.51 Maximum Radial Power Peaking Factor 1.62 Maximum Axial Power Peak 1.47 CEA Worth on Trip,10-2 op -10.0 (most reactive CEA Stuck) O l O Amendment No. 7 March 31,1982 3 4,. [* 's I .. Is ; . l, ,1 Q \ ) B:ACTTVITY > t- CD:ffACL g Y \ ' 4 ap;&s *at 575 stLL AL53 5t tCTtiAft3 OLA!4G \ g ' TWn TRAA5tkaf ai0 u!LL F CTIOS TO , INCAD$E TMt REL.A3!LITY OF THE RP5 y' 'A
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- gggpfg / CORE AVERAGE HEAT FLUX vs TIME 15 3 . 1 -3
! l l 4 2799 , , , , O 2699 - - 2599- $ 2499 - o_ $2399 E n. 2299 - - 2199 - - 2099 - 1999 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E TOTAL LOSS OF REACTOR COOLANT FLOW Figure RCS PRESSURE vs TIME 15.3. 1 - 4 650 , , , , O j l 630 - O vi E ? g T H0T E 610 - - lE i i! _ E 5 o T 8 590 AVG g - - OsW E O 570 - COLD _ 550 0 100 200 300 400 500 TIME, SECONDS Amendment No. 7 March 31, 1982 C-E i TOTAL LOSS OF REACTOR COOLANT FLOW Figure Effffd' / CORE AVERAGE C00lANT TEMPERATURES vs TIME 15 3 .1 - 5 2.5 { i , i i DOPPLER 0.0 a. W $ -2.5 - M N 5 $ -5.0 - -- O6 e -7.5 - - TOTAL CEA -10.0 0 100 200 300 400 500 TIME, SECONDS}}