ML21361A218

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Supplemental Information for Revision 22 to Updated Safety Analysis Report, Chapter 6, Engineered Safety Features
ML21361A218
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Site: Perry FirstEnergy icon.png
Issue date: 12/20/2021
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Energy Harbor Nuclear Corp
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Office of Nuclear Reactor Regulation
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TABLE OF CONTENTS Section Title Page 6.0 ENGINEERED SAFETY FEATURES 6.1-1 6.1 ENGINEERED SAFETY FEATURE MATERIALS 6.1-1 6.1.1 METALLIC MATERIALS 6.1-1 6.1.1.1 Materials Selection and Fabrication 6.1-1 6.1.1.2 Composition, Compatibility and Stability of Containment and Core Spray Coolants 6.1-5 6.1.2 ORGANIC MATERIALS 6.1-7 6.

1.3 REFERENCES

FOR SECTION 6.1 6.1-9 6.2 CONTAINMENT SYSTEMS 6.2-1 6.2.1 CONTAINMENT FUNCTIONAL DESIGN 6.2-1 6.2.1.1 Containment Structure 6.2-1 6.2.1.2 Containment Subcompartments 6.2-46 6.2.1.3 Mass and Energy Release Analyses for Postulated Loss-of-Coolant Accident 6.2-55 6.2.1.4 Mass and Energy Release Analysis for Postulated Secondary System Pipe Ruptures Inside Containment (PWR) 6.2-58 6.2.1.5 Minimum Containment Pressure Analysis for Performance Capability Studies on Emergency Core Cooling System (PWR) 6.2-58 6.2.1.6 Testing and Inspection 6.2-58 6.2.1.7 Instrumentation Requirements 6.2-58 6.2.2 CONTAINMENT HEAT REMOVAL SYSTEM 6.2-59 6.2.2.1 Design Bases 6.2-59 6.2.2.2 System Design 6.2-60 6.2.2.3 Design Evaluation 6.2-68 6.2.2.4 Tests and Inspections 6.2-70 6.2.2.5 Instrumentation Requirements 6.2-70 6.2.3 SECONDARY CONTAINMENT FUNCTIONAL DESIGN 6.2-70 6.2.3.1 Design Bases 6.2-70 6.2.3.2 System Design 6.2-71 6.2.3.3 Design Evaluation 6.2-73 6.2.3.4 Tests and Inspections 6.2-77 6.2.3.5 Instrumentation Requirements 6.2-77 Revision 12 6-i January, 2003

TABLE OF CONTENTS (Continued)

Section Title Page 6.2.4 CONTAINMENT ISOLATION SYSTEM 6.2-78 6.2.4.1 Design Bases 6.2-78 6.2.4.2 System Design 6.2-82 6.2.4.3 Design Evaluation 6.2-109 6.2.4.4 Tests and Inspections 6.2-111 6.2.5 COMBUSTIBLE GAS CONTROL IN CONTAINMENT 6.2-112 6.2.5.1 Design Bases 6.2-112 6.2.5.2 System Design 6.2-115 6.2.5.3 Design Evaluation 6.2-121 6.2.5.4 Testing and Inspection 6.2-124 6.2.5.5 Instrumentation Requirements 6.2-125 6.2.6 CONTAINMENT LEAKAGE TESTING 6.2-126 6.2.6.1 Primary Reactor Containment Integrated Leakage Rate Test 6.2-126 6.2.6.2 Containment Penetration Leakage Rate Test 6.2-127 6.2.6.3 Containment Isolation Valve Leakage Rate Tests 6.2-128 6.2.6.4 Scheduling and Reporting of Periodic Tests 6.2-129 6.2.6.5 Special Testing Requirements 6.2-129 6.2.6.6 Primary Containment Leakage Rate Testing Program 6.2-131 6.2.7 SUPPRESSION POOL MAKEUP SYSTEM 6.2-132 6.2.7.1 Design Bases 6.2-132 6.2.7.2 System Design 6.2-134 6.2.7.3 Design Evaluation 6.2-137 6.2.7.4 Tests and Inspections 6.2-141 6.2.7.5 Instrumentation Requirements 6.2-141 6.2.8 HYDROGEN CONTROL SYSTEM 6.2-142 6.2.8.1 Design Bases 6.2-143 6.2.8.2 System Design 6.2-145 6.2.8.3 Design Evaluation 6.2-146 6.2.8.4 Testing and Inspection 6.2-149 6.2.8.5 Instrumentation Requirements 6.2-149 6.

2.9 REFERENCES

FOR SECTION 6.2 6.2-150 Revision 12 6-ii January, 2003

TABLE OF CONTENTS (Continued)

Section Title Page 6.3 EMERGENCY CORE COOLING SYSTEMS 6.3-1 6.3.1 DESIGN BASES AND

SUMMARY

DESCRIPTION 6.3-1 6.3.1.1 Design Bases 6.3-1 6.3.1.2 Summary Descriptions of ECCS 6.3-7 6.3.2 SYSTEM DESIGN 6.3-9 6.3.2.1 Schematic Piping and Instrumentation Diagrams 6.3-9 6.3.2.2 Equipment and Component Descriptions 6.3-9 6.3.2.3 Applicable Codes and Classifications 6.3-36 6.3.2.4 Material Specifications and Compatibility 6.3-36 6.3.2.5 System Reliability 6.3-37 6.3.2.6 Protection Provisions 6.3-37 6.3.2.7 Provisions for Performance Testing 6.3-39 6.3.2.8 Manual Actions 6.3-39 6.3.3 PERFORMANCE EVALUATION 6.3-39 6.3.3.1 ECCS Bases for Technical Specifications 6.3-41 6.3.3.2 Acceptance Criteria for ECCS Performance 6.3-41 6.3.3.3 Single Failure Considerations 6.3-42 6.3.3.4 System Performance During the Accident 6.3-43 6.3.3.5 Use of Dual Function Components for ECCS 6.3-44 6.3.3.6 Limits on ECCS System Parameters 6.3-45 6.3.3.7 ECCS Analyses for LOCA 6.3-45 6.3.3.8 Conclusions 6.3-51 6.3.4 TESTS AND INSPECTIONS 6.3-52 6.3.4.1 ECCS Performance Tests 6.3-52 6.3.4.2 Reliability Tests and Inspections 6.3-53 6.3.5 INSTRUMENTATION REQUIREMENTS 6.3-57 6.

3.6 REFERENCES

FOR SECTION 6.3 6.3-58 6.4 HABITABILITY SYSTEMS 6.4-1 6.4.1 DESIGN BASES 6.4-1 6.4.2 SYSTEM DESIGN 6.4-4 6.4.2.1 Definition of Control Room Envelope 6.4-4 6.4.2.2 Ventilation System Design 6.4-4a Revision 14 6-iii October, 2005

TABLE OF CONTENTS (Continued)

Section Title Page 6.4.2.3 Leak Tightness 6.4-9 6.4.2.4 Interaction with Other Zones and Pressure Containing Equipment 6.4-11 6.4.2.5 Shielding Design 6.4-12 6.4.3 SYSTEM OPERATIONAL PROCEDURES 6.4-12 6.4.4 DESIGN EVALUATION 6.4-14 6.4.4.1 Radiological Protection 6.4-14 6.4.4.2 Toxic Gas Protection 6.4-15 6.4.4.3 Control Room Emergency Recirculation System 6.4-15 6.4.4.4 Control of the Control Room Thermal Environment 6.4-16 6.4.4.5 Fire Protection 6.4-17 6.4.4.6 Food, Water and Sanitation 6.4-17 6.4.5 TESTING AND INSPECTION 6.4-18 6.4.6 INSTRUMENTATION REQUIREMENTS 6.4-19a 6.4.6.1 Control Room HVAC System 6.4-20 6.4.6.2 Control Room Emergency Recirculation System 6.4-20 6.4.6.3 Lighting System 6.4-21 6.4.6.4 Offsite and Onsite Power Systems 6.4-21 6.5 FISSION PRODUCT REMOVAL AND CONTROL SYSTEMS 6.5-1 6.5.1 ENGINEERED SAFETY FEATURES (ESF) FILTER SYSTEMS 6.5-1 6.5.1.1 Design Bases 6.5-1 6.5.1.2 System Design 6.5-4 6.5.1.3 Design Evaluation 6.5-6 6.5.1.4 Tests and Inspections 6.5-7 6.5.1.5 Instrumentation Requirements 6.5-8 6.5.1.6 Materials 6.5-9 6.5.2 CONTAINMENT SPRAY SYSTEM 6.5-9 6.5.2.1 Design Bases 6.5-9 6.5.2.2 System Design 6.5-10 6.5.2.3 Design Evaluation 6.5-11 6.5.2.4 Tests and Inspections 6.5-15 6.5.2.5 Instrumentation Requirements 6.5-15 6.5.2.6 Materials 6.5-15 Revision 17 6-iv October, 2011

TABLE OF CONTENTS (Continued)

Section Title Page 6.5.3 FISSION PRODUCT CONTROL SYSTEMS 6.5-15 6.5.3.1 Primary Containment 6.5-15 6.5.3.2 Secondary Containment 6.5-17 6.5.4 ICE CONDENSER AS A FISSION PRODUCT CLEANUP SYSTEM 6.5-24 6.

5.5 REFERENCES

FOR SECTION 6.5 6.5-24 6.6 INSERVICE INSPECTION OF CLASS 2 AND 3 COMPONENTS 6.6-1 6.6.1 COMPONENTS SUBJECT TO EXAMINATION 6.6-1 6.6.2 ACCESSIBILITY 6.6-1 6.6.3 EXAMINATION TECHNIQUES AND PROCEDURES 6.6-1 6.6.4 INSPECTION INTERVALS 6.6-2 6.6.5 EXAMINATION CATEGORIES AND REQUIREMENTS 6.6-2 6.6.6 EVALUATION OF EXAMINATION RESULTS 6.6-2 6.6.7 SYSTEM PRESSURE TESTS 6.6-3 6.6.8 AUGMENTED INSERVICE INSPECTION TO PROTECT AGAINST POSTULATED PIPING FAILURES 6.6-3 6.7 MAIN STEAM LINE ISOLATION VALVE LEAKAGE CONTROL SYSTEM 6.7-1 6.8 SAFETY-RELATED INSTRUMENT AIR_SYSTEM 6.8-1 6.8.1 DESIGN BASES 6.8-1 6.8.2 SYSTEM DESIGN 6.8-1 6.8.3 DESIGN EVALUATION 6.8-3 6.8.4 TESTS AND INSPECTIONS 6.8-4 6.8.5 INSTRUMENTATION REQUIREMENTS 6.8-5 Revision 12 6-v January, 2003

TABLE OF CONTENTS (Continued)

Section Title Page 6.9 FEEDWATER LEAKAGE CONTROL SYSTEM 6.9-1 6.9.1 DESIGN BASES 6.9-1 6.9.2 SYSTEM DESCRIPTION 6.9-2 6.9.3 DESIGN EVALUATION 6.9-5 6.9.4 TESTS AND INSPECTIONS 6.9-6 6.9.5 INSTRUMENTATION REQUIREMENTS 6.9-6 Revision 12 6-vi January, 2003

LIST OF TABLES Table Title Page 6.1-1 Principal Engineered Safety Features Components Pressure Retaining Materials 6.1-11 6.1-2 Organic Coating Materials Inside Reactor Building 6.1-15 6.2-1 Key Design and Maximum Accident Parameters For Pressure Suppression Containment 6.2-154 6.2-2 Containment Design Parameters 6.2-155 6.2-3 Engineered Safety Feature Systems Performance Parameters for Containment Response Analyses 6.2-156 6.2-4 Accident Assumptions and Initial Conditions for Containment Response Analyses (at 3833 MWt) 6.2-158 6.2-5 Initial Conditions Employed in Containment Response Analyses (at 3833 MWt) 6.2-159 6.2-6 Summary of Short Term Containment Responses to Recirculation Line and Main Steam Line Breaks (up to 30 seconds) 6.2-161 6.2-7 Summary of Long Term Containment Responses to Recirculation Line or Main Steam Line Break (at 3729 MWt) 6.2-162 6.2-7a Summary of Long Term Containment Responses to Recirculation Line or Main Steam Line Break (at 3833 MWt) 6.2-163 6.2-8 Energy Balance for Main Steam Line Break Accident (at 3729 MWt) 6.2-164 6.2-9 Accident Chronology for Main Steam Line Break Accident (at 3729 MWt) 6.2-166 6.2-10 Available Containment Heat Sinks 6.2-167 6.2-11 (Deleted) 6.2-168 6.2-12 Reactor Annulus 6.2-169 6.2-13 Reactor Annulus Feedwater Line Break 6.2-171 Revision 12 6-vii January, 2003

LIST OF TABLES Table Title Page 6.2-14 Drywell Head Region Analysis 6.2-173 6.2-15 Steam Tunnel 6.2-174 6.2-16 Reactor Water Cleanup Rooms Analysis 6.2-175 6.2-16a Drywell Bulkhead Plate P Analysis Volume Description 6.2-176 6.2-17 Mass and Energy Releases 6.2-177 6.2-18 Mass and Energy Into Reactor Annulus Due to Feedwater Break Used for Analysis 6.2-178 6.2-19 Reactor Water Cleanup System Double Ended Pipe Break Liquid Blowdown 6.2-179 6.2-20 Reactor Annulus Recirculation Line Break 6.2-180 6.2-21 Reactor Annulus Feedwater Line Break 6.2-182 6.2-22 Drywell Head Flow Path Data 6.2-186 6.2-23 Reactor Water Cleanup Rooms Flow Path Data 6.2-187 6.2-24 Steam Tunnel Flow Path Data 6.2-188 6.2-24a Drywell Bulkhead Plate P Analysis Flow Path Description 6.2-189 6.2-25 Reactor Blowdown Data for Recirculation Suction Line Break (at 3729 MWt) 6.2-190 6.2-26 Reactor Blowdown Data for Main Steam Line Break - Minimum ECCS (at 3729 MWt) 6.2-191 6.2-27 Core Decay Heat Following Loss-of-Coolant Accident for Containment Analysis (at 3729 MWt) 6.2-192 6.2-27a Core Decay Heat Following Loss-of-Coolant Accident for Long-Term Containment Analysis (at 3833 MWt) 6.2-193 6.2-28 Additional Information to be Provided for Dual Containment Plants 6.2-194 Revision 12 6-viii January, 2003

LIST OF TABLES (Continued)

Table Title Page 6.2-29 (Deleted) 6.2-196 6.2-30 (Deleted) 6.2-197 6.2-31 Overall Heat Transfer Coefficients as a Function of Time 6.2-198 6.2-32 Containment Isolation Valve Summary 6.2-199 6.2-33 Potential Secondary Containment Bypass Leakage Paths 6.2-208 6.2-34 Reactor Coolant Pressure Boundary Influent Lines that Penetrate Containment/Drywell 6.2-221 6.2-35 Reactor Coolant Pressure Boundary Effluent Lines that Penetrate Containment/Drywell 6.2-222 6.2-36 Primary Containment Isolation for Lines that Penetrate Containment and Connect to the Suppression Pool 6.2-223 6.2-37 Combustible Gas Control System Equipment Design and Performance Data 6.2-225 6.2-38 Combustible Gas Control System Failure Analysis 6.2-228 6.2-39 Design and Operating Parameters for Hydrogen Control 6.2-229 6.2-40 Primary Reactor Containment Penetration and Containment Isolation Valve Leakage Rate Test List 6.2-230 6.2-41 Containment Leak Rate Test Data 6.2-243 6.2-43 Hydrogen Control System Equipment Design and Performance Data 6.2-246 6.2-44 Containment Equipment Survivability List 6.2-247 6.2-45 Drywell Equipment Survivability List 6.2-259 Revision 20 6-ix October, 2017

LIST OF TABLES (Continued)

Table Title Page 6.2-46 Perry CLASIX-3 Results 6.2-264 6.3-1 Parameters Used in Perry SAFER/GESTR-LOCA Analysis 6.3-61 6.3-2 Operational Sequence of Emergency Core Cooling Systems for Design Basis Accident 6.3-66 6.3-3 Perry Single Failure Evaluation 6.3-67 6.3-4 Summary of Recirculation Line Break Results for Perry SAFER/GESTR Analysis for Cycle 8 6.3-68 6.3-5 SAFER/GESTR-LOCA Licensing Results for Perry 6.3-69 6.3-6 Key to Figures 6.3-70 6.3-7 ECCS Design Parameters 6.3-72 6.3-8 Manual Valves in HPCS System 6.3-76 6.3-9 Manual Valves in LPCS System 6.3-78 6.3-10 Manual Valves in LPCI (RHR) System 6.3-80 6.4-1 Equipment Which Could Require Control Room Operator Access During an Emergency 6.4-22 6.4-2 Design Data for Control Room HVAC System Major Components 6.4-23 6.4-3 Design Data for Control Room Emergency Recirculation System Major Components 6.4-26 6.4-4 Single Failure Analysis 6.4-29 6.5-1 Comparison of Control Room Emergency Recirculation System with Regulatory Guide 1.52 Positions 6.5-25 6.5-2 Comparison of Fuel Handling Area Exhaust Subsystem with Regulatory Guide 1.52 Positions 6.5-31 6.5-3 Comparison of Annulus Exhaust Gas Treatment System with Regulatory Guide 1.52 Positions 6.5-37 Revision 12 6-x January, 2003

LIST OF TABLES (Continued)

Table Title Page 6.5-4 Control Room Emergency Recirculation System Materials List (Design Data) 6.5-43 6.5-5 Fuel Handling Area Exhaust Subsystem Materials List (Design Data) 6.5-46 6.5-6 Annulus Exhaust Gas Treatment System Materials List (Design Data) 6.5-49 6.5-7 Primary Containment Operation Following a Design Basis Accident 6.5-52 6.5-8 Design Data for Annulus Exhaust Gas Treatment System Components 6.5-53 6.5-9 Input Parameters for the Spray Removal Analysis 6.5-56 6.5-10 (Deleted) 6.5-57 6.5-11 Elemental Iodine Deposition Removal Factors 6.5-58 6.9-1 Single Failure Analysis of Feedwater Leakage Control System 6.9-7 Revision 19 6-xi October, 2015

6.0 ENGINEERED SAFETY FEATURES 6.1 ENGINEERED SAFETY FEATURE MATERIALS Materials used in the manufacture of engineered safety feature (ESF) components have been evaluated to ensure that material interactions will not occur that could potentially impair operation of the engineered safety features. Materials have been selected to withstand environmental conditions encountered during normal operation as well as during postulated accidents. Their compatibility with core and containment spray solutions has been considered and the effects of radiolytic decomposition products have been evaluated.

Coatings used on exterior surfaces within the primary containment are suitable for the environmental conditions expected. Nonmetallic thermal insulation utilized is required to have the proper ratio of leachable sodium plus silicate ions to leachable chloride plus fluoride ions to minimize the possibility of stress corrosion cracking.

6.1.1 METALLIC MATERIALS 6.1.1.1 Materials Selection and Fabrication 6.1.1.1.1 Material Specifications Principal pressure retaining materials and the material specifications for the reactor coolant pressure boundary components are listed in

.
lists the principal pressure retaining materials and the material specifications for the engineered safety features components of the plant. All materials have been provided with ASME Section III material tests as required by the applicable component safety classifications. In addition, all Safety Class 2 carbon steel Revision 12 6.1-1 January, 2003 piping and valves installed in the main steam and feedwater systems meet the fracture toughness requirements specified in Subsection NB-2300,Section III of the ASME Code. 6.1.1.1.2 Engineered Safety Features Construction Material <Section 5.2.3> discusses compatibility of the reactor coolant with materials exposed to the reactor coolant. These same materials are found in the engineered safety features components. All ESF construction materials are resistant to stress corrosion in the presence of BWR coolant and containment spray. Conservative corrosion allowances are provided for all exposed surfaces of carbon steel. General corrosion of all other materials is negligible. Demineralized water, with no additives, is used as the core cooling water and for containment spray. Following a LOCA, this high purity water will have no detrimental effect on any of the ESF materials. All of the materials listed in
are compatible. 6.1.1.1.3 Integrity of Engineered Safety Feature Components During Manufacture and Construction 6.1.1.1.3.1 Control of Sensitized Stainless Steel Conformance with <Regulatory Guide 1.44> and <Regulatory Guide 1.31> is discussed in <Section 1.8> and <Section 5.2.3>. The following controls were used to avoid severe sensitization of balance-of-plant (BOP) piping and to comply with the intent of <Regulatory Guide 1.44> and <NUREG-0313>:
a. Corrosion Resistant Material All safety-related Types 304, 316L and 347 modified stainless steel material used in the reactor coolant pressure boundary and ESF Revision 12 6.1-2 January, 2003
systems were obtained in the solution annealed condition. Piping subject to hot bending is solution heat treated with all cold straightening limited to the two percent strain rule as specified by the ASME Section III Code. All BOP piping exposed to reactor coolant uses socket seal welded fittings with controlled heat input and welding interpass temperatures are limited to 350F. Both the design of the weld and the weld procedure reduce the susceptibility of the material to crack sensitization.
b. Other Methods The methods employed include:
1. Piping exposed to reactor coolant, within the scope of BOP piping, is included in four systems: reactor recirculation, nuclear boiler, standby liquid control, and control rod drive.
The largest size piping used in these systems is 1-1/2 inch diameter Schedule 40 or thicker. Over 99 percent of the piping is one inch in diameter or less. This piping is joined by socket welded fittings. The design of the socket fittings, using fillet seal welds, limits the heat input into the pipe. When combined with a limited voltage, amperage and travel speed, this prevents sensitization of the Type 304 austenetic stainless steel piping used. The gas tungsten arc welds used in accordance with strict QA approved procedures result in a maximum of 45,000 joules per inch; shielded metal arc welds result in 56,000 joules per inch for all socket welded stainless steel pipe. This limited heat input control, when combined with the heat sink effect of the socket seal weld connection design, provides maximum protection from sensitization of the metal adjacent to the seal weld.
2. Using socket seal welds reduces the possibility of the welded portion of the pipe being exposed to the reactor coolant.
Revision 12 6.1-3 January, 2003 This also eliminates the necessity of interior grinding since the interior surface of the pipe is not disturbed.
3. Using weld heat input control to limit the material heat flux to a value that avoids the conditions that cause excessive sensitization.
4. Limiting weld interpass temperatures to 350F and the weld weave pattern to four times the core wire diameter to control the heat buildup that contributes to excessive sensitization.
6.1.1.1.3.2 Cleaning and Contamination Protection Procedures Specifications for ESF piping and components specify requirements for cleanliness and contamination protection during fabrication, shipment and storage as recommended by <Regulatory Guide 1.44>. Onsite and preoperational cleaning of ESF components is in accordance with the recommendations of <Regulatory Guide 1.37>. General compliance to regulatory guides is discussed in <Section 1.8>. Exposure to contaminants capable of causing stress corrosion cracking of austenitic stainless steel components was avoided by carefully controlling all cleaning and processing materials which contact the stainless steel during manufacture and construction. Special care was exercised to ensure removal of surface contaminants prior to any heating operations. Water quality for cleaning, rinsing, flushing, and testing was controlled and monitored. Suitable packaging and protection was provided for components to maintain cleanliness during shipping and storage. 6.1.1.1.3.3 Cold Worked Stainless Steel Austenitic stainless steel with a yield strength greater than 90,000 psi is not used in engineered safety features systems. Revision 12 6.1-4 January, 2003 6.1.1.1.3.4 Nonmetallic Insulation Nonmetallic thermal insulation materials in ESF systems are in accordance with the staff positions of <Regulatory Guide 1.36>. They have the proper ratio of leachable sodium plus silicate ions, to leachable chloride plus fluoride ions. A detailed discussion of the nonmetallic thermal insulation used inside containment is presented in <Section 6.1.2>. 6.1.1.1.4 Weld Fabrication and Assembly of Stainless Steel ESF Components All ESF system components and piping have been constructed in accordance with the staff positions of <Regulatory Guide 1.31> or the interim positions specified in NRC Branch Technical Position MTEB 5-1, Control of Stainless Steel Welding. General compliance or alternate approach assessment for <Regulatory Guide 1.31> is discussed in <Section 1.8> and <Section 5.2.3>. 6.1.1.1.5 Weld Fabrication and Assembly of Ferritic Steel ESF Components All ESF system components and piping have been constructed in accordance with <Regulatory Guide 1.50> and <Regulatory Guide 1.71> as delineated in
. General compliance may also be found in <Section 1.8> and <Section 5.2.3.3>. Moisture control on low hydrogen welding materials conforms to the requirements of Sections II and III of the Code. Compliance to the Code is also addressed in <Section 5.2.3.3>. 6.1.1.2 Composition, Compatibility and Stability of Containment and Core Spray Coolants Demineralized water, with no additives, is employed in the core cooling water and containment sprays. No detrimental effects will occur on any Revision 12 6.1-5 January, 2003 of the ESF materials from this high purity water. In addition, following an accident, the containment and drywell atmospheres are maintained below 4 percent (by volume) hydrogen in accordance with <Regulatory Guide 1.7> <Section 6.2.5>. No soluble acids or bases are stored within containment, except for the 5,150 gallon capacity borax-boric acid solution storage tank. This volume of borax-boric acid will be injected into the reactor if a failure of the control rod drive system occurs. Water used in the engineered safety features system is controlled to provide assurance against stress corrosion cracking of unstabilized austenitic stainless steel components. Water used for emergency core cooling systems and spray systems is controlled to ensure the following limits:
a. Conductivity = 3 to <10 mhos/cm at 25C
b. Chloride (Cl-) <0.50 ppm
c. pH = 5.3 to 8.6 at 25C Water used in the ESF systems is stored in the suppression pool and the condensate storage tank. Water quality is maintained by deep bed demineralizers or filter demineralizers.
The coating systems used inside containment comply with the staff positions of <Regulatory Guide 1.54> and have undergone a qualification program to verify integrity following a LOCA. All coating materials (exceptions are noted in <Section 6.1.2>) used inside containment have been successfully tested for irradiation decontamination and DBA in accordance with the application specifications (Reference 1), (Reference 2), and (Reference 3). Revision 20 6.1-6 October, 2017 The nonmetallic insulating system used inside containment (Owens-Corning NuKon Fiberglas blanket insulation) has also undergone a qualification program (Reference 4) to verify its performance following a LOCA. 6.1.2 ORGANIC MATERIALS Many protective coatings that are common in industrial use can deteriorate in a postaccident environment and contribute substantial quantities of foreign solids and residue to the reactor building sump. Therefore, protective coatings used inside the reactor building have demonstrated the ability to withstand postaccident conditions by satisfying all the criteria listed in ANSI N101.2 with minor exceptions as identified in
. Also included in this qualification is the epoxy caulking material used to seal weld discontinuities, such as porosity and laminations prior to final application of the coating system. The suitability of the reactor building coating systems to withstand the design-basis accident (DBA) has been evaluated. Coatings have been applied in accordance with manufacturers recommendations. In addition, the guidance of <Regulatory Guide 1.54> is followed. Organic coating materials for inside the reactor building are listed in
. Stainless steels will not be placed in contact with organic coatings or cleaning materials that could contribute to stress corrosion cracking. These materials are compounds containing unacceptable levels of leachable chlorides, fluorides, lead, zinc, copper, sulfur, or mercury. Various nonmetallic materials are used as follows: in bearings; ethylene propylene, silicone or butyl rubber for O-rings; wire wound asbestos for gaskets; and lubricants with less than 200 ppm leachable Revision 12 6.1-7 January, 2003 chlorides. Cross-linked polyethylene or ethylene propylene rubber is used for electrical cable insulation and chlorosulfonated polyethylene is used for cable jacketing. The cabling was designed to withstand radiation dose. There is approximately 330,000 ft of electrical cabling inside containment which results in less than 40,000 lbs of these materials. Total exposed surface area of these materials is conservatively estimated to be 86,400 ft2 based on an equivalent cable diameter of 1.0 inch. In addition, closed cell polyethylene is provided on chilled water lines in the wetwell areas in containment. The amount is less than 130 lbs and approximately four gallons of contact cement is used to apply the insulation to carbon steel pipe. The cement includes a chlorinated compound which is not leachable under either operating or LOCA temperatures. Any plastics or elastomers used in a high radiation area are evaluated to determine service deterioration in accordance with ANSI N4.1. Penetrants used in liquid penetrant testing contain not more than one percent total sulfur and one percent total halogens (Reference 5). The only significant organic materials used on equipment supplied by General Electric are the protective coatings used on some carbon steel components. These coatings are specified to meet the requirements of <Regulatory Guide 1.54> and are qualified using the standard ANSI tests. However, because of the impracticability of using these special coatings on all equipment, certain small size equipment (e.g., electronic/electrical trim, covers, face plates, valve handles, etc.) may be coated with unqualified organic coatings. In addition, certain touch-up and repair applications (for which valid DBA tests per ANSI N101.2 are not available) were used during construction to repair previously applied qualified coatings. The total coated area for these surfaces and this equipment is approximately 9,520 sq ft. Heat insulation used within the containment (Owens Corning NuKon) is95-100 percent inorganic. Exterior cloth and Fiberglas insulating wool Revision 20 6.1-8 October, 2017 are the major components of the insulation. Together they represent over 95 percent of the total mass of the insulation. The insulation is comprised of a quilted, light density, semi-rigid fiberous glass (pad) material, encapsulated in woven glass (cloth) to form a composite blanket. The blankets use Velcro for ease of installation and removal. The Velcro is made from two components: Nomex nylon for the base mat and loops, and stainless steel for the hooks. Insulation is encapsulated with rolled and formed 22 gauge (304) stainless steel jacketing, combining quick release stainless steel latches and closure handles. For anti-sweat insulation a closed cell polyethylene foam is used in limited quantity (less than 130 lbs) in areas of the wetwell above the Elevation 620-6 floor. 6.

1.3 REFERENCES

FOR SECTION 6.1

1. Bechtel Corporation, Standard Specification Coatings for Nuclear Power Plants, Specification Numbers CP-951, CP-952, CP-956.
2. American National Standards Institute, Protective Coatings (Paints) for Light Water Nuclear Reactor Containment Facilities, ANSI N101.2, 1972.
3. American National Standards Institute, Protective Coatings (Paints) for the Nuclear Industry, ANSI N5.12, 1974.
4. Topical Report OCF-1, Nuclear Containment Insulation System, dated August 1977.

Revision 12 6.1-9 January, 2003

5. American Society of Mechanical Engineers,Section V, Article 6, Liquid Penetrant Examination, 1974 Edition With Addenda, up to and including Winter 1975.

Revision 12 6.1-10 January, 2003

TABLE 6.1-1 PRINCIPAL ENGINEERED SAFETY FEATURES COMPONENTS PRESSURE RETAINING MATERIALS Principal Component Form Material ASME Specification RHR Heat Exchanger:

Shell, head and Plate Carbon steel SA-516, GR 70 channel Tube sheet Plate Carbon steel SA-516, GR 70 Nozzles Forging Carbon steel SA-105 Flanges Forging Carbon steel SA-105 Tubes Tubing Stainless steel SA-249, Type 304L Bolts Bar Low alloy steel SA-193, GR B7 Nuts Forging Low alloy steel SA-194, GR 7 RHR, HPCS and LPCS Pumps:

Bowl assembly Casting Cast steel A-216, GR WCB (ASTM)

Discharge head Plate Carbon steel SA-516, GR 70 shell Discharge head Forging Carbon steel SA-105 cover Suction barrel Plate Carbon steel SA-516, GR 70 shell and dished head Flanges Forging Carbon steel SA-105 Pipe Plate Carbon steel SA-516, GR 70 Pipe Carbon steel SA-106, GR B Shaft Bar Stainless steel A-276, Type 410 (ASTM)

Impeller Casting Stainless steel A-351, GR CA6NM (ASTM)

Studs Bolting Alloy steel SA-193, GR B7 Nuts Nut Low alloy steel SA-194, GR 7 Cyclone separator Bar Stainless steel SA-479 body and cover HPCS Valves:

Body, bonnet Casting Cast steel SA-216, WCB and disc Alternate disc Forging Carbon steel SA-105 Stem Bar Stainless steel A-479 or A276, Type 410 (ASTM)

Studs Bar Alloy steel SA-193, GR B7 Nuts Bar Steel SA-194, GR 2H Revision 12 6.1-11 January, 2003

TABLE 6.1-1 (Continued)

Principal Component Form Material ASME Specification Standby Liquid Control Pump:

Fluid cylinder Forging Stainless steel SA-182, F304 Cylinder head, Plate Stainless steel SA-240, Type 304 valve, cover, and stuffing box flange plate Cylinder head Bar Stainless steel SA-479, Type 304 extension, valve stop, and stuffing box Stuffing box Forging Nickel alloy SA-564, Type 630 gland and plungers Studs Bar Alloy steel SA-193, GR B7 Nuts Forging Alloy steel SA-194, GR 7 Standby Liquid Control Storage Tank:

Tank Plate Stainless steel SA-240, Type 304 Fittings Forgings Stainless steel SA-182, Type F304 Pipe Pipe Stainless steel SA-312, Type 304 Welds Electrodes Stainless steel SFA 5.4 and 5.9, Types 308, 308L, 316, 316L Control Rod Casting Stainless steel A-351, GR CF8 (ASTM)

Velocity Limiter Other Components Piping:

Pipe Stainless steel SA-312, Type 304 Stainless steel SA-312, Type 316L Stainless steel SA-358, Type 304, Cl-2 Stainless steel SA-376, Type 304 Stainless steel SA-376, Type 347 Modified Stainless steel SA-403, GR WP304 Stainless steel SA-403, GR WP304H Revision 12 6.1-12 January, 2003

TABLE 6.1-1 (Continued)

Principal Component Form Material ASME Specification Carbon steel SA-155, GR KCF70, Cl-2 Carbon steel SA-155, GRKCF70, Cl-1 Carbon steel SA-234, GR WPB Carbon steel SA-106, GR B Alloy steel SA-335, GR P11 Alloy steel SA-335, GR P22 Alloy steel SB-464 Forgings Stainless steel SA-182, GR F304 Stainless steel SA-182, GR F316 Carbon steel SA-105 Alloy steel SA-182, GR F12 Alloy steel SA-182, GR F22 Alloy steel SA-182, GR F22 C1-3 Plate Stainless steel SA-240, Type 304 Bolting Alloy steel SA-193, GR B7 Nuts Carbon steel SA-194, GR 2H Valves:

Castings Stainless steel SA-351, GR CF8M Stainless steel SA-351, GR CF8 Carbon steel SA-216, GR WCB Stainless steel SA-351, GR CF3M Alloy steel SA-217, GR WC9 Forgings Stainless steel SA-182, GR F316 Stainless steel SA-182, GR F304 Alloy steel SA-182, GR F11 Alloy steel SA-182, GR F12 Alloy steel SB-462 Carbon steel SA-105 Alloy steel SA-182, GR F22 Alloy steel SA-182, GR F22 C1-3 Plate Carbon steel SA-516, GR 70 Bolts Stainless steel SA-564, Type 630 Alloy steel SA-193, GR BT Nuts Stainless steel SA-194, GR 8M Carbon steel SA-194, GR 2H Bar Stainless steel SA-479, Type 316L Stainless steel SA-564, Type 630 (per Code Case 1773)

Revision 18 6.1-13 October, 2013

TABLE 6.1-1 (Continued)

Principal Component Form Material ASME Specification Pumps:

Castings Stainless steel SA-351, GR CF8M Carbon steel SA-216, GR WCB Plate Stainless steel SA-240, Type 304 Carbon steel SA-515, GR 70 Pipe Carbon steel SA-106, GR B Carbon steel SA-155, GR C55 Bolts Alloy steel SA-193, GR B7 Alloy steel SA-193, GR B8 Vessels:

Plate Stainless steel SA-240, Type 304L Carbon steel SA-283, GR C Pipe Stainless steel SA-312, Type 304L Heat Exchangers:

Plate Stainless steel SA-240, GR 304L Carbon steel SA-285, GR C SA-306, GR 60 SA-515, GR 70 SA-516, GR 70 Pipe Carbon steel SA-53, GR B Forgings Carbon steel SA-181, GR I Extrusions Stainless steel SA-249, GR 304L (tubes) Copper SB-359 Bolts Alloy steel SA-193, GR B7 Nuts Carbon steel SA-194, GR 2H Revision 12 6.1-14 January, 2003

TABLE 6.1-2 ORGANIC COATING MATERIALS INSIDE REACTOR BUILDING Material Area DFTmax Materials Weight Total Weight Surface _(ft2)_ (mils) Type (oz./mil-ft2) (lbs) _

Steel(1) 842,954 8 Polyamide - 0.15 63,222 cured epoxy Concrete 92,485 20 Polyamide - 0.15 17,341 cured epoxy Total 80,563 Steel(2) 8,939 8 Water base and 0.15 671 polyamide-cured epoxies Steel(2) 581 - Powder coat - 18 NOTES:

(1) Includes pipe, structural steel, plate, and equipment (approx.).

(2) Applicable DBA tests are not available.

Revision 20 6.1-15 October, 2017

6.2 CONTAINMENT SYSTEMS 6.2.1 CONTAINMENT FUNCTIONAL DESIGN 6.2.1.1 Containment Structure 6.2.1.1.1 Design Bases The pressure suppression containment system is designed to have the following functional capabilities:

a. The containment and drywell have the capability to maintain functional integrity during and following peak transient pressures and temperatures which would occur following any postulated loss-of-coolant accident (LOCA). The LOCA includes the worst single failure (which leads to maximum containment and drywell pressure and temperature) and is further postulated to occur simultaneously with loss of offsite power and a safe shutdown earthquake (SSE). A detailed discussion of LOCA events is presented in <Section 6.2.1.1.3.3>. A detailed discussion of mass and energy released is presented in <Section 6.2.1.3>.
b. The containment, in combination with other accident mitigation systems, limits fission product leakage during and following the postulated design basis accident to values less than leakage rates that would result in offsite doses greater than those stated in

<10 CFR 50.67>.

c. The containment system and drywell can withstand coincident fluid jet forces associated with the flow from the postulated rupture of any pipe within the containment or drywell.

Revision 19 6.2-1 October, 2015

d. The containment design permits removal of fuel assemblies from the reactor core after the postulated LOCA.
e. The containment system is protected from, or is designed to withstand, missiles from internal sources and excessive motion of pipes which could directly or indirectly endanger the integrity of the containment.
f. The containment system provides means to channel the flow from postulated pipe ruptures in the drywell to the suppression pool.
g. The containment system is designed to allow for periodically performing tests at the peak pressure calculated to result from the postulated design basis accident to confirm the leaktight integrity of the containment and containment penetrations.

6.2.1.1.2 Design Features General layout drawings of the containment structure are provided by

<Figure 1.2-3>, <Figure 1.2-4>, <Figure 1.2-5>, <Figure 1.2-6>,

<Figure 1.2-7>, <Figure 1.2-8>, <Figure 1.2-9>, <Figure 1.2-10>,

<Figure 1.2-11>, and <Figure 1.2-13>.

Design provisions for protection of the containment structure against internally and externally generated missiles are discussed in

<Section 3.5>. Protection against pipe rupture is discussed in

<Section 3.6>.

Codes, standards and guides applicable to the design of the containment and internal structures are addressed in <Section 3.8.1>,

<Section 3.8.2> and <Section 3.8.3>.

The tests that demonstrate the functional capability of structural systems and components are discussed in <Section 6.2.1.6>.

Revision 20 6.2-2 October, 2017

The functional capability and frequency of operation of systems which maintain containment and subcompartment atmospheric conditions within limits during normal plant operation are discussed in <Section 9.4.6>.

Design provisions for protection of the containment structure against loss of integrity under external pressure loading conditions resulting from inadvertent operation of heat removal systems that could result in significant external structural loadings are described in

<Sections 3.8.2> and <Section 6.2.1.1.4>.

6.2.1.1.3 Design Evaluation 6.2.1.1.3.1 Summary Evaluation Key design parameters and the maximum calculated accident parameters for the pressure suppression containment are presented by
. These design and maximum calculated accident parameters are not determined from a single accident event but from an envelope of accident conditions. As a result, no single design basis accident (DBA) for this containment system exists. It is assumed for analytical purposes that the primary system and containment are initially at the maximum normal operating conditions. (Reference 1), (Reference 2), (Reference 3), and (Reference 4) describe relevant experimental verification of analytical models used to evaluate the containment system response. 6.2.1.1.3.2 Containment Design Parameters
provides a listing of key design parameters for the primary containment system, including the design characteristics of the drywell, suppression pool and pressure suppression vent system. Revision 12 6.2-3 January, 2003
provides a listing of performance parameters for the related engineered safety feature systems which supplement the design conditions presented by
for containment cooling purposes during post-blowdown, long term accident operation. Performance parameters listed include those applicable to full capacity operation and to those conservatively reduced capacities assumed for containment analyses. 6.2.1.1.3.3 Accident Response Analysis The containment functional evaluation is based upon consideration of several postulated accident conditions resulting in release of reactor coolant to containment. These accidents include the following:
a. Instantaneous guillotine rupture of a recirculation line.
b. Instantaneous guillotine rupture of a main steam line.
c. Rupture of an intermediate size liquid line.
d. Rupture of a small size steam line.
Energy release resulting from these accidents is addressed in <Section 6.2.1.3>. The accident response analyses are discussed in detail in (Reference 31). 6.2.1.1.3.3.1 Recirculation Line Break Immediately following rupture of a recirculation line, flow from both sides of the break is the maximum value limited by critical flow considerations. The total effective flow area is shown by <Figure 6.2-1>. On the side of the break adjacent to the suction nozzle, flow corresponds to critical flow in the pipe cross section. On the side adjacent to the injection nozzle, flow corresponds to critical Revision 12 6.2-4 January, 2003 flow at the ten jet pump nozzles associated with the broken loop. In addition, the cleanup line crosstie adds to the critical flow area.
summarizes the break areas. A penalty is added to the Peak Clad Temperature (PCT) to account for a flow path that is not in the base recirculation failure LOCA analysis. This flow path is from the bottom head drain of the Reactor Pressure Vessel to the recirculation loop and only impacts the recirculation line failure LOCA analysis. The penalty is added to the PCT values found in
and
. 6.2.1.1.3.3.1.1 Assumptions for Reactor Blowdown The response of the reactor coolant system during the blowdown period of the accident is analyzed using the following assumptions:
a. Initial conditions for the recirculation line break accident are such that system energy is maximized and system mass is minimized.
These conditions are as follows:
1. The reactor is operating at 102 percent of rated power. This maximizes postaccident decay heat.
2. Service water temperature is the maximum normal.
3. Suppression pool mass is at the low water level with a maximum (positive) drywell-to-containment differential pressure (dP) for the long term analysis, and at the high water level with a minimum (negative) drywell-to-containment dP for the short term analysis.
4. Suppression pool temperature is the maximum normal.
Revision 12 6.2-5 January, 2003
b. The recirculation line is considered to be severed instantly. This results in the most rapid coolant loss and depressurization of the reactor pressure vessel. Coolant is discharged from both ends of the break.
c. Reactor power generation ceases at the time of accident initiation as a result of void formation in the core region. Scram occurs less than one second after receipt of the high drywell pressure signal. The difference between shutdown times is negligible.
d. Reactor pressure vessel depressurization flow rates are calculated using Moodys critical flow model (Reference 3), assuming liquid only outflow since this assumption maximizes the energy release to the drywell. Liquid only outflow implies that all vapor formed in the reactor pressure vessel by bulk flashing rises to the surface rather than being entrained in the existing flow. In reality, some of the vapor would be entrained in the break flow which would significantly reduce reactor pressure vessel discharge flow rates. Further, Moodys critical flow model, which assumes annular, isentropic flow, thermodynamic phase equilibrium, and maximized slip ratio, accurately predicts reactor pressure vessel outflows through small orifices. Actual rates through larger flow areas, however, are less than the model indicates because of the effects of a nearly homogeneous two phase flow pattern and phase nonequilibrium. These effects are conservatively neglected in the analysis.
e. Core decay heat and sensible heat released in cooling the fuel to initial average coolant temperature are included in the reactor pressure vessel depressurization calculation. The rate of energy release is calculated using a conservately high heat transfer coefficient throughout the depressurization period. The resulting high energy release rate causes the reactor pressure vessel to maintain nearly rated pressure for approximately 20 seconds. The Revision 12 6.2-6 January, 2003
high reactor pressure vessel pressure increases the calculated blowdown flow rates. This, again, is conservative for analytical purposes. The sensible energy of the fuel stored at temperatures below the initial average coolant temperature is released to the reactor pressure vessel fluid along with the stored energy in the vessel and internals as vessel fluid temperatures decrease during the remainder of the transient calculation.
f. The main steam isolation valves start closing at 0.5 seconds after the accident. These valves are fully closed in the shortest possible time of three seconds following closure initiation.
Actually, the closure signal for the main steam isolation valves occurs as a result of low reactor water level. Therefore, the valves do not receive a signal to close for more than four seconds and the closing time may be as long as five seconds. By assuming rapid closure of the main steam isolation valves, the reactor pressure vessel is maintained at a high pressure which maximizes the calculated discharge of high energy water in the drywell.
g. A complete loss of offsite power occurs simultaneously with the pipe break. This condition results in the loss of power conversion system equipment and also requires that all vital systems for long term cooling be supported by onsite power supplies.
6.2.1.1.3.3.1.2 Assumptions for Containment Pressurization The pressure response of the containment during the first 10 seconds of the accident is analyzed using the following assumptions:
a. Thermodynamic equilibrium exists in the drywell and containment.
Since highly turbulent conditions are expected due to the blowdown flow, the analysis assumes complete mixing. Revision 12 6.2-7 January, 2003
b. Fluid flowing through the drywell to suppression pool vents is formed from a homogeneous mixture of the fluid in the drywell. Use of this assumption results in complete carryover of the drywell air and a higher positive flow rate of liquid droplets which conservatively maximizes vent pressure losses.
c. Fluid flow in the drywell to suppression pool vents is compressible, except for the liquid phase.
d. No heat loss occurs from the gases inside containment. Actually, condensation of some steam on the drywell surfaces would occur.
6.2.1.1.3.3.1.3 Assumptions for Long Term Cooling Following the initial blowdown period, the emergency core cooling system (ECCS), discussed in <Section 6.3>, provides water for core flooding, containment spray and long term decay heat removal. The containment pressure and temperature response during this period is analyzed using the following assumptions:
a. The low pressure core injection (LPCI) pumps are used to flood the core prior to 600 seconds after the accident. The high pressure core spray (HPCS) is available for the entire accident.
b. The effects on suppression pool temperature decay energy, stored energy, sensible energy, energy added by ECCS pumps, and energy from the zirconium water reaction are considered.
c. The suppression pool and the structures inside the containment are the only heat sinks available in the containment system. After a certain period, makeup water from the upper containment pool is included.
Revision 12 6.2-8 January, 2003
d. After approximately 1,980 seconds, the residual heat removal (RHR) heat exchangers are activated to remove energy from the containment by means of recirculation cooling of the suppression pool with the emergency service water system. It is conservatively assumed that containment spray is not used.
Performance of the ECCS equipment during the long term cooling period is evaluated for each of the following cases of interest:
a. Case A: Offsite Power Available, All ECCS Equipment Operating.
b. Case B: Loss of Offsite Power, Minimum Diesel Power Available for ECCS.
6.2.1.1.3.3.1.4 Initial Conditions for Accident Analysis
provides the initial conditions and numerical values assumed for the recirculation line break accident, as well as the sources of energy considered prior to the postulated pipe rupture. The assumed conditions for the reactor blowdown are also provided.
presents the initial reactor coolant system and containment conditions used in all the accident response evaluations. This tabulation includes parameters for the reactor, drywell and containment. Mass and energy release sources and rates for the containment response analyses are addressed in <Section 6.2.1.3>. 6.2.1.1.3.3.1.5 Short Term Accident Response The calculated containment pressure and temperature responses for the recirculation line break are shown by <Figure 6.2-2> and <Figure 6.2-3>, respectively. Following the break, drywell pressure increases rapidly Revision 12 6.2-9 January, 2003 due to the injection of the break flow. The peak drywell pressure occurs during the vent clearing phase of the transient as suppression pool water is being cleared from the vents. Following vent clearing, drywell pressure decreases as break flow decreases. The containment is pressurized early in the transient by the carryover of noncondensibles from the drywell. As the transient continues, break flow is injected into the suppression pool and the temperature of the suppression pool water increases, causing containment pressure to increase. At the end of the blowdown, drywell pressure stabilizes at a slightly higher pressure than the containment, the difference being equal to the hydrostatic head of vent submergence. During the reactor pressure vessel depressurization phase most of the noncondensible gases initially in the drywell are forced into containment. However, following depressurization the noncondensibles are redistributed between the drywell and containment through the vacuum breaker system. This redistribution occurs as steam in the drywell is condensed by the relatively cool ECCS water which begins to cascade from the break causing drywell pressure to decrease (drywell vacuum breaker operation for this condition is not an ESF function). The ECCS supplies sufficient core cooling water to control core heatup and limit metal-water reaction to less than one percent. After the reactor pressure vessel is flooded to the height of the jet pump nozzles, the excess flow discharges through the recirculation line break into the drywell. This flow of water (steam flow is negligible) transports the core decay heat out of the reactor pressure vessel through the broken recirculation line in the form of hot water. This hot water flows into the suppression pool through the drywell to suppression pool vent system.
lists the peak pressure, temperature and time parameters for the recirculation line break as predicted for the conditions presented by
and
, and corresponds with Revision 12 6.2-10 January, 2003 <Figure 6.2-2> and <Figure 6.2-3>. <Figure 6.2-2> includes the time dependent response of the drywell differential pressure. During the blowdown period of the LOCA the pressure suppression vent system conducts the flow of the steam-water gas mixture in the drywell to the suppression pool for condensation of the steam. The pressure differential between the drywell and suppression pool controls this flow. <Figure 6.2-5> provides the mass flow through the vent system versus time relationship for this accident. 6.2.1.1.3.3.1.6 Long Term Accident Responses To assess the adequacy of the containment following the initial blowdown transient, an analysis of the long term temperature and pressure response following the accident was performed. The assumptions used in this analysis are those discussed in <Section 6.2.1.1.3.3.1.3> for the two cases of interest.
a. Case A: Offsite Power Available, All ECCS Equipment Operating (3729 MWt)
This case assumes that offsite ac power is available to operate all cooling systems. During the first 1,800 seconds following the pipe break HPCS, low pressure core spray (LPCS), and all LPCI pumps are assumed to be operating. All flow is injected directly into the reactor vessel. After 1,980 seconds both RHR heat exchangers are activated to remove energy from the containment. In this mode of operation LPCI flow is routed through both RHR heat exchangers where the fluid is cooled before being returned to the suppression pool. The containment pressure response under recirculation line break is bounded by the maximum ECCS curve of <Figure 6.2-6>. Drywell and Revision 20 6.2-11 October, 2017 suppression pool temperature responses for Case A are bounded by the maximum ECCS curves of <Figure 6.2-7> and shown on <Figure 6.2-8> respectively. After the initial blowdown and subsequent depressurization, core decay heat results in a gradual pressure and temperature rise in containment. When the energy removal rate of the RHR System equals the energy addition rate from decay heat, containment pressure and temperature reach a second peak value and then decrease gradually.
summarizes equipment operation, the peak long term containment pressure and the peak suppression pool temperature.
b. Case B1: Loss of Offsite Power, Minimum ECCS Equipment Operating (3729 MWt)
This case assumes that no offsite power is available following the accident and that only minimum diesel generator power is available. After 1,980 seconds LPCI flow through one RHR heat exchanger is returned to the suppression pool. The containment pressure response under this set of conditions is bounded by the minimum ECCS curve of <Figure 6.2-6>. Drywell and suppression pool temperature responses for Case B are bounded by the minimum ECCS curves of <Figure 6.2-7> and shown on <Figure 6.2-8> respectively. A summary for this case is presented by
. <Figure 6.2-9> shows the rate at which the RHR heat exchanger removes heat from the suppression pool following a LOCA (<Section 6.2.2> describes the containment cooling mode of RHR System operation). The heat removal rate is shown by both Case A and Case B. The first case assumes that all ECCS equipment is available, including both RHR heat exchangers and the associated emergency service water pumps. The second case assumes the very degraded minimum cooling condition that limits heat removal capacity to one heat exchanger. For both cases it is conservatively assumed that all the time of the accident the Revision 12 6.2-12 January, 2003 emergency service water is at the maximum design temperature as defined by
.
c. Case B2: Loss of Offsite Power, Minimum ECCS Equipment Operating (3833 MWt)
Case B1 (above) is reanalyzed at 102% core thermal power. <Figure 6.2-6a>, <Figure 6.2-7a>, and <Figure 6.2-8a> show the corresponding results of that evaluation. 6.2.1.1.3.3.1.7 Energy Balance during Accident The following energy sources and sinks are required to establish an energy distribution in containment as a function of time (short term, long term) for this accident:
a. Blowdown energy release rates.
b. Decay heat rate and fuel relaxation sensible energy.
c. Sensible heat rate (vessel and internals).
d. Pump heat rate.
e. Rate of removal of heat from the suppression pool <Figure 6.2-9>.
f. Metal-water reaction heat rate.
g. Rate of heat transfer to structural heat sinks.
A further discussion of Items a. through d. and f. above, is provided in <Section 6.2.1.3>. Revision 20 6.2-13 October, 2017 6.2.1.1.3.3.1.8 Chronology of Accident Events A complete description of the containment response to the recirculation line break is presented by <Section 6.2.1.1.3.3.1.5>, <Section 6.2.1.1.3.3.1.6>, and <Section 6.2.1.1.3.3.1.7>. Results for this accident are illustrated by <Figure 6.2-2>, <Figure 6.2-3>, <Figure 6.2-4>, and <Figure 6.2-5>, <Figure 6.2-8>, <Figure 6.2-8a>, and <Figure 6.2-9> and bounded by <Figure 6.2-6>, <Figure 6.2-6a>, <Figure 6.2-7>, and <Figure 6.2-7a>. 6.2.1.1.3.3.2 Main Steam Line Break The postulated sudden rupture of a main steam line between the reactor pressure vessel and the flow limiter results in the maximum rate of primary system fluid flow and energy transfer to the drywell. This, in turn, results in the maximum drywell differential pressure. Steam flow immediately following rupture of a main steam line between the reactor pressure vessel and the break accelerates to the maximum allowed by the critical flow considerations. On the side adjacent to the reactor pressure vessel the flow corresponds to critical flow in the main steam line break area. Blowdown through the other side of the break occurs because the main steam lines are all interconnected by the bypass header at a point upstream of the turbine. This interconnection allows primary system fluid to flow from the three unbroken steam lines through the header back into the drywell through the broken line. Flow is limited by critical flow in the steam line flow restrictor. The total effective flow area for the main steam line break is given by <Figure 6.2-10>. Revision 12 6.2-14 January, 2003 6.2.1.1.3.3.2.1 Assumptions for Reactor Blowdown The response of the reactor coolant system during the blowdown period of the accident is analyzed using the assumptions listed in <Section 6.2.1.1.3.3.1.1> for the recirculation line break, with the following exceptions:
a. Reactor pressure vessel depressurization flow rates are calculated using Moodys critical flow model (Reference 3). During the first second of blowdown the flow consists of saturated steam.
Immediately following the break the total steam flow rate leaving the reactor pressure vessel exceeds the rate of steam generation in the core. This causes an initial depressurization of the reactor pressure vessel. Void formation in the water within the reactor pressure vessel causes a rapid rise in vessel water level. It is conservatively assumed that water level reaches the vessel steam nozzles one second after the break occurs. The water level rise time of one second is the minimum that could occur under any reactor operating condition. After one second, a two-phase mixture is discharged from the break.
b. The main steam isolation valves start to close at 0.5 seconds after the accident and are fully closed in the maximum time of five seconds after initiation of closure. By assuming slow closure of these valves, a large effective break area is maintained for a longer period of time. Peak drywell pressure occurs before the reduction in effective break area and is, therefore, insensitive to any additional delay in closure of the main steam isolation valves.
6.2.1.1.3.3.2.2 Assumptions for Containment Pressurization The pressure response of the containment during the blowdown period of the accident is analyzed using the assumptions listed in <Section 6.2.1.1.3.3.1.2>. Revision 12 6.2-15 January, 2003 6.2.1.1.3.3.2.3 Assumptions for Long Term Cooling The containment pressure and temperature response during the period following blowdown is analyzed using the assumptions listed in <Section 6.2.1.1.3.3.1.3>. 6.2.1.1.3.3.2.4 Initial Conditions for Accident Analyses
lists the initial conditions and numerical values assumed for the main steam line break accident, as well as the sources of energy considered prior to the postulated pipe rupture. Assumed conditions for the reactor blowdown are also provided.
lists the initial reactor coolant system and containment conditions used in all the accident response evaluations. This tabulation includes parameters for the reactor, drywell and containment. Mass and energy release sources and rates for the containment response analyses are presented in <Section 6.2.1.3>. 6.2.1.1.3.3.2.5 Short Term Accident Response <Figure 6.2-11> and <Figure 6.2-12> show the pressure and temperature responses of the drywell and suppression pool during the first 10 seconds following the main steam line break accident. <Figure 6.2-13> shows the response of the drywell differential pressure and <Figure 6.2-14> shows the vent mass flow versus time. The drywell atmosphere temperature approaches a peak after approximately one second of primary system blowdown. At that time, water level in the reactor pressure vessel reaches the steam line nozzle elevation and the blowdown flow changes to a two phase mixture. This increased flow causes a more rapid drywell pressure rise. The peak differential pressure occurs shortly after the vent clearing transient. As the Revision 12 6.2-16 January, 2003 blowdown proceeds, the primary system pressure and fluid inventory decrease, resulting in reduced break flow rates. As a consequence the flow rate in the vent system and the differential pressure between the drywell and suppression pool begin to decrease.
presents the peak pressures, peak temperatures and times of this accident in comparison with similar parameters for the recirculation line break. 6.2.1.1.3.3.2.6 Long Term Accident Responses After the primary system pressure has decreased to the drywell pressure, the blowdown is over. At this time the drywell contains saturated steam and drywell and containment pressures stabilize. The pressure difference corresponds to the hydrostatic pressure of vent submergence. The drywell and suppression pool remain in this equilibrium condition until the reactor pressure vessel is reflooded. During this period the ECCS pumps inject cooling water from the suppression pool into the reactor. This injection of water eventually floods the reactor vessel to the level of the steam line nozzles. At this point the ECCS flow spills into the drywell. The water spillage condenses the steam in the drywell, reducing drywell pressure. As drywell pressure drops below containment pressure the noncondensible gases from containment flow into the drywell until pressures in the two regions are equalized. The long term containment pressure and temperature responses following the accident are identical to those described in <Section 6.2.1.1.3.3.1.6> for the recirculation line break. The results are shown on or bounded by <Figure 6.2-6>, <Figure 6.2-7>, <Figure 6.2-7a>, <Figure 6.2-8>, <Figure 6.2-8a>, and <Figure 6.2-9>.
summarizes cooling equipment operation, peak long term containment pressure and peak suppression pool temperature at 3729 MWt.
summarizes the results at 3833 MWt. Revision 12 6.2-17 January, 2003 6.2.1.1.3.3.2.7 Energy Balance during Accident The following energy sources and sinks are required to establish an energy distribution in containment as a function of time (short term, long term) for this accident:
a. Blowdown energy release rates.
b. Decay heat and fuel relaxation sensible energy.
c. Sensible heat rate (reactor pressure vessel and internals).
d. Pump heat rate.
e. Rate of removal of heat from the suppression pool <Figure 6.2-9>.
f. Metal-water reaction heat rate.
g. Rate of heat transfer to structural heat sinks.
A further discussion of Items a. through d. and f. above, is provided in <Section 6.2.1.3>. A complete energy balance for the main steam line break accident is provided by
for the reactor system, containment and containment cooling systems at time zero, time of peak drywell pressure, time of end of reactor blowdown, and time of long term peak pressure in containment. 6.2.1.1.3.3.2.8 Chronology of Accident Events A complete description of the containment response to the main steam line break is presented in <Section 6.2.1.1.3.3.2.5>, <Section 6.2.1.1.3.3.2.6>, and <Section 6.2.1.1.3.3.2.7>. Results for this accident analysis are shown by <Figure 6.2-6>, <Figure 6.2-6a>, <Figure 6.2-7>, <Figure 6.2-7a>, and <Figure 6.2-10>, <Figure 6.2-11>, Revision 20 6.2-18 October, 2017 <Figure 6.2-12>, <Figure 6.2-13>, and <Figure 6.2-14>. A chronological sequence of events for this accident from time zero is provided by
. This chronology is based on a power level of 3729 MWt. 6.2.1.1.3.3.3 Hot Standby Accident Analysis This accident was not reanalyzed for power uprate since it was not the limiting case. The analysis presented below is based on a power of 3729 MWt. Both the short term and long term response of the containment system have been evaluated, assuming that the reactor has been operating in the hot standby mode prior to the LOCA. The peak drywell pressure following a main steam line break is dependent upon the rise time of the reactor pressure vessel water level since this determines the time at which two phase blowdown begins. A level rise time of one second is a conservative bounding condition for a main steam line break at a reduced reactor power level. However, since a one second level rise time was conservatively assumed for the LOCA at 104.2 percent of rated power, the peak drywell pressure following a blowdown at hot standby will be no higher than shown by <Figure 6.2-11>. In the event of a recirculation line break, the short term blowdown flow rate is essentially independent of reactor power level if the same initial reactor pressure is assumed for all power levels. In practice the lower reactor pressures associated with reduced reactor power result in lower blowdown flow rates and in peak drywell pressures lower than the value presented by <Figure 6.2-2>. The short term drywell response to either a main steam line or recirculation line break is insensitive to suppression pool water temperature. This insensitivity is due to domination of the transient by the rate at which energy is transferred to the drywell and the rate at which vent clearing can be accomplished. Neither is sensitive to suppression pool water temperature. Revision 12 6.2-19 January, 2003 The long term suppression pool and containment transient is only affected very slightly by a period of hot standby operation prior to blowdown. <Figure 6.2-15> presents a comparison of suppression pool temperature transients following a blowdown under the following conditions:
a. Maximum normal suppression pool water temperature and 104.2 percent of rated power.
b. Approximately 700 seconds of hot standby operation.
Since in both cases containment cooling (RHR System) is initiated 1,980 seconds after the start of the event, the peak long term suppression pool temperature is about the same, as can be seen from <Figure 6.2-15>. 6.2.1.1.3.3.4 Intermediate Size Breaks This accident was not reanalyzed for power uprate since it was not the limiting case. The analysis presented below is based on a power of 3729 MWt. The classification, intermediate size breaks, includes those breaks, the blowdown from which results in reactor depressurization and operation of the ECCS. This section describes the consequences to the containment of 2 a 0.68 ft break below the reactor pressure vessel water level. This break was chosen as being representative of the intermediate size break range. Such breaks can involve either reactor steam or liquid blowdown. Following the occurrence of the 0.68 ft2 break, drywell pressure increases at approximately one psi/sec. This transient is sufficiently slow that the dynamic effect of the water in the vents is negligible and the vents clear when the drywell to containment differential pressure is equal to the vent submergence hydrostatic pressure. Revision 12 6.2-20 January, 2003 <Figure 6.2-16> and <Figure 6.2-17> show the drywell and containment pressure and temperature response, respectively. The ECCS response is discussed in <Section 6.3>. Approximately five seconds after the 2 0.68 ft break occurs, air, steam and water start to flow from the drywell to the suppression pool. The steam is condensed and the air enters the containment free space. The continual purging of drywell air to the containment results in a gradual pressurization of both containment and drywell. Containment pressure continues to gradually increase due to the long term suppression pool heatup. The ECCS is initiated as a result of the 0.68 ft2 break and provides emergency cooling of the core. Operation of the ECCS is such that the reactor is depressurized in approximately 600 seconds, terminating the blowdown phase of the transient. In addition, the suppression pool temperature at the end of blowdown is the same as that of the main steam line break because essentially the same amount of primary system energy is released during the blowdown. After reactor pressure vessel depressurization and reflood, water from the ECCS begins to flow out the break. This flow condenses the drywell steam and eventually causes the drywell and containment pressures to equalize in the same manner as described for a main steam line break. The subsequent long term suppression pool and containment heatup transient that follows is essentially the same as for the main steam line break. 6.2.1.1.3.3.5 Small Size Breaks This accident was not reanalyzed for power uprate since it was not the limiting case. The analysis presented below is based on a power of 3729 MWt. Revision 12 6.2-21 January, 2003 6.2.1.1.3.3.5.1 Reactor System Blowdown Considerations This section discusses the containment transient associated with small primary system blowdowns. The sizes of primary system ruptures in this category are those blowdowns that do not result in reactor pressure vessel depressurization due either to loss of reactor coolant or automatic operation of ECCS equipment. Following the occurrence of a break of this size, it is assumed that the reactor operators initiate an orderly plant shutdown and depressurization of the reactor system. The thermodynamic process associated with blowdown of primary system fluid is one of constant enthalpy. If the primary system break is below the water level, blowdown flow consists of reactor water. Blowdown from reactor pressure to drywell pressure results in flashing of approximately one third of the blowdown water to steam. Two thirds of the water remains liquid. Both phases are at saturation conditions corresponding to the drywell pressure. Thus, if the drywell is at atmospheric pressure, for example, the steam and liquid associated with a liquid blowdown would be at a temperature of 212F. If the primary system rupture is so located that the blowdown flow consists only of reactor steam, the resultant steam temperature in drywell is significantly higher than the temperature associated with liquid blowdown. This is because the constant enthalpy depressurization of high pressure, saturated steam results in superheated conditions. For example, decompression of saturated steam at 1,000 psia to atmospheric pressure results in superheated steam at 298F (86F of superheat). A small reactor steam leak resulting in superheated steam imposes the most severe temperature conditions on the drywell structures and on the safety equipment in the drywell. For larger steam line breaks, the superheat temperature is nearly the same as for small breaks but the duration of the high temperature condition is less for the larger break. This is a result of the more rapid depressurization of the reactor Revision 12 6.2-22 January, 2003 pressure vessel through the larger breaks. Depressurization is slower for the orderly shutdown assumed to terminate the small break. 6.2.1.1.3.3.5.2 Containment Response For drywell design considerations, the following sequence of events is assumed to occur. With the reactor and containment operating under normal maximum conditions, a small break occurs that allows blowdown of reactor steam to the drywell. The resulting pressure increase in the drywell leads to a high drywell pressure signal that scrams the reactor and initiates the containment isolation logic. Drywell pressure continues to increase at a rate dependent upon the size of the steam leak. The pressure increase lowers the water level in the annulus until the level begins to clear the vents. At this time, air and steam start to enter the suppression pool. The steam is condensed and the air carries over to the containment free space. The air carryover results in a gradual pressurization of the containment at a rate dependent upon the size of the steam leak. Once all of the drywell air is carried over into the containment, short term containment pressurization ceases and the system reaches an equilibrium condition. The drywell contains only superheated steam and continued blowdown of reactor steam is condensed in the suppression pool. Suppression pool temperature continues to rise until the RHR heat exchanger heat removal rate equals the decay heat release rate. 6.2.1.1.3.3.5.3 Recovery Operations The reactor operators are alerted to the small size break incident by the high drywell pressure signal and reactor scram. For purposes of evaluating the duration of the superheat condition in the drywell, it is assumed that the response of the operators is to shut down the reactor in an orderly manner, using the main condenser, while limiting the reactor cooldown rate to 100F/hr. This results in depressurization of the primary system within six hours. At this time blowdown flow to the Revision 20 6.2-23 October, 2017 drywell ceases and the superheat condition is terminated. If the operators elect to cool down and depressurize the primary system more rapidly than at 100F/hr, the duration of the drywell superheat condition is shorter. 6.2.1.1.3.3.5.4 Drywell Design Temperature Considerations For drywell design purposes it is assumed that there is a blowdown of reactor steam for the six hour cooldown period. The corresponding design temperature is determined by finding the combination of primary system pressure and drywell pressure that produces the maximum superheat temperature. The maximum drywell steam temperature occurs when the primary system is at approximately 450 psig and the drywell pressure is maximum. Thus, for design purposes, it is assumed that the drywell is at 15 psig. This results in temperatures of 330F for the first three hours of the cooldown period, and 310F for the next three hours. 6.2.1.1.3.4 Accident Analysis Models 6.2.1.1.3.4.1 Short Term Pressurization Model The analytical models, assumptions and methods used by GE to evaluate the containment response during the reactor pressure vessel blowdown phase of a LOCA are described in (Reference 1) and (Reference 2). 6.2.1.1.3.4.2 Long Term Cooling Model Once the reactor pressure vessel blowdown phase of the LOCA is over, a fairly simple model of the drywell and containment is used. During the long term post-blowdown transient, the RHR containment cooling system flow path is a closed system and the suppression pool mass is constant. The cooling loop model used for analysis is schematically illustrated by <Figure 6.2-18>. Revision 12 6.2-24 January, 2003 The analytical models, assumptions and methods used by GE to evaluate the containment response during the long term cooling phase of a LOCA are described in (Reference 2). 6.2.1.1.3.5 High Energy Line Rupture Inside Containment Some primary system pipes are routed from the drywell through the containment to the auxiliary building (main steam lines for example). If such pipes were unguarded, rupture within containment would result in direct release of primary system fluid to the containment atmosphere. The pressure suppression features of the containment would thus be bypassed and the potential would exist for a pipe rupture to produce significant containment pressures. Because of the potential for overpressurizing containment, all reactor coolant pressure boundary pipes of a size which would result in containment overpressurization and which pass through the containment except LPCI, HPCS and LPCS pipes, are provided with guard pipes that vent to the drywell. Thus, in the event of rupture of a reactor coolant pressure boundary pipe, flow passes through the suppression pool vent system and the steam is condensed. The LPCI, HPCS and LPCS pipes have check valves inboard of the drywell penetration that prevent blowdown to the containment. The traversing incore probe, control rod drive insert and withdraw and instrument lines could discharge primary coolant to the containment in the event of a rupture. The unisolatable instrument line rupture results in the maximum discharge of primary coolant to containment. This accident is discussed in <Chapter 15>. Each instrument line includes a 1/4 inch diameter flow restricting orifice to limit the containment pressure increase to values well below the design pressure. Revision 12 6.2-25 January, 2003 The major components of the reactor water cleanup system are located within containment and system piping could also discharge primary coolant to the containment in the event of rupture. The system suction line penetrates the drywell and is provided with a guard pipe. System components located inside containment are provided with break detection and isolation systems that limit the total blowdown fluid flow to containment to acceptable values. 6.2.1.1.4 Negative Pressure Design Evaluation 6.2.1.1.4.1 Evaluation of Drywell Negative Differential Pressure Following the blowdown phase of a LOCA, air initially contained in the drywell has been purged to the containment and the drywell is full of steam. During this period the ECCS is injecting cooling water from the suppression pool into the reactor pressure vessel. When the reactor pressure vessel is flooded to the level of the break, water begins spilling into the drywell, condensing the steam and causing rapid depressurization of the drywell. A bounding calculation of the peak drywell negative differential pressure is based upon the following conservative assumptions:
a. All air has been purged out of the drywell.
b. Drywell vacuum breakers do not open.
c. The suppression pool is at the design temperature of 185F.
d. The containment is at suppression pool temperature and 100 percent relative humidity.
e. Steam in the drywell is cooled to suppression pool temperature.
Revision 12 6.2-26 January, 2003 Using the above assumptions, the final drywell pressure is equal to saturation pressure at 185F or: Pd = 8.38 psia Based upon the initial conditions listed in
, the initial air masses in the drywell and containment are: Md = 19,193 lbm (145F at drywell) Mc = 78,106 lbm Using the assumptions in Items a. through e., above, the final containment pressure for the purposes of determining the drywell negative differential pressure is calculated as the summation of the partial pressures of air and vapor: Pc = 28.48 psia Thus, the bounding negative pressure load across the drywell wall is: Pd = Pd - Pc Pd = -20.1 psid 6.2.1.1.4.2 Evaluation of Containment Negative Pressure If the containment spray system is activated during any period of time other than when it is designed to be operated, it is possible that a vacuum could be created inside the containment vessel. If the containment spray system is accidently activated, an excessive vacuum is prevented from developing by means of vacuum breakers provided for this purpose. Containment vacuum relief capability is necessary only to maintain containment integrity should the containment spray system be operated in such a way as to tend to create a vacuum inside containment. Although the containment spray system is adequately protected against Revision 12 6.2-27 January, 2003 inadvertent, unintentional or incorrect operation by interlocks and administrative procedures <Section 6.2.2>, two hypothetical situations are considered, assuming these protective measures are bypassed in some manner and the spray is started:
a. For the first situation, pressure and temperature conditions for the containment atmosphere are based on the following sequence of events:
1. The atmosphere inside containment is at normal pressure and temperature.
2. A 6-inch reactor water cleanup (RWCU) line break occurs inside containment.
3. Isolation of the RWCU line is complete at 40 seconds after the accident. At this time, the containment pressure is 5 psig, temperature is 157F, and the containment has been isolated.
4. The vacuum breakers between the containment and drywell
<Section 3.8.3> open to equalize the pressure of the containment and drywell. During this pressure equalization period, a portion of the containment air is swept into the drywell through the drywell vacuum breakers and remains there when the vacuum breakers close. The maximum amount of air drawn into the drywell from containment is simply the difference between the amount of air in containment during normal operation and the amount of air in containment after the RWCU line isolation, assuming a slightly conservative relative humidity of 100 percent. Revision 12 6.2-28 January, 2003 Normal Operating RWCU Line Conditions Isolation Pressure, psig 0.0 5.0 Temperature, F 90.0 157.0 Relative Humidity, % 50.0 100.0 Mass of air, lbm 82,200.0 78,100.0
5. The containment spray system is activated at a flow rate of 10,500 gpm and a temperature of 60F (minimum suppression pool temperature). Note: System flow rates of 6,000 gpm per spray loop (12,000 gpm total) are possible. A qualitative analysis indicated that the containment negative pressure analysis remains valid when considering an 87% spray efficiency for this event.
6. The containment is depressurized as a result of steam being condensed by the containment spray; the spray droplets are assumed to have an efficiency of 100 percent. Three cases are considered in sizing the containment vacuum breakers:
(a) Condensation rate including heat transfer structures with initial temperature of 80F. (b) Condensation rate including heat transfer structures with initial temperature of 90F. (c) The effects of the internal surfaces on the condensation rate are not considered. This is the limiting case. The resulting pressure-temperature history within containment is calculated using the digital computer code CONTEMPT (Reference 5). Revision 14 6.2-29 October, 2005
7. <Figure 6.2-19> and <Figure 6.2-20> present the results of the analyses for Cases a and b, respectively. Curves are plotted on these figures showing the containment vapor pressure and temperature, the total vapor mass, and the surface temperature of the internal concrete and steel liner as a function of time after RWCU isolation.
<Figure 6.2-21> presents the results for Case c. As indicated by comparing these three figures the net effect of considering the internal surfaces is a lesser vacuum condition than when the effects of the internal surfaces are not considered. The peak vacuum calculated is 0.70 psig.
b. For the second situation, it is assumed that the containment depressurization is a result of accidental initiation of the containment spray system during normal plant operation. The conditions present in the containment at the time of spray initiation are chosen to provide the most conservative results:
1. Maximum temperature in containment during normal operation: 105F.
2. Minimum relative humidity in containment during normal operation: 30 percent.
3. Minimum spray water temperature: 60F.
The source for the containment spray system water is the suppression pool. The normal water temperature in the pool is 90F or equal to the normal operating temperature in the containment vessel outside the drywell. The minimum temperature of 60F for the suppression pool is based on the minimum ambient air temperature (60F) in the drywell and Revision 12 6.2-30 January, 2003 containment vessel which could occur only under shutdown conditions. As described in <Section 9.4.6>, the reactor building ventilation system is designed to assure that the temperature of the containment atmosphere never falls below 60F.
4. Spray system flow rate: 10,500 gpm Note: System flow rates of 6,000 gpm per spray loop (12,000 total) are possible. A qualitative analysis indicated that the containment negative pressure analysis remains valid when considering a flow rate of 12,000 gpm combined with a 95F initial containment temperature (limited by the Technical Specifications) and assuming an 87% spray efficiency for this event.
5. During the evaporative cooling phase of the transient, the water drops sprayed into the containment absorb heat from the containment atmosphere and evaporate to contribute to saturating the containment atmosphere. This process is generally very rapid for spray rates typical of containment spray systems, and therefore, the time to complete the evaporative cooling process is important to compare to the vacuum breaker response time. In the calculations presented here the following assumptions are made:
(a) Spray efficiency is 100 percent. (b) All of the spray water entering the containment is immediately vaporized and forms a homogeneous mixture with the containment atmosphere. Because of this conservative assumption, no detailed analytical heat/mass transfer modeling of the spray droplets is required. (c) No heat is transferred back into the containment atmosphere from the structures during the transient. Revision 14 6.2-31 October, 2005 (d) The mass flow through two 24-inch diameter containment vacuum relief lines as a function of pressure differential is shown on <Figure 6.2-22>. The equations used in the analyses are derived from the conservation of mass and energy and the equations of state of water and air. Utilizing the above assumptions the equations can be written as: (a) Conservation of mass: dm g m fg dt dm f m s m fg dt The assumption of instantaneous evaporation of the spray water defines the following additional relationship: m fg m s and therefore, dm f m s m fg 0 dt (b) Conservation of energy: From these equations it can be seen that the equation for the conservation-of-energy includes the effect of evaporative cooling. This equation is given as: d dt m a u a m g u g m f uf m s h f m fg h f Revision 12 6.2-32 January, 2003 For any addition of low enthalpy spray water, the heat required for evaporation lowers the total energy (temperature) of the vapor region, thereby lowering the partial pressure of the air (constant mass with decreasing temperature) while increasing the partial pressure of the vapor (result of increasing mass of vapor being more dominant than decreasing temperature). (c) Equation of state: pa V m a R aT pg V m g R g T Where: ma = Mass of air, lbm mf = Mass of liquid water, lbm mg = Mass of vapor, lbm m s = Rate of spray water, lbm/sec m fg = Rate of evaporation, lbm/sec ua = Internal energy of air, Btu/lbm uf = Internal energy of liquid water, Btu/lbm ug = Internal energy of vapor, Btu/lbm hf = Enthalpy of spray water, Btu/lbm pa = Partial pressure of air, psi pg = Partial pressure of vapor, psi Ra = Gas constant of air, ft-lbf/R-lbm Rg = Gas constant of vapor, ft-lbf/R-lbm T = Temperature of the containment atmosphere, R V = Volume of the containment, ft3 Revision 12 6.2-33 January, 2003 The Hammings modified predictor - corrector method is used to obtain an approximate solution of the equations listed above (Reference 6).
6. After the evaporative cooling phase of the analyses is complete, the pressure - temperature history of the containment in the saturated condition is calculated utilizing the digital computer code CONTEMPT (Reference 5).
<Figure 6.2-23> shows the pressure and temperature inside containment as a function of time after start of the containment spray system. As indicated on this curve the resulting peak vacuum calculated is 0.72 psig. In addition, <Figure 6.2-24> shows a curve of initial containment temperature versus relative humidity which results in a peak calculated vacuum of approximately 0.7 psig. This curve is used in establishing plant technical specifications. As a result of these analyses, a value of 0.8 psi is selected as the design negative pressure differential between the outside atmosphere and containment atmosphere (acting inward on the containment vessel). The containment vacuum relief system is available for any postulated situation requiring relief of a vacuum inside containment. This would include the rupture of a RWCU line. For this event, the containment vacuum relief isolation valves would initially be closed by high drywell pressure. After initiation of the spray system differential pressure switches in the containment override the containment isolation signal and open the vacuum relief isolation valves when the outside to containment atmosphere differential pressure has decreased to 0.0 psid. Vacuum breaker opening for other than the inadvertent containment spray actuation scenarios presented in this section is considered a non-ESF actuation. Conditions which result in changes to the containment Revision 12 6.2-34 January, 2003 atmosphere, (such as containment venting and cooling, suppression pool level changes and weather changes), and subsequently result in containment vacuum breaker operation, are considered normal and expected, and are bounded by the limiting inadvertent containment spray situations. <Section 7.3.1> gives details of the instrumentation and logic for this system. 6.2.1.1.4.2.1 Vacuum Breaker Design Two 24-inch nominal diameter vacuum relief lines are provided to obtain the vacuum relief cross-sectional area required to prevent the negative pressure inside containment from exceeding the design value of 0.8 psi during the hypothetical situations presented in this section. Two additional 24-inch nominal diameter vacuum relief lines are provided for redundancy. Each vacuum relief line has a 24-inch nominal diameter, free swinging, simple check valve inside containment. This check valve serves as both the vacuum breaker device and the inner isolation valve for the vacuum relief line. Outside containment, each vacuum relief line has a 24-inch nominal diameter motor-operated butterfly valve to serve as the outer isolation valve. A combination of any two vacuum relief lines provides a 10 percent margin between the maximum calculated negative pressure and the design negative pressure. If all four vacuum relief lines are assumed operable (i.e., no failures) this margin is increased to 80 percent. These margins are considered satisfactory for the following reasons:
a. When a design negative pressure differential is selected and an A / K ratio is calculated, sizing of the vacuum breakers depends entirely upon the K value used. Precise, tested, k values are available from vacuum relief valve manufacturers. In addition, a Revision 12 6.2-35 January, 2003
10 percent margin on friction losses is standard in sizing piping systems.
b. The hypothetical situations used in the analyses are very conservative in that they assume during each of the occurrences that the suppression pool is at its minimum design temperature while the containment atmosphere is at its peak temperature.
6.2.1.1.4.2.2 Testing and Inspection Periodically, each check valve is exercised to ensure that it is in proper working condition. For this purpose, each check valve has an air cylinder for power operated exercising. Testing and inspection of the containment isolation function of the check valves and the outer isolation valves are discussed in <Section 6.2.4.4> and <Section 6.2.1.6>. 6.2.1.1.4.2.3 Instrumentation Applications The vacuum breaker check valves are normally closed. They begin to open under a pressure differential of 0.1 psid and close by gravity. The motor-operated outer isolation valves are controlled remote-manually from the control room or automatically, as discussed in <Section 6.2.4> and <Section 7.3.1>, and are open during normal plant operation. Position indicators on the vacuum breaker check valves annunciate in the control room if any of these check valves stick open during normal plant operation. If this occurs, the outer isolation valves are closed manually from the control room. Revision 12 6.2-36 January, 2003 6.2.1.1.5 Steam Bypass of the Suppression Pool 6.2.1.1.5.1 Introduction The concept of the pressure suppression reactor containment is that any steam released from the primary system is condensed by the suppression pool and does not have an opportunity to produce a significant pressurization effect on the containment. This is accomplished by channeling the steam into the suppression pool through a vent system. This arrangement forces steam released from the primary system to be condensed in the suppression pool. Should a leakage path exist between the drywell and containment, the leaking steam would result in pressurization of the containment. To mitigate the consequences of any steam bypassing the suppression pool, a high containment pressure signal automatically initiates the containment spray system any time after LOCA plus ten minutes. Realignment logic and interlocks affecting operation of containment spray are discussed in <Section 7.3>. <Section 6.2.1.1.5.2>, <Section 6.2.1.1.5.3>, and <Section 6.2.1.1.5.4> present the results of calculations performed to determine the allowable leakage capacity between the drywell and containment. 6.2.1.1.5.2 Criteria The allowable bypass leakage is defined as the amount of steam which could bypass the suppression pool without exceeding the design containment pressure. In calculating this value, a stratified atmosphere model is used to ensure conservatism. Revision 20 6.2-37 October, 2017 6.2.1.1.5.3 Analysis The allowable drywell leakage capacity has been evaluated for the complete spectrum of credible primary system rupture areas. This leakage capacity is expressed in terms of the parameter: A/ K Where: A = Flow area of leakage path, ft2. K = Geometric and friction loss coefficient. The parameter A / K is dependent only upon the geometry of drywell leakage paths and is a convenient numerical definition of the overall drywell leakage capacity. It results from a consideration of the flow process in the leakage paths. Assuming steady-state, incompressible fluid flow theory to be applicable to the leakage flow, the pressure loss between the drywell and containment can be written as follows: V2 1 Pd Pc K 2gc 144v Where: Pd = Drywell pressure, psia. Pc = Containment pressure, psia. K = Total loss coefficient of the flow path between the drywell and containment. These losses include entrance, exit, discontinuities, and friction. The latter is somewhat dependent upon the Reynolds number of the fluid flow but, for drywell leakage considerations, can be considered constant. Revision 12 6.2-38 January, 2003 Where: (Continued) V = Velocity of flow, ft/sec. gc = Gravitational constant, lbm-ft/lbf-sec2. v = Specific volume of fluid flowing in the leakage path, ft3/lbm. Given the equation for flow rate of m AV/v . If the leakage path flow 2 rate is m lb m /sec and the flow area is A ft , the above equations can be rewritten to give: A 144 m 2gc Pd Pc K v Thus for a given drywell to containment pressure differential, the leakage flow (capacity) is dependent only upon A / K . 6.2.1.1.5.4 Bypass Capability with Containment Spray and Heat Sinks An analysis has been performed which evaluates the bypass capability of the containment for small primary system breaks, considering containment spray and containment heat sinks as means for mitigating the effects of bypass leakage. The flow rate of one containment spray loop is 5,250 gpm. This flow is assumed to start not sooner than ten minutes after the accident. The suppression pool water passes through the RHR heat exchanger and is injected into the upper containment region. The spray rapidly condenses the stratified steam and, therefore, creates a homogeneous air-steam mixture in containment. The available containment heat sinks, listed in
, were considered with variable convective heat transfer coefficients, based upon the local instantaneous air-steam ratio. The cooldown rate was assumed to be 100F/hr and the maximum design service Revision 12 6.2-39 January, 2003 water temperature
was used. The cooldown rate corresponds to the maximum rate which does not thermally cycle the reactor pressure vessel. This analysis results in an allowable drywell leakage capability of A / K of 1.68 ft2. This allowable drywell leakage capability (1.68 ft2) is calculated to ensure that the containment design pressure of 15 psig (29.7 psia) will not be exceeded (Reference 37). A similar pressure 2 transient for an A / K of 1.0 ft for a Mark III design (Reference 38) is provided in <Figure 6.2-25>. Assumptions for allowable bypass calculations using heat sinks are as follows:
a. Following occurrence of a pipe line break within the drywell, the air is purged through the vents into containment.
b. Prior to containment spray operation, the bypassed steam is assumed to stratify in the upper containment.
c. Air in containment is compressed by incoming steam.
d. Containment spray is activated 180 seconds after containment pressure reaches 9 psig or at LOCA plus 13 minutes, whichever occurs later.
e. Efficiency of containment spray is based upon the local steam to air ratio.
f. Following spray activation, the air and steam in containment become mixed.
Revision 13 6.2-40 December, 2003
g. Heat is transferred to exposed concrete and steel containment. The Uchida convective heat transfer coefficients used are based upon the local steam to air ratio.
h. No energy is assumed to leave the containment, except through the RHR heat exchanger.
Revision 13 6.2-40a December, 2003 The following analysis provides an illustration of the methods used to calculate steam condensing capability under typical post-LOCA conditions. The condensation capability is calculated using the following equation: Ns Tc Ts M c M s Cp H fg Where: M c = Steam condensation rate, lbm/sec. M s = Spray flow rate, lbm/sec (degraded flow of one RHR pump). Ns = Spray efficiency. Tc = Containment temperature, F. Ts = Spray temperature at the nozzles, F. Hfg = Latent heat of vaporization, Btu/lbm. Cp = Constant pressure specific heat of water, Btu/F-lbm. The spray water temperature is calculated from: KHX Tp Tsw Ts Tp M Cp Where: Tp = Suppression pool temperature, F. KHX = Heat exchanger effectiveness, Btu/sec - F (degraded). Tsw = Service water temperature F. Containment spray has a significant effect on the allowable bypass capacity. Use of spray increases the maximum allowable bypass rate by an order of magnitude and represents an effective backup means of condensing bypass steam. Revision 12 6.2-41 January, 2003 A study was performed by GENEDO-10977 (Reference 4), of potential cracking of the reinforced concrete drywell due to shrinkage, thermal gradients, seismic events, small breaks, LOCAs, and combinations of these has been performed and indicates no significant cracking of the drywell walls. The drywell liner is not required to maintain a leak tight barrier and the GE generic concrete crack analyses demonstrates that the maximum allowable bypass leakage will be maintained. The study also concluded that there was no through cracking due to a large break DBA in a main steam or recirculation line plus SSE. The conservatisms in the crack study as supplemented by CEI/GAI calculations, reinforcement ratios and penetration reinforcement practices provide a conservative bound on estimated crack widths and drywell bypass leakage flow paths. Under an SBA, no bypass leakage flow paths are predicted through the drywell concrete. Under a DBA, even with the extremely conservative assumption of concurrent peak drywell pressures, maximum SSEearthquake forces, concurrent SRV actuations, and precracks at all construction joints, the maximum predicted bypass leakage flow path is only 0.35 ft2 as compared to an allowable 5 ft2. 6.2.1.1.6 Suppression Pool Dynamic Loads Following a design basis LOCA in the drywell, the drywell atmosphere is rapidly compressed due to blowdown mass and energy addition to the drywell volume. This compression is transmitted to the water in the weir annulus in the form of a compressive wave which propagates through the horizontal vent system into the suppression pool. Upon pressurization of the drywell, water in the weir annulus is depressed and forced out through the horizontal vent system into the suppression pool. This movement of pool water can result in a vent clearing reaction force on the weir wall and a water jet impingement force on the containment wall. Revision 12 6.2-42 January, 2003 Following vent clearing, the air-steam-water mixture flows from the drywell through the vents and is injected into the suppression pool. A vent flow reaction load is imparted to the weir wall and a vent flow differential pressure loads the drywell wall. During vent flow the steam component of the flow mixture condenses in the suppression pool while the air, since it is noncondensible, is released to the suppression pool in the form of high pressure air bubbles. Initial air bubble loads are experienced by all suppression pool retaining and submerged structures. The continued addition and expansion of air within the suppression pool causes pool volume to swell resulting in acceleration of the pool surface vertically upward. This response of the suppression pool is referred to as bulk pool swell since the air is confined beneath the pool and is driving a solid ligament of water. Bulk pool swell air bubble and flow drag loads are imparted to the drywell and containment walls and to structures, components, etc., which may be located at low elevations above the normal pool surface. Bulk pool swell impact loads also result for low elevation structures and components. Due to the effects of buoyancy, air bubbles rise faster than the suppression pool water mass and eventually break through the swollen surface and relieve the driving force beneath the pool. This breakup of the water ligament leads to the upward expulsion of a two-phase mixture of air and water and is referred to as pool swell in the froth mode. Structures which are located at higher elevations above the initial pool surface, i.e., the hydraulic control unit (HCU) floors, experience a pool swell froth impingement load due to impact of two phase flow. In the annular region between the drywell and containment walls where pool swell occurs, a flow restriction exists at the HCU floor level, approximately 27 above the normal pool surface. The volume between the normal suppression pool surface and the HCU level is referred to as the Revision 20 6.2-43 October, 2017 wetwell. During pool swell in the froth mode, passage of the air-water mixture through this restriction generates a two-phase flow pressure drop and produces a wetwell pressurization load on the HCU floors. Froth flow continues until the fluid kinetic energy is expended, followed by fallback of the water to the initial suppression pool level. Water fallback loads are experienced by all previously mentioned structures and equipment in the wetwell. Following the initial pool swell event, the suppression system settles into a generally coherent phase during which vent flow rates are maintained from the drywell to the suppression pool. A resultant effect is the occurrence of vent flow steam condensation loads on pool retaining structures. As the reactor coolant system inventory of mass and energy is depleted near the end of blowdown, venting rates to the suppression pool diminish, allowing recovering of each row of horizontal vents. During phases of low vent mass flux, the suppression system behaves in an oscillatory manner, referred to as chugging. This periodic clearing and subsequent recovering of vents occurs since the vent flow cannot sustain bulk steam condensation at the vent exit. The resultant local fluctuations in pressure and water level generate chugging oscillation loads, predominantly on the drywell and weir wall. Pool dynamic loading associated with relief valve operations has been identified in addition to loading associated with the design basis LOCA. Pressure waves are generated within the suppression pool when, upon first opening, relief valves discharge air and steam into the pool water. This phenomenon yields steam vent clearing loads which are imparted to pool retaining and submerged structures. The design basis loads for the containment system due to pool swell and safety/relief valve actuation discussed in <Appendix 3A>. Revision 12 6.2-44 January, 2003 6.2.1.1.7 Containment Environment Control The functional capability of the normal containment ventilation systems to maintain the temperature, pressure and humidity in the containment and subcompartments within prescribed limits (maximum allowable containment conditions) are discussed in <Section 9.4.6>. 6.2.1.1.8 Postaccident Monitoring The containment atmosphere monitoring system provides highly reliable instrumentation for detecting and possibly predicting abnormal occurrences in containment and for monitoring following postulated accidents. Temperature and pressure sensors are furnished throughout the containment and drywell and are equipped with adjustable alarm features. Instrumentation channels are of high quality and accuracy so that precise monitoring information is available to the operator. The suppression pool is similarly instrumented for purposes of temperature monitoring. Monitoring system components are considered to be safety-related and are qualified in accordance with IEEE Standards 323 (Reference 7) and 344 (Reference 8). Redundant channels are provided and independence is maintained in accordance with the criteria of IEEE Standards 279 (Reference 9) and 384 (Reference 10). Redundant Train A and Train B components are used. Precision trip/calibration units continuously monitor each channel to ensure accurate alarming and inplace calibration at any time. Recording of all containment atmosphere monitoring safety-related channels is accomplished at the postaccident monitoring panel in the control room. Further details concerning the containment atmosphere monitoring system are presented in <Section 7.6>. Revision 12 6.2-45 January, 2003 6.2.1.2 Containment Subcompartments 6.2.1.2.1 Design Bases An analysis of the containment subcompartments containing high energy piping, in which breaks are postulated to occur, has been performed. The breaks selected for a pressurization analysis are those which release the most energy into the subcompartments. All of the breaks were assumed to be circumferential. Appropriate restraints were used where applicable to limit the mass release while still producing conservative results. Final design margins above the peak calculated pressure are given in the appropriate tables for each subcompartment analyzed. 6.2.1.2.2 Design Features 6.2.1.2.2.1 Analyses Performed
a. Reactor Annulus Pressurization The reactor annulus was analyzed for recirculation line breaks and for a feedwater line break. Obstructions considered included feedwater piping, recirculation piping, instrument lines, inservice inspection pins, and insulation.
b. Drywell Head Region Pressurization A six inch reactor core isolation cooling (RCIC) spray line enters the head region of the drywell and is attached to the top of the reactor pressure vessel <Figure 6.2-26>. When this line breaks, the reactor pressure vessel blows down into the head region which Revision 20 6.2-46 October, 2017
is vented to the drywell through six 20-inch holes in the bulkhead member. The six inch RCIC line is not assumed to discharge any liquid since the RCIC outboard isolation valve is closed.
c. Reactor Water Cleanup Rooms Pressurization Four reactor water cleanup rooms, listed below, were analyzed:
1. Heat exchanger room.
2. Filter demineralizer valve room.
3. Filter demineralizer room.
4. Drain valve nest room.
Plan and elevation drawings of the above rooms are provided by <Figure 6.2-27>.
d. Steam Tunnel Pressurization The steam tunnel was analyzed for the same break as were the reactor water cleanup rooms. This break was used since the main steam lines are enclosed in guard pipes inside containment. Plan and elevation drawings showing the steam tunnel and the break location are provided by <Figure 6.2-27>.
e. Bulkhead Plate P Analysis An analysis has been performed to determine the peak pressure differential across the drywell bulkhead plate resulting from the postulated rupture of a main steam line at the reactor vessel nozzle. <Figure 6.2-51a> presents a schematic of the model used for the pressurization analysis.
Revision 12 6.2-47 January, 2003 6.2.1.2.2.2 Subcompartment Volumes Volumes of the subcompartments are discussed in <Section 6.2.1.2.3>. 6.2.1.2.2.3 Vent Areas Vent areas are discussed in <Section 6.2.1.2.3>. 6.2.1.2.3 Design Evaluation The computer code COMPARE (Reference 11) was used in all subcompartment analyses, except for the analysis of the reactor annulus. The computer code RELAP4/MOD3 (Reference 12) was used in the analysis of the reactor annulus. Initial conditions, along with nodal volumes, calculated peak pressure differentials and design pressure differentials, are presented by
,
,
,
, and
. Descriptions of break locations are presented in <Section 3.6> and below:
a. Reactor Annulus Breaks were considered as follows:
1. The recirculation suction line break is assumed to occur at the nozzle of the reactor pressure vessel. A flow diverter with a 1 inch gap is constructed around the recirculation line as shown by <Figure 6.2-28>. This limits the amount of fluid discharged from the nozzle into the reactor annulus.
Revision 12 6.2-48 January, 2003
2. The recirculation discharge line break is a guillotine break which occurs within the reactor annulus.
3. The feedwater line break is a guillotine break which occurs in the reactor annulus area.
b. Drywell Head Region The break in the six inch RCIC spray line is at the top of the reactor pressure vessel where the line enters the vessel.
c. Reactor Water Cleanup Rooms All four reactor water cleanup rooms were conservatively analyzed using the blowdown flow for the same break. The inlet to the first regenerative heat exchanger is the assumed rupture point.
d. Steam Tunnel The break used in the steam tunnel analysis is the same as that used for the reactor water cleanup rooms.
e. Bulkhead Plate P Analysis Nodal boundaries are based on actual flow restrictions ensuring that no substantial pressure gradient exists within a node. Nodalization information is as follows:
a. Reactor Annulus The nodalization schemes of the reactor annulus were developed to provide detailed information, especially in the region surrounding the break itself, concerning the spatial pressure variation within the reactor annulus. These nodalization schemes for the Revision 15 6.2-49 October, 2007
recirculation and feedwater line breaks are similar in detail to those used in reactor annulus analyses for other plants. The nodal schematic for the recirculation suction line break, which takes credit for symmetry is provided in <Figure 6.2-29>, where Node 25 is the break node and Node 24 is the drywell. The spatial pressure variation due to the mass and energy release from a recirculation discharge line using the recirculation suction model was also analyzed. The nodal schematic for the feedwater line break is provided in <Figure 6.2-30>, where Node 29 is the break node and Node 50 is the drywell.
b. Drywell Head Region The drywell head region model is a two node model. Node 1 is the head region and Node 2 is the drywell.
c. Reactor Water Cleanup Rooms Four reactor water cleanup rooms are modeled as follows:
1. The heat exchanger room is modeled using three nodes: the heat exchanger room, corridor and containment.
2. The filter demineralizer valve room is modeled using three nodes: the filter demineralizer valve room, corridor and containment.
3. The filter demineralizer room model is a two node model: the filter demineralizer room and containment.
4. The drain valve nest room is modeled using three nodes: the drain valve nest room, corridor and containment.
Revision 12 6.2-50 January, 2003
d. Steam Tunnel The steam tunnel model is a two node model: Node 1 is the steam tunnel, Node 2 is the containment.
e. Bulkhead Plate P Analysis The COMPARE model used for the Bulkhead Plate P Analysis is given in <Figure 6.2-51a>. Control Volumes 1 and 2 are the break nodes and Control Volume 5 models the drywell head region. The nodal descriptions are given in
and the flow path data is given in
. Graphs of pressure differential with respect to time are provided for the subcompartments by the figures indicated:
a. Reactor annulus:
1. Recirculation line breaks, <Figure 6.2-31>, <Figure 6.2-32>,
<Figure 6.2-33>, <Figure 6.2-34>, <Figure 6.2-35>, <Figure 6.2-36>, and <Figure 6.2-37>.
2. Feedwater line break, <Figure 6.2-38>, <Figure 6.2-39>,
<Figure 6.2-40>, <Figure 6.2-41>, <Figure 6.2-42>, <Figure 6.2-43>, <Figure 6.2-44>, and <Figure 6.2-45>.
b. Drywell head region, <Figure 6.2-46>.
c. Reactor water cleanup rooms, <Figure 6.2-47>, <Figure 6.2-48>,
<Figure 6.2-49>, and <Figure 6.2-50>.
d. Steam tunnel, <Figure 6.2-51>.
e. Bulkhead Plate P Analysis, <Figure 6.2-51b> and <Figure 6.2-51c>.
Revision 12 6.2-51 January, 2003 Mass and energy releases used in the analyses are presented in the tables indicated or as stated below. All mass and energy as presented in the following tables is assumed to enter the break node.
a. Reactor annulus:
1. Recirculation suction line break,
.
2. Recirculation discharge line break,
.
3. Feedwater line break,
.
b. Drywell head region: flow rate, 390 lbm/sec; enthalpy, 1,190 Btu/lbm.
c. Reactor water cleanup rooms,
.
d. Steam tunnel inside reactor building. The RWCU line is the source of pipe rupture (main steam lines are guard piped),
.
e. Bulkhead plate P analysis - rupture of a main steam line in the drywell,
.
,
,
,
,
, and
provide flow path information.
a. Reactor Annulus,
and
. The compressible flow model as provided in (Reference 12) was used. Special consideration has been given to the effect of the insulation attached to the biological shield wall following an accident within the reactor annulus. Revision 12 6.2-52 January, 2003 The following assumptions have been used in determining nodal volumes and vent flow areas:
1. The annulus area below the reactor vessel skirt is assumed to remain isolated during the break transient.
2. Air seals which rupture at 15.0 psid separate the reactor annulus and the drywell.
3. Nodal volumes and initial flow area were evaluated, assuming that the insulation remained in place.
4. At the start of the accident all insulation within 120 of the break centerline is assumed to tear away from the biological shield wall and to catch on annulus piping and inservice inspection equipment. A study was made considering three different distribution schemes to represent how the insulation panels might catch on annulus obstructions. They are:
(a) Insulation panels are distributed evenly from 0 to 150 from the break centerline. (b) Insulation panels are distributed evenly from 0 to 120 from the break centerline. (c) Insulation panels are assumed to preferentially catch on obstructions between 30 and 120. Results of this study indicate that the even distribution of insulation panels over the 0-120 range leads to a greater spatial pressure variation within the reactor annulus. Revision 12 6.2-53 January, 2003
5. Insulation panels are assumed not to collapse for purposes of calculating vent area reduction, with the exception of those panels caught on obstructions which border the break node; these panels are assumed to collapse only in the direction of direct flow.
6. Flow blockage which occurs within the boundaries of a node is projected to the surrounding nodal junctions.
b. Drywell head region,
The flow models, as provided in the COMPARE (Reference 11) computer code, have been used. Loss coefficients were calculated using the methods of (Reference 25) adjusted to the flow path minimum area.
c. Reactor water cleanup rooms,
. The flow models, as provided in the COMPARE computer code, have been used. Loss coefficients were calculated using the methods of (Reference 25) adjusted to the flow path minimum area.
d. Steam tunnel,
The flow models, as provided in the COMPARE computer code, have been used. Loss coefficients were calculated using the methods of (Reference 25) adjusted to the flow path minimum area. Revision 12 6.2-54 January, 2003
e. Bulkhead Plate P Analysis,
The flow models, as provided in the COMPARE computer code have been used. Loss coefficients were calculated using the methods of (Reference 25) adjusted to flow path minimum area. Reactor vessel insulation is assumed to be blown away and to block the opening to the drywell head region located in Control Volume No. 1. 6.2.1.3 Mass and Energy Release Analyses for Postulated Loss-of-Coolant Accident This section presents information concerning the transient energy release rates from the reactor primary system to the containment system following a LOCA. Where the emergency core cooling systems enter into the determination of energy released to the containment, the single failure criteria have been applied to maximize the release. 6.2.1.3.1 Mass and Energy Release Data
provides the mass and enthalpy release data for the recirculation line break. Blowdown steam and liquid flow rates approach zero in approximately 376 seconds and do not change significantly during the remainder of the 24-hour period following the accident. <Figure 6.2-52> shows the blowdown flow rates for the recirculation line break. These data were used in the containment pressure-temperature transient analyses discussed in <Section 6.2.1.1.3.3.1>.
provides the mass and enthalpy release data for the main steam line break. Blowdown steam and liquid flow rates approach zero in approximately 360 seconds and do not change significantly during the remainder of the 24-hour period following the accident. <Figure 6.2-53> shows the reactor pressure vessel blowdown flow rates for the main steam Revision 12 6.2-55 January, 2003 line break as a function of time after the postulated rupture. This information was used in the containment response analyses discussed in <Section 6.2.1.1.3.3.2>. 6.2.1.3.2 Energy Sources Reactor coolant system conditions prior to the line break are listed in
and
. Reactor blowdown calculations for containment response analyses are based upon these conditions during a LOCA. The energy released to containment during a LOCA is comprised of the following:
a. Stored energy in the reactor system.
b. Energy generated by fission product decay.
c. Energy from fuel relaxation.
d. Sensible energy stored in reactor structures.
e. Energy being added by the ECCS pumps.
f. Metal-water reaction energy.
All of the above energies, except pump heat energy, are discussed or referenced in this section. The pump heat rate used in evaluating the containment response to the LOCA is selected as an input of 5,267 Btu/sec to the system with all ECCS equipment operating and 3,393 Btu/sec for minimum ECCS equipment operating. Following each postulated accident event, the stored energy in the reactor system and the energy generated by fission product decay is Revision 12 6.2-56 January, 2003 released. The rate of release of core decay heat for the evaluation of the containment response to a LOCA is presented by
and
as a function of time after accident initiation. The analysis at 3729 MWt
used decay heat based on the ANS 5.0 (1973 standard) +20/10 (add 20% for the first 1000 seconds and 10% thereafter). The long-term analysis at 3833 MWt
used the more realistic ANS/ANSI 5.1 (1979 standard) with 2 sigma uncertainty adders. Following a LOCA, the sensible energy stored in the reactor primary system metal is transferred to the recirculating ECCS water, and thus, contributes to suppression pool and containment heatup. <Figure 6.2-54> shows the variation of the sensible heat content of the reactor pressure vessel and internal structures during a main steam line break accident, based upon the temperature transient responses. 6.2.1.3.3 Reactor Blowdown Model Description The reactor primary system blowdown flow rates were evaluated using the model described in (Reference 1). 6.2.1.3.4 Effects of Metal-Water Reaction The containment systems are designed to accommodate the effects of metal-water reactions and other chemical reactions which may occur following a LOCA. The amount of metal water reaction which can be accommodated is consistent with the performance objectives of the ECCS. <Section 6.2.5.3> provides a discussion of the generation of hydrogen within containment by metal-water reaction. In evaluating the containment response, 16,221 Btu/sec of heat from metal-water reaction is included for the first 120 seconds. The containment response is Revision 12 6.2-57 January, 2003 insensitive to the reaction time, even for the extremely conservative case where all the energy is included prior to the occurrence of peak drywell pressure. 6.2.1.3.5 Thermal Hydraulic Data for Reactor Analysis Sufficient data to perform thermodynamic evaluations of the containment have been provided in <Section 6.2.1.1.3.3> and associated tables, in particular
. 6.2.1.4 Mass and Energy Release Analysis for Postulated Secondary System Pipe Ruptures Inside Containment (PWR) This section is not applicable to PNPP. 6.2.1.5 Minimum Containment Pressure Analysis for Performance Capability Studies on Emergency Core Cooling System (PWR) This section is not applicable to PNPP. 6.2.1.6 Testing and Inspection Containment testing and inspection requirements are discussed in <Section 3.8.1>, <Section 3.8.2>, <Section 3.8.3>, and <Section 6.2.6>. No other special tests of either the drywell or containment structure are planned. Testing and inspection of other engineered safety features inside containment that interface with the containment structures are discussed in those sections which address the specific systems. 6.2.1.7 Instrumentation Requirements The containment atmosphere monitoring system provides the operator with precise alarming, indicating and recording of the drywell and containment atmospheric conditions and suppression pool temperature Revision 12 6.2-58 January, 2003 before, during and after a design basis accident. Additional details concerning the containment atmosphere monitoring system are provided in <Section 7.6>. The drywell and containment vacuum relief system continuously monitors the drywell/containment and containment/atmosphere differential pressures and initiates automatic valve actuation as required. Redundant instrumentation is provided. Additional details concerning this system are presented in <Section 7.3>. The combustible gas control system provides redundant hydrogen analyzers to monitor postaccident containment hydrogen concentration. Additional details concerning the hydrogen analyzers are provided in <Section 6.2.5> and <Section 7.3>. The plant and area radiation monitoring system provides indication of containment ventilation exhaust and area radiation levels. Alarms are also provided. Details concerning radiation monitoring are provided in <Section 11.5> and <Section 12.3.4>. 6.2.2 CONTAINMENT HEAT REMOVAL SYSTEM 6.2.2.1 Design Bases The containment heat removal system, consisting of the suppression pool cooling and containment spray systems, is an integral part of the RHR system. The purpose of this system is to prevent excessive containment temperatures and pressures, thus maintaining containment integrity following a LOCA, and to provide a mechanism to remove post-LOCA airborne fission product activity. To fulfill this purpose, the containment heat removal system meets the following safety design bases:
a. The system limits the long term bulk temperature of the suppression pool to 185F without spray operation when considering the energy Revision 12 6.2-59 January, 2003
additions to the containment following a LOCA. These energy additions, as a function of time, are provided in <Section 6.2.1.3>.
b. The single failure criteria applies to the system.
c. The system is designed to safety grade requirements including the capability to perform its function following a safe shutdown earthquake.
d. The system maintains operation during those environmental conditions imposed by the LOCA.
e. Each active component of the system is testable during normal operation of the nuclear power plant.
6.2.2.2 System Design The containment heat removal system is an integral part of the RHR system. Water is drawn from the suppression pool, pumped through one or both pairs of RHR heat exchangers and delivered to the suppression pool or to the containment sprayheader. The return flow penetrates containment through 18 inch lines at Elevation 603-6 which is 10-6 above normal water level. After penetrating containment, the return line descends vertically to Elevation 588-6 where it turns and discharges horizontally into the pool. Physical model testing of the suction and discharge arrangement was performed to assure adequate mixing of the return water with the total suppression pool inventory. The large passive strainer installed in response to <NRC Bulletin 96-03> changed the suction configuration which was used in the physical model testing, the discharge configuration was unchanged. Analysis shows that pool mixing is not adversely affected by the new suction configuration. Because the large passive strainer is located on the floor of the suppression pool, any possible short circuiting of the RHR discharge to Revision 12 6.2-60 January, 2003 its suction is not likely. Additionally, the large passive strainer design has continuous suction capability for the full 360 degrees around the suppression pool. During routine plant operation without significant quantities of debris present in the suppression pool, the majority of flow through the strainer to the RHR pumps will be from the strainer segments nearest the pump suction connection. However, debris buildup on the strainer post-LOCA will result in a more uniform flow distribution through the strainer along the entire length of the strainer (this has been confirmed by test). Spreading the source of suction over the entire strainer surface enhances mixing. Plan and section views are shown on <Figure 6.2-55> and <Figure 6.2-56>. Water from the emergency service water system is pumped through the heat exchanger tube side to exchange heat with the processed water. Two cooling loops are provided, each being mechanically and electrically separate from the other to achieve redundancy. A process and instrumentation diagram is provided in <Section 5.4>. The process diagram, including the process data, is provided in <Section 5.4> for all design operating modes and conditions. All portions of the containment heat removal system are designed to withstand operating loads and loads resulting from natural phenomena. All operating components can be tested during normal plant operation so that reliability can be assured. Construction codes and standards are discussed in <Section 5.4.7>. The containment spray subsystem is started manually or automatically. The LPCI mode is automatically initiated from ECCS signals and the RHR system realigned for containment cooling by the plant operator after the reactor vessel water level has been recovered <Section 6.2.1>. Suppression pool cooling is initiated in loop A or B by manually starting the emergency service water pump, closing the heat exchanger Revision 12 6.2-61 January, 2003 bypass valve, opening the service water valve at the heat exchangers, closing the LPCI injection valve, and opening the pool return valve. If a single failure occurred and the action which the plant operator is taking does not result in system initiation, then the operator will place the other totally redundant system into operation by following the same initiation procedure. If the operator chooses to utilize the containment spray, he must close the LPCI injection valves and open the spray valves. The containment spray mode is also initiated automatically on high containment pressure. Actual spray is delayed for 10 minutes and is initiated then only if LOCA and high drywell pressure signals are present. Automatic initiation is provided to protect the containment in the event of suppression pool bypass leakage as is described in <Section 6.2.1.1.5.4>. If containment pressure is below the high containment pressure setpoint, actuation of the containment spray system can be performed manually from the control room. Preoperational tests are performed to verify individual component operation, individual logic element operation and system operation up to the containment sprayheader. A sample of the nozzles are bench tested for flow rate versus pressure drop to evaluate the original hydraulic calculations. Finally, the headers are tested by air and visually inspected to verify that all nozzles are clear. Refer to <Section 5.4.7.4> for further discussion of preoperational testing. Each ECCS pump takes suction directly from the suppression pool which does not have a sump. To prevent foreign objects in the suppression pool from entering the ECCS flow path, a strainer is located on the ECCS suction lines in the suppression pool. The suction piping strainer from the suppression pool is specified with 3/32 (0.094) inch mesh openings capable of screening all foreign Revision 12 6.2-62 January, 2003 particles which are of sufficient size to clog the RHR pump seal cyclone separators which have 1/8 inch orifices. The HPCS portion of the strainer uses the same mesh opening criteria as does the remainder of the strainer, however, an opening of 0.125 inch is allowed, which is sufficient to protect the HPCS pumps cyclone separator which has a 0.136 inch orifice. The large passive strainer is designed with sufficient strainer surface area to provide very low fluid approach velocities under all postulated debris loading conditions so that in the event the strainer becomes fully loaded (i.e., maximum postulated loading resulting from LOCA-generated and pre-LOCA debris materials), the minimum required NPSH is still provided to the RHR pumps during LPCI and suppression pool cooling modes. At a design flow rate of 7,800 gpm, the large strainer has a maximum pressure drop of 6.25 feet (HPCS) with the strainer fully loaded. The strainer completely circumscribes the suppression pool and is fabricated from stainless steel plate and perforated (3/32 holes) stainless steel plate. The strainer is semi-circular in cross-section with two separate flow channels separated by an open central channel. The three ECCS divisions which connect to the strainer are physically separated through the use of internal divider plates in the flow channels; two divider plates are installed at each divisional interface location. The strainer rests on the floor of the suppression pool and the top of the strainer is approximately 3-2 above the suppression pool floor. <Figure 6.2-83> shows the general layout of the strainer. The mechanism for transport of insulation from the drywell into the containment suppression pool following an accident involves a series of occurrences, as discussed below. The following types of insulation are used for piping and equipment within the containment:
a. Metal-reflective insulation for the reactor pressure vessel.
Revision 22 6.2-63 October, 2021
b. Metal-jacketed fiberglass blanket (NuKon) for all hot piping and equipment. For those portions of hot piping and equipment where system configuration does not permit metal jacketing, only fiberglass blankets are installed.
c. Polyethylene closed cell foam insulation on chilled water piping.
Metal-reflective insulation is installed in sections with overlapping edges and quick release latches with keepers. Metal-jacketed fiberglass blanket insulation is installed in two-foot sections with Velcro fasteners on the longitudinal seam for ease of installation and removal. The blanket jacketing consists of a separate stainless steel sheath combining quick release latches and closure handles. <Regulatory Guide 1.82> (Position 2.3.1.1) states that, consistent with the requirements of <10 CFR 50.46>, debris generation should be calculated for a number of postulated LOCAs of different sizes, locations, and other properties sufficient to provide assurance that the most severe postulated LOCAs are calculated. <Regulatory Guide 1.82> (Position 2.3.1.2) states an acceptable method for determining the shape of the zone of influence (ZOI) of a break is described in <NUREG/CR-6224>. The volume contained within the zone of influence should be used to estimate the amount of debris generated by a postulated break. PNPP utilized NEDO-32686, Utility Resolution Guidance for ECCS Suction Strainer Blockage, <Section 3.2.1.2.3> (method 2) (Reference 34), to determine the size of a spherical ZOI. PNPP selected worst case break configuration based on the latest available information contained in (Reference 34). Specific pipe break locations were not used to identify the most severe zone of influence by a LOCA. Instead, a graphical model of the drywell was used to locate the center of the most severe Revision 12 6.2-64 January, 2003 (largest) spherical zone of influence on the centerline of large bore drywell piping. A number of locations were compared for the greatest volume of insulation affected. The spherical zone size was determined independent of piping location, based on maximum pipe size (main steam piping diameter), and most severe offset and separation. The zone takes no credit for any fraction of debris that is considered non-transportable (i.e., all debris is 100% transportable). (Reference 34) (Section 3.2.1.2.3, method 1) was used to calculate the volume of fibrous insulation available for transport. The ZOI calculation produced a quantity of fiber debris that was less than the installed fibrous insulation. The strainer design is based on the full drywell debris load and, therefore, is unaffected by changes in ZOI methodology, and conservative. The quantity of other LOCA-generated debris (debris resulting from painted surfaces, fibrous, cloth, plastic, or particulate materials within the zone of influence that may produce debris) is based on the recommendations contained in the (Reference 34). The spherical ZOI was used to assess the mass of other drywell debris, and to demonstrate the safety margin available with the strainer design. The debris quantities used in the strainer design are considered very conservative. PNPP has only considered fiber insulation quantities with respect to transportable insulation materials from the drywell. Stainless steel NUKON jacketing and reactor vessel metallic insulating materials and components at PNPP have been considered to be of sufficient density that they would sink to the bottom of the drywell or accumulate within the reactor vessel bioshield wall. Based on the very low approach velocity of the strainer, the design is not sensitive to any volume of reflective metal insulation generated as the result of a LOCA. Hence, the effects of pipe breaks inside the bioshield are bounded by the pipe breaks outside the bioshield which generate significantly greater amounts of fibrous insulation debris. Revision 12 6.2-65 January, 2003 Due to low approach velocities associated with the large, passive strainer, metal tags and metallic insulation materials were assumed to settle in the Suppression Pool. PNPP takes no credit for settling of fiber insulation material, corrosion products/sludge, paint or coating debris, and plastic debris materials at the onset of a LOCA; however, significant debris settling was observed in a test program utilizing a 1/4-scale model of the strainer. The settling observed in the testing program is considered prototypical of the settling which would occur in the suppression pool after chugging and condensation oscillation have ceased. With respect to debris transport, 100% of the drywell fiber insulation is considered to be transported to the suppression pool, without credit for any holdup time in the drywell. Similarly, the other amounts of debris are also assumed to be completely transported to the pool. It is assumed that the hydrodynamic actions during the first few minutes of a LOCA are sufficient to completely mix all debris which enters the pool from the drywell and to fully disperse all pre-existing debris resident in the suppression pool prior to LOCA occurrence. PNPP utilized the methods prescribed in the (Reference 34) and plant specific data to establish the limits for pre-LOCA debris in the suppression pool. Prior to the initiation of suppression pool cooling, and once the suppression pool has settled from the initial hydrodynamic disturbances, the debris will either settle, be drawn to the strainer, or both. Since the 0.02 fps design approach velocity of the strainer is approximately the same as fiber settling velocities, fiber will be drawn to the strainer locally or else settle, with minimal tangential movement of the debris. This is potentially true to an even greater extent with the denser, particulate debris types such as ferrous materials, paint chips, etc. since their settling velocities are higher than fiber. However, these materials are also basically attracted to the strainer because of their dispersion within the fiber debris. Particulate materials which Revision 12 6.2-66 January, 2003 are initially resident in the pool water nearest the strainer may also be expected to be preferentially drawn to the strainer mesh surface in lieu of settling, to be trapped by the fiber material which forms there. The strainer design is such that debris will tend to collect first on the surface near the source of suction. As the debris bed thickness increases, the head loss will tend to increase through that portion of the strainer, and as a result the primary debris accumulation points will tend to migrate along the strainer, i.e., the strainer will be self-regulating with regards to debris accumulation and head loss. This process would continue until all debris has been captured by the strainer or has settled in the pool. If less than the maximum quantity of debris is generated, portions of the strainer may remain uncovered. Therefore, rate of accumulation of debris on the strainer is of no consequence. The large toroidal passive strainer has been designed in accordance with <Regulatory Guide 1.82>, Revision 2. The suction strainer has been designed to preclude the potential for loss of NPSH caused by debris blockage during the period that the ECCS is required to maintain long-term cooling. The large toroidal passive strainer results in a very low approach velocity for water entering the strainer. Debris collected on the strainer surface is not expected to compact significantly (due to the very low approach velocity), resulting in minimal head loss. The testing of a 1/4-scale model of the strainer design confirmed the performance of the strainer and the behavior of the postulated debris bed as a function of time after the postulated LOCA. Because the debris bed will not be significantly compacted, flow will continue to pass through the debris (and the strainer) and thus the overall differential pressure will remain low. Maintaining a low differential pressure will ensure adequate NPSH for the ECCS pumps. Revision 12 6.2-67 January, 2003 A complete DBA analysis of the interaction of the NuKon insulation with the ECCS systems is presented in Owens-Corning Topical Report OCF-1. Subsequent to the installation of the strainer and 1/4-scale testing, additional 1/4 scale testing was performed using a single strainer module, identified as the small-scale test. The small-scale test facility was constructed mainly to respond to questions regarding post-LOCA coating failures. The small-scale tests included similarly conservative post-LOCA debris inventories as the initial 1/4 scale testing, plus significant fractions of drywell and containment primer and top coat, and additional debris. A simple flow model approach was used to correlate the small-scale test results to the initial 1/4-scale test configuration to conservatively bound the full-scale strainer head losses. The chilled water anti-sweat insulation is only located above the floor grating on the wetwell Elevation 620-6. If pieces were to reach the pool below, the pieces would float on the pool surface since the material has negligible water absorption capacity and weighs 2 lbs/ft3. 6.2.2.3 Design Evaluation In the event of the postulated LOCA, the short term energy release from the reactor primary system will be dumped to the suppression pool. This will cause a pool temperature rise of approximately 45F. Subsequent to the accident, fission product decay heat will result in a continuing energy input to the pool. The containment cooling system will remove this energy which is released into the primary containment system, thus resulting in acceptable suppression pool temperatures and containment pressures. To evaluate the adequacy of the RHR system, the following sequence of events is assumed to occur: Revision 22 6.2-68 October, 2021
a. The reactor initially operating at 104.2 percent of original rated power (3729 MWt), a LOCA occurs.
b. A loss of offsite power occurs and one emergency diesel fails to start and remains out-of-service during the entire transient. This is the worst single failure.
c. Only three ECCS pumps are activated and operated as a result of Item b., above.
Revision 22 6.2-68a October, 2021
d. After 30 minutes the plant operators activate one RHR heat exchanger in order to start containment heat removal. Once containment cooling has been established, no further operator actions are required.
NPSH requirements of <Regulatory Guide 1.1> are found in <Section 6.3.2.2>. 6.2.2.3.1 Summary of Containment Heat Removal Analysis When calculating the long term, post-LOCA pool temperature transient, it is assumed that the initial suppression pool temperature and the emergency service water temperature are at their maximum values. This assumption maximizes the heat sink temperature to which the containment heat is rejected and thus maximizes the containment temperature. In addition, the RHR heat exchanger is assumed to be in a fouled condition at the time the accident occurs. This conservatively minimizes the heat exchanger heat removal capacity. The resultant suppression pool temperature transient is described in <Section 6.2.1.1.3.3.1> and is shown in <Figure 6.2-7> and <Figure 6.2-8>. Even with the degraded conditions outlined above, the maximum temperature is only 182.7F, which is below the design limit specified in <Section 6.2.2.1>. It should be noted that when evaluating this long term suppression pool transient, all heat sources in the containment are considered with no credit taken for any heat losses other than through the RHR heat exchanger. These heat sources are discussed in <Section 6.2.1.3>. <Figure 6.2-9> shows the actual heat removal rate of the RHR heat exchanger. The conservative evaluation procedure described above clearly demonstrates that the RHR system in the suppression pool cooling mode limits the post-LOCA containment temperature transient. Revision 13 6.2-69 December, 2003 6.2.2.4 Tests and Inspections The preoperational test program of the containment cooling system is described in <Section 6.2.2.2>. Preoperational testing of the RHR system is discussed in <Section 5.4.7.4>. 6.2.2.5 Instrumentation Requirements The details of the instrumentation are provided in <Section 7.3>. The suppression pool cooling mode of the RHR system is manually initiated from the control room. 6.2.3 SECONDARY CONTAINMENT FUNCTIONAL DESIGN 6.2.3.1 Design Bases The secondary containment system includes the shield building and the annulus exhaust gas treatment system (AEGTS). Details of the AEGTS are given in <Section 6.5.3>. The following are the design bases for the shield building:
a. The shield building is designed to collect the fission product leakage from the primary containment during and following a postulated design basis LOCA and delay it until it can be released to the environs after processing through the annulus exhaust gas treatment system such that the resultant offsite doses are less than the values set forth in <10 CFR 50.67>.
b. The shield building is designed to withstand the peak transient pressures and temperatures which could occur due to the postulated design basis accident.
Revision 19 6.2-70 October, 2015
c. The shield building is designed as a Seismic Category I structure.
d. The shield building is maintained at a slight negative pressure relative to atmospheric pressure so any leakage post-LOCA through the shield building or the containment vessel is into this space.
e. The design loads on the shield building are discussed in
<Section 3.8.1>.
f. The leak tightness of the shield building is continually verified by maintaining the annulus at a minimum vacuum of 0.66 inch water gauge. This constitutes a continuous testing program. Inspection of the secondary containment structure will not be necessary as long as a vacuum can be maintained through normal operation of plant equipment.
6.2.3.2 System Design The shield building is a cylindrical reinforced concrete structure with a spherical dome enclosing the containment vessel. The internal diameter is 130 feet and the outside diameter is 136 feet. There is an annulus width of five feet between the containment vessel and the inside of the shield building. <Figure 1.2-3>, <Figure 1.2-4>, <Figure 1.2-5>, <Figure 1.2-6>, <Figure 1.2-7>, <Figure 1.2-8>, <Figure 1.2-9>, <Figure 1.2-10>, <Figure 1.2-11>, <Figure 1.2-12>, and <Figure 1.2-13> show plan and elevation views of the shield building. There are two doors allowing access to the annulus area, both of which are normally locked. They are provided with position indicators and alarms which annunciate in the control room. A tabulation of the design and performance data for the shield building is provided in
. Revision 20 6.2-71 October, 2017 The performance objective of the shield building is to collect and retain any fission product leakage from the containment vessel during and following a design basis accident and, in conjunction with the annulus exhaust gas treatment system, process and release the fission products to the environs in a controlled manner. This release is accomplished such that the resultant doses to the general public and the control room are within the values given in <10 CFR 50.67>. The principal construction codes, standards and guides used in the design of the shield building are described in <Section 3.8.1>. In order to minimize the amount of radioactive material that leaks to the secondary containment following a design basis accident, primary containment penetrations are provided with redundant, ASME Code,Section III, Class 2, Seismic Category I isolation valves, one inside of the primary containment and one outside of the shield building, or some other acceptable configuration such as a closed system outside of containment. The piping out to the outboard containment isolation valve or in the closed system is also ASME Code,Section III, Class 2. This isolation valve arrangement functions to minimize through-line leakage, which is limited by leak rate testing as described below. The containment isolation system is discussed in more detail in <Section 6.2.4>. The containment and reactor vessel isolation control system is discussed in more detail in <Section 7.3.1>. The containment boundary and all penetrations except for penetrations with guard pipes terminate in the annulus. Therefore, containment shell leakage and penetration leakage are considered to be totally directed to the annulus. The sources listed in
are a summary of potential leakage paths that could bypass the AEGTS. The containment design basis accident leakage is 0.2 percent by weight of the contained atmosphere in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The maximum test leakage rate permitted from the sources listed in
is 10.08 percent of the total Revision 21 6.2-72 October, 2019 containment leakage. This value will be the technical specification commitment for leakage bypassing the AEGTS as listed in the Technical Specifications. In order to verify that the total amount of potential bypass leakage will be within this limit, a testing and evaluation program will be conducted on isolation valves, personnel airlocks and guard pipes as described in <Section 6.2.4.3.1>. The expected leakage rates per valve have been calculated and are shown on
for the potential bypass leakage paths. In these calculations, it was assumed that the onsite leakage limit per valve will be the same as the shop test limits given in the valve specifications. The air-filled lines penetrating primary containment that are not entirely contained in the secondary containment, and are potential bypass leakage paths, are identified in
. The air supply lines to the ADSaccumulators are not considered bypass leakage paths since they are safety-related lines that remain pressurized post-LOCA (at a pressure exceeding containment vessel design pressure). 6.2.3.3 Design Evaluation All high energy lines which penetrate the containment wall and the shield wall are protected by guard pipes, with the exception of the control rod drive hydraulic supply
. The CRD supply is a 2-1/2 inch water line with a normal operating pressure of 1,850 psi. The justifying logic allowing postulation of pipe rupture locations in other high energy lines penetrating the containment which require guard pipe protection does not apply to this line. Guard pipes are used where the energy release rate of the postulated accident is such that the resulting pressurization must be confined to the drywell rather than Revision 21 6.2-73 October, 2019 allowed to pressurize the containment volume directly. The energy release rate of an 1,850 psi fluid at a maximum of 140F does not require that it be diverted from either the containment volume or from the annulus volume. Release of such a fluid within the containment volume will not prevent the AEGTS from performing its function, since pressurization of the volume does not result. In the case of high energy lines whose postulated rupture would jeopardize containment design pressure capacity, the pipe break location criteria in MEB 3-1 were suspended and additional breaks postulated which could pose a hazard. Since the consequences of a 2-1/2 inch CRD line rupture are not significant with respect to hazard, the criteria of MEB 3-1 apply and no rupture is postulated to occur within the penetration. Due to line size being under 4 inches nominal, no longitudinal splits are considered to occur, only circumferential ruptures. The postulation of a rupture in the 2-1/2 inch line at either end of the penetration will not jeopardize the integrity of the penetration. A break inside the containment structure will only load the penetration axially. Any break outside of the shield building will not load the penetration at all since no flow issues from the containment side of such a rupture, but from the pump side only. An analysis of the pressure response profile in the shield buildingannulus following the design basis was performed using a modified version of the CONTEMPT-LT (Reference 5) computer code. The following methods and assumptions were used in calculating the pressure response:
a. Annulus design parameters given in
. Revision 12 6.2-74 January, 2003
b. During a LOCA, the containment vessel will expand due to the pressure and temperature change within containment. It is included in the analysis by assuming that the volume expansion takes place as a function of Pressure and Temperature as shown in
<Figure 6.2-59a> and <Figure 6.2-59b>.
c. The annulus exhaust fan is assumed to purge at a rate of 2,000 cfm to the environment.
d. The containment vessel and shield building were the only heat conducting structures considered in the analysis. Conservative values are summarized as follows:
Surface Area Thickness Description Material _ (ft2) _ _ (ft) _ Containment Vessel Carbon Steel 74,912 0.125 Shield Building Concrete 74,912(1) 3.00
1. The surface area of the containment vessel and shield building are assumed to be the same in the computer analysis. The increased diameter of the annulus and concrete surface area of the containment fix at the annulus base are not included as this is conservative.
e. The total heat transfer coefficient, ht, between the containment atmosphere and the steel containment vessel is given by:
ht = hc + hr Revision 15 6.2-75 October, 2007 Where: hc = 0.3 (T)0.25, as given by (Reference 13). hc = Convective film coefficient, Btu/hr-ft2-Fabsolute T = Containment atmosphere temperature - initial containment vessel temperature, F. The containment temperature used is given by (Reference 26). The steel vessel temperature is assumed to be 90F. The actual T used is given in
. T14 T24 hr 1 2 S T1 T2 Where: hr = Radiation coefficient, Btu/hr-ft2-Fabsolute 1 = Emissivity of steel = 0.7 2 = Emissivity of air = 1.0 = Stefan-Boltzmann constant, 0.1714 x 10-8 Btu/hr-ft2-Fabsolute T1 = Higher temperature, Fabsolute T2 = Lower temperature, Fabsolute S = Shape factor = 1.0 The radiation coefficients are given in
and assume the same relative temperatures used in calculating the convective film coefficient. Revision 15 6.2-76 October, 2007 The total heat transfer coefficients as a function of time between the containment atmosphere and the steel containment vessel are listed in
. The total heat transfer coefficient for the steel vessel to the annulus atmosphere and for the annulus atmosphere to the shield building is taken to be 1.2 Btu/hr-ft2-Fabsolute.
f. A schematic diagram of the model input into CONTEMPT is presented in <Figure 6.2-57>.
The results of the annulus pressure response are presented in <Figure 6.2-58>. As shown on this figure the annulus exhaust fans are adequate to maintain the annulus pressure below atmospheric pressure following a DBA-LOCA. 6.2.3.4 Tests and Inspections The program for test and inspection of the containment isolation system is described in detail in <Section 6.2.4> and <Section 6.2.6>. The program for the annulus exhaust gas treatment system is described in <Section 6.5.3>. 6.2.3.5 Instrumentation Requirements Design details and logic of the instrumentation for the AEGTS are given in <Section 7.3.1>. Revision 15 6.2-77 October, 2007 6.2.4 CONTAINMENT ISOLATION SYSTEM 6.2.4.1 Design Bases The design objective for the containment isolation systems is to allow normal or emergency passage of fluids through the containment boundary while preserving the ability of the boundary to prevent or limit the escape of fission products that may result from postulated accidents so that site boundary dose guidelines specified by <10 CFR 50.67> are not exceeded. This objective is achieved by provisions for automatic isolation of appropriate lines that penetrate the containment boundary. The containment isolation systems are automatically actuated with input from the following signals:
a. Low reactor pressure vessel water level (3 setpoints).
b. High drywell pressure.
c. High main steam line tunnel high ambient or differential temperature.
d. Main steam line high area temperature, turbine building.
e. (Deleted)
f. High main steam line flow.
g. Low main steam line pressure at turbine inlet.
h. High radiation in containment and drywell purge exhaust.
Revision 19 6.2-78 October, 2015
i. High reactor water cleanup system ambient or differential temperature.
j. High temperature at outlet of reactor water cleanup system non-regenerative heat exchanger.
k. High differential flow in reactor water cleanup system.
l. Low line pressure in the steam supply line to the reactor core isolation cooling system.
m. High steam flow in steam line to reactor core isolation cooling turbines.
n. High residual heat removal system ambient or differential temperature.
o. High reactor core isolation cooling system ambient.
p. High pressure at the reactor core isolation cooling turbine exhaust diaphragm.
q. High steam flow in the steam supply line to the reactor core isolation cooling system.
r. High reactor vessel pressure (one signal for RHR valves).
s. Low main condenser vacuum.
t. Containment to atmosphere differential pressure greater than 0.0 psid.
u. Standby liquid control system activated.
Revision 14 6.2-79 October, 2005
v. Closure of reactor core isolation cooling turbine trip and steam shutoff valves.
w. High drywell atmospheric radiation.
x. (Deleted)
y. (Deleted)
z. (Deleted) aa. (Deleted) bb. Containment spray initiated.
cc. High reactor pressure vessel water level. dd. Injection flow rate above setpoint (minimum flow valve control) for low and high pressure core sprays, residual heat removal and reactor core isolation cooling systems. ee. Discharge pressure below setpoint (minimum flow valve control) for high pressure core spray system. The containment isolation systems can also be manually actuated from other locations as specified in
. After initiation of containment isolation, either automatically or manually, the function goes to completion. Upon receipt of signals indicating low water level in the reactor vessel or high drywell pressure, containment isolation valves in systems not required for emergency shutdown are closed except for the main steam Revision 14 6.2-80 October, 2005 isolation, main steam line drain, and reactor water cleanup system isolation valves which do not close on high drywell pressure. These signals also activate systems associated with emergency core cooling. Those fluid system penetrations that support systems not required for emergency operation are closed by the containment isolation systems. Fluid system penetrations that support engineered safety feature (ESF) systems have remotely operated isolation valves that may be closed from the control room if required. The isolation criteria for determination of quantity, type and location of containment isolation valves for a particular system generally conform to the requirements of General Design Criteria (GDC) 54, 55, 56, and 57, and comply with the recommendations of <Regulatory Guide 1.11>. Redundancy and physical separation are required in the electrical and mechanical design of the systems to ensure that no single failure in the containment isolation systems prevents performance of the intended functions. Protection of system components from missiles and from the effects of postulated high and moderate energy line breaks is also a design consideration. Instrument lines that penetrate the containment boundary conform to the requirements of GDC 55 and 56, and comply with the recommendations of <Regulatory Guide 1.11>. Containment isolation valves and associated piping and penetrations satisfy the requirements of the ASME Code,Section III, Class 1 or Class 2, as applicable. These components are also Seismic Category I. Classification of systems and equipment is presented in
. Upon loss of instrument air, air operated containment isolation valves fail in the position required for containment isolation. Closure times and leak tightness of containment isolation valves are sufficient to Revision 14 6.2-81 October, 2005 ensure that the site boundary dose guidelines specified by <10 CFR 50.67> are not exceeded following a postulated accident. The B Train of the safety-related instrument air system provides postaccident makeup to the outboard MSIVaccumulators to assure leak tightness of the outboard MSIVs. A capability for rapid closure of all lines provides a containment barrier within the lines that is sufficient to maintain leakage within permissible limits. 6.2.4.2 System Design 6.2.4.2.1 General A summary of containment isolation valves is presented in
. Each valve is described, including penetration number, applicable GDC or regulatory guide, fluid system, fluid, line size, valve arrangement, location, valve type, actuation mode, valve position, initiating signal, power source, etc. <Figure 6.2-60> illustrates the various containment isolation valve arrangements. Justification for containment isolation provisions which differ from the requirements of GDCs is presented in <Section 6.2.4.2.2>. Containment isolation valve closure times
are established to prevent radiological effects from exceeding the guidelines specified by <10 CFR 50.67>. A discussion of valve closure times, for those valves through which a direct path from containment to the environment could exist, is provided in <Chapter 15>. Containment isolation for such lines is accomplished in accordance with NRC Branch Technical Position CSB 6-4, Containment Purging During Normal Plant Operations. Additional discussion of Branch Technical Position CSB 6-4 is presented in <Section 6.2.4.2.3>. Revision 19 6.2-82 October, 2015 Instrument lines which penetrate containment comply with the recommendations of <Regulatory Guide 1.11>. A power operated remotely controlled isolation valve is provided just outside containment. Instrument lines which penetrate both containment and drywell have a similar arrangement. A power operated isolation valve is provided just outside containment. Details of these arrangements are illustrated on <Figure 6.2-60>. Inside containment each instrument line is either sized to adequately restrict flow or is provided with a 0.25 inch orifice as close to the beginning of the line as possible. In some cases a power operated valve is provided inside containment in lieu of a flow restriction. Quality standards for containment isolation systems follow the recommendations of <Regulatory Guide 1.26>. Additional discussion of <Regulatory Guide 1.26> is presented within <Section 3.2.2>. Seismic classification is in accordance with the recommendations of <Regulatory Guide 1.29>. Additional discussion of <Regulatory Guide 1.29> is presented in <Section 3.2.1>.
addresses classification of specific systems and equipment. Containment isolation valves, actuators and controls are protected against damage from missiles, jet impingement and pipe whip. Potential sources of missiles and jet forces and locations of postulated pipe breaks are evaluated. Where potential hazards exist, protection is provided by physical separation, missile or jet shields, etc. These valves are located either inside containment, inside the intermediate building or inside the auxiliary building. Both of these structures are designed to satisfy Seismic Category I requirements and the turbine missile design criteria stated in <Section 3.5>. To prevent debris from entering lines and obstructing valve closure, screens are provided on the open ends of lines through which a direct path from containment to the environment could exist. Revision 14 6.2-83 October, 2005 Isolation valves are designed to be operable under the most adverse environmental conditions, such as maximum differential pressures, extreme seismic occurrences, steam laden atmosphere, high temperature, and high relative humidity. Normal and accident environmental conditions, for which the containment isolation valves and associated electrical equipment are designed, are discussed in <Section 3.11>. Also, where necessary, a dynamic system analysis to determine the effects of rapid valve closure under operating conditions, is required by the design specifications for piping systems associated with containment isolation valves. The valve operability assurance program for active, safety-related valves is discussed in <Section 3.9>. Electrical redundancy is provided for power operated valves. Power for the operation of two isolation valves in a line (inside and outside containment) is supplied from two redundant, independent power sources without cross ties. In general, isolation valves outside containment are powered from the Division 1 power supply while isolation valves within containment are powered from the Division 2 power supply. Both Division 1 and Division 2 valves are generally powered from ac power sources. Loss of power to each motor-operated valve is annunciated. Provisions for detecting leakage from remote-manually controlled systems are discussed in <Section 5.2.5>. Detection of leakage from containment is discussed in <Section 6.2.6>. The fraction of the total containment leakage following a design basis accident/LOCA that could bypass the containment annulus exhaust gas treatment system is limited to the leakage from sources which constitute open systems or nonsafety-related systems. Safety class systems which are open systems are considered. For example, for determination of potential bypass leakage pathways it is assumed, for nonsafety-related systems (other than the feedwater lines, for approximately one hour following a LOCA), that the only portion of such a system remaining Revision 14 6.2-84 October, 2005 intact would be the containment isolation valves and the piping between these valves. Additional leakage sources considered are the containment penetrations with guard pipes. The containment boundary is surrounded by the annulus. Containment penetrations, except those with guard pipes, terminate in the annulus. Therefore, containment shell leakage and penetration leakage are totally directed into the annulus. Containment design basis accident leakage is 0.2 percent, by weight, of the contained atmosphere in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The maximum allowable combined test leakage rate from potential sources listed in
is 10.08 percent of the total containment leakage. This value is the technical specification commitment for leakage bypassing the containment annulus exhaust gas treatment system. To verify that the total amount of potential bypass leakage is within the established limit, the following test and evaluation program will be conducted in accordance with the Containment Leakage Rate Testing Program:
a. Isolation Valves Since it is assumed for determination of potential bypass leakage pathways that nonsafety-related systems outside the containment isolation valves will not remain intact, (other than the feedwater lines, for approximately one hour following a LOCA), containment atmosphere must terminate at the outer containment isolation valve seat. The same effect is possible for open ended safety class systems. To assure that this potential source of bypass leakage is checked, isolation valves listed in
are included in the periodic Type C test program discussed in <Section 6.2.6>. Revision 21 6.2-85 October, 2019 The test method is also described within this section. By measuring the time related pressure decay or by directly measuring the leakage flow rate, each valve is quantitatively evaluated for leak tightness.
b. Guard Pipes The basic configuration for guard pipes is to have one end open to the drywell and the other end welded closed to the process pipe outside the shield building. The primary potential leakage path is at the outer end closure welds. Secondary leakage paths may exist through discontinuities in the guard pipe material. Leakage testing is performed concurrently with the initial containment integrated leak rate test. Guard pipe leakage is detected by application of a soap bubble solution to 100 percent of the exposed guard pipe surface outside the shield building, including all weld connections. Any leak detected as a result of bubble formation will be eliminated (i.e., no detectable leakage) by performing the appropriate repair procedure. This test will be repeated each time a Type A test (containment integrated leak rate test) is performed <Section 6.2.6>.
c. Personnel Air Locks Containment atmosphere could potentially bypass the annulus exhaust gas treatment system by leaking past the double seals on each door of the personnel airlocks. The personnel air lock leakage control system has been designed to eliminate this potential bypass leakage past the double seals on the outer doors <Section 6.2.6>. In addition, a test of the leak tightness of the volume between the double seals is performed frequently. By using the pressure decay method or leakage flow rate method, the actual leakage rate through the seals can be determined.
Revision 14 6.2-86 October, 2005 Results of Type B and Type C testing in accordance with the Containment Leakage Rate Testing Program are used to determine whether the 10.08 percent limit has been met. Tests or analyses are also performed to demonstrate that the purge isolation valves function as specified. These are as follows:
a. Necessary prototype tests and/or analyses to satisfy the recommendations of <Regulatory Guide 1.48> relative to demonstrating the operability of the equipment under the specified loading combination.
b. Hydrostatic test of the valve body in accordance with the ASME Code,Section III.
c. Leak test of the valve assembly at maximum operating pressure in accordance with applicable requirements of <10 CFR 50, Appendix J>
(Option B).
d. Valve operator performance test for closure speed under maximum operating pressure.
Systems penetrating containment can be isolated by remote-manual action as indicated in
. Discussions of individual system isolations are presented in the sections which address the specific systems. In the event of valve power failure, most motor-operated containment isolation valves remain as is. Air operated valves close upon loss of air. Main steam line isolation valves are spring loaded, pneumatic, piston operated globe valves, designed to fail closed upon loss of air pressure or loss of power to the solenoid operated pilot valves. Each main steam Revision 21 6.2-87 October, 2019 isolation valve is served by two independent pilot valves, each of which is powered from an independent source. In addition, each main steam isolation valve is equipped with an air accumulator to assist in valve closure in the event of loss of air, loss of electrical power to the pilot valves and/or failure of the valve spring. The separate and independent action of either air pressure or spring force is capable of closing a main steam isolation valve. Pneumatic and motor-operated containment isolation valves have status lights on the control switch in the control room to indicate open and closed position. A subset of these valves also have position indicator lights on the control room isolation status panel. Position of manual isolation valves is maintained by means of locking devices and/or administrative controls. The containment isolation valves are designed in accordance with the requirements of Section III of the ASME Code. 6.2.4.2.2 Justification of Differences from General Design Criteria The GDCs were not established specifically for BWR plants; rather, these criteria are intended to guide the design of all water cooled nuclear power plants. As a result, the GDCs are generic in nature and subject to a variety of interpretations. For this reason some cases exist with no one-to-one correspondence between the applicability of an individual GDC and plant design. In such cases, GE has developed a design that meets the intent of the criteria. The isolation criteria within the GDCs contain clauses, such as, unless it can be demonstrated ... on some other defined bases, which allows for an alternate design with reliability and performance capabilities that reflect the importance to safety of isolating the piping systems. Such alternates are described in <Section 6.2.4.2.2.1>, <Section 6.2.4.2.2.2>, and <Section 6.2.4.2.2.3>. The final measure by Revision 14 6.2-88 October, 2005 which GE is assured that the BWR design is in agreement with the GDCs is receipt of the Advisory Committee on Reactor Safeguards (ACRS) letters permitting construction and operation of previous plants with comparable valving arrangements. 6.2.4.2.2.1 Justification with Respect to General Design Criterion 55 The reactor coolant pressure boundary, as defined in <10 CFR 50.2(v)>, consists of the following: reactor pressure vessel; pressure retaining appurtenances attached to the vessel; valves, and pipes which extend from the reactor pressure vessel to, and including, the outermost isolation valve. The lines of the reactor coolant pressure boundary which penetrate containment are capable of isolating the containment, thereby precluding any significant release of radioactivity. Similarly, for lines which do not penetrate containment, but which do comprise a portion of the reactor coolant pressure boundary, the design ensures that isolation of the reactor coolant pressure boundary can be achieved. Items a, b and c, below, address influent lines, effluent lines and conclusions, respectively, with regard to GDC 55.
a. Influent Lines Influent lines which penetrate containment and the drywell directly to the reactor coolant pressure boundary are equipped with at least two isolation valves. One valve is inside the drywell; the second is as close as possible to the external side of containment. These isolation valves protect the environment. Where needed, protection of the containment in the event of pipe rupture outside the drywell but within containment is further ensured by extension of the drywell by use of guard pipes. These guard pipes, together with the isolation valves, assure protection in the event of an active failure between drywell and containment.
lists Revision 14 6.2-89 October, 2005 those influent lines that comprise part of the reactor coolant pressure boundary and penetrate containment. The purpose of this table is to summarize the design of each line with respect to the requirements of GDC 55. Items 1 through 8, below, demonstrate that, although a word-for-word comparison with GDC 55 is not always practical, it is possible to demonstrate adequate isolation provisions on some other defined basis.
1. Feedwater Penetrations (P121 and P414)
Feedwater lines are part of the reactor coolant pressure boundary since they penetrate both the containment and drywell and connect to the reactor pressure vessel. Each line includes three isolation valves and is enclosed in a guard pipe. The isolation valve inside the drywell is a control closure anti-water hammer check valve. The first isolation valve outside containment is also a control closure check valve and is located as close as possible to the outside containment wall. The outermost valve is a motor-operated gate valve. The two control closure check valves are designed and tested to close with no reverse flow. Extension of the drywell by means of the guard pipe protects the containment from overpressurization in the event of a feedwater line break between the drywell and containment walls. The internal design temperature and pressure for the guard pipes which enclose the feedwater lines are the same as the design values specified for the enclosed feedwater lines. Should a break occur in a feedwater line, the control closure check valves prevent significant loss of reactor coolant inventory and provide immediate isolation. These check valves are tested in accordance with the Revision 21 6.2-90 October, 2019 Inservice Testing Program, to verify this closure function. The outermost motor-operated valve does not close automatically upon occurrence of a protection system signal since, during a LOCA accident, maintenance of reactor coolant makeup from all sources, including nonsafety sources, is desirable. This valve, however, can be remotely closed from the control room to provide long term, high integrity leakage protection when, in the judgment of the operator, continued makeup from the feedwater system is no longer necessary. Power to these motor-operated valves can be provided from an alternate division under administrative controls, if necessary, following a LOCA. In addition, after feedwater flow terminates, the operator will initiate the feedwater leakage control system <Section 6.9> to provide a positive water seal on the seat, stem and bonnet of the motor-operated valve in each line. The check valves, coupled with the single motor-operated high integrity leakage protection gate valve on each line, provides an acceptable configuration for the feedwater lines. A branch line connects to the feedwater line outboard of the second feedwatercheck valve, which is outboard of the containment. This branch line provides the pathway for RWCU water and RHRshutdown cooling water to return to the reactor vessel. For the RHRshutdown cooling return line, a safety-related globe valve is treated as a high integrity containment isolation valve, similar to the feedwater gate valves. The RHR system outboard of the globe valve is also treated as a closed system outside of containment, to control any leakage. For the RWCU return line, the piping outboard of the RWCU branch line check valveleads directly back to containment penetration P132, and is ASME Code Class 2, Seismic Category I, protected from pipe whip, missiles and jet forces, and analyzed for break exclusion. This line is also Revision 14 6.2-91 October, 2005 tested like a closed system outside of containment, i.e., per the Primary Coolant Sources Outside Containment Program (see
for testing details on containment penetrations). The design of these branch lines also provides an acceptable configuration.
2. High Pressure Core Spray Line (P410)
The high pressure core spray line penetrates both the containment and the drywell and connects to the reactor pressure vessel. Isolation is provided by a hydraulically testable check valve inside the drywell and a motor-operated gate valve as close as possible to the outside of the containment wall. This gate valve maintains long term leakage control. Position indication for the hydraulically testable check valve is provided in the control room. The gate valve is automatically and remote-manually operated. A guard pipe is not necessary since the high pressure core spray fluid is at an energy level during system operation that containment overpressurization cannot result should the line break between the containment and the drywell.
3. Low Pressure Core Spray and Low Pressure Coolant Injection Lines (P112, P113, P412, and P411)
Isolation of the low pressure core spray and low pressure coolant injection system lines is accomplished by use of a hydraulically testable check valve and a motor-operated gate valve. The check valve is located as close as possible to the reactor vessel and is normally closed. This valve protects against containment overpressurization in the event of a line break between the check valve and the containment wall by preventing high energy reactor coolant from entering containment. The gate valves for the low pressure core spray and low pressure coolant injection line C are located outside Revision 19 6.2-92 October, 2015 containment and are automatically and remote-manually operated and normally closed. The gate valves for the low pressure coolant injection lines A and B are inside containment and function similarly. All gate valves are automatically opened at the appropriate time to ensure that acceptable fuel design limits are not exceeded during a LOCA. A guard pipe is not necessary since the system fluid during operation is at such a low energy level to preclude the possibility of containment overpressurization should a break occur.
4. Control Rod Drive System Lines (P204)
The control rod drive system, located between the reactor pressure vessel and containment, includes two types of influent lines: the supply line that penetrates containment, and the insert and withdraw lines that penetrate the drywell. Isolation of the supply line is accomplished by a check valve inside containment and a remote-manually actuated motor-operated block valve as close as possible to the outside of the containment wall. The insert and withdraw lines are not part of the reactor coolant pressure boundary since these lines do not communicate directly to reactor coolant. The basis upon which these lines are designed is commensurate with the importance to safety of maintaining the pressure integrity of these lines. The classification of these lines is Quality Group B and they are designed in accordance with the ASME Code,Section III, Class 2. In the design of the control rod drive system, it has been accepted practice to omit automatic valves for isolation purposes since inclusion of such a valve would introduce a Revision 19 6.2-93 October, 2015 possible failure mechanism into the shutdown (scram) function. Manual shutoff valves are provided for isolation. In the event of a break in these lines, the manual valves provide isolation capability. In addition, a ball check valve in the control rod drive flange housing automatically seals the insert line in the event of a break. Containment overpressurization will not result from a line break in containment since these lines contain small volumes of fluids, resulting in relatively small blowdown masses. As shown in <Figure 6.2-60 (1)>, Arrangement No. 4, the recirculation pump seal water supply line is connected to the control rod drive system downstream of the inboard containment isolation valve and is provided with check valve isolation both inside and outside the drywell.
5. Residual Heat Removal Head Spray and Reactor Core Isolation Cooling Lines (P123)
The residual heat removal head spray and reactor core isolation cooling lines join outside containment to form a common line which penetrates both the containment and the drywell and connects to the reactor pressure vessel. A hydraulically testable check valve is provided inside the drywell as close as possible to the reactor pressure vessel. Two valves, a check valve and a remote-manually actuated, motor-operated valve, are located outside containment in each line. The line is also enclosed in a guard pipe. The hydraulically testable check valve inside the drywell is normally closed. The check valve(s) outside containment ensure immediate containment isolation in the event of a line break. The motor-operated valve in each line is remote-manually actuated to provide long term leakage control. Revision 19 6.2-94 October, 2015 The guard pipe provides protection against containment overpressurization in the event of a line break between the drywell and containment walls. Should the check valve inside the drywell fail coincident with a line break, the guard pipe would direct the released fluid into the drywell. Position indication lights are provided in the control room for the hydraulically testable check valves inside the drywell.
6. Standby Liquid Control Line (NA)
The standby liquid control system is located between the containment and the drywell. The standby liquid control line penetrates the drywell and connects to the reactor pressure vessel. Isolation is provided by a check valve inside the drywell and a check valve and explosive valve outside the drywell. The explosive valve provides an absolute seal for long term leakage control, as well as preventing leakage of boron solution into the reactor pressure vessel during normal reactor operation. Since the standby liquid control line is normally an isolated, nonflowing line, rupture is extremely improbable. However, should a break occur subsequent to actuation of the explosive valve, the check valves ensure isolation.
7. Residual Heat Removal Shutdown Cooling Return Lines (P121/P112 and P414/P410)
The residual heat removalshutdown cooling return lines discharge into the feedwater line between the control closure check valve and the motor-operated gate valve outside of containment. A check valve and a normally closed, Revision 20 6.2-95 October, 2017 motor-operated, remote-manually actuated globe valve provide for isolation of the residual heat removalshutdown cooling return lines. See item 1 above for additional discussion.
8. Reactor Water Cleanup System Line (P419/P432)
The discharge line from the reactor water cleanup pumps penetrates containment and serves the reactor water cleanup regenerative heat exchangers inside containment. Automatically actuated motor-operated gate valves, one inside, one outside containment, provide for isolation.
b. Effluent Lines Effluent lines that form part of the reactor coolant pressure boundary and penetrate containment and/or the drywell are equipped with at least two isolation valves. One valve is inside the drywell, the other outside, but as close as possible to the containment. Where needed, the containment is protected, in the event of a pipe rupture outside of the drywell but inside containment, by guard pipes which enclose the process lines, forming an extension of the drywell. This combination of isolation valves and guard pipes assures protection in the event of a failure between drywell and containment walls.
lists those effluent lines that comprise part of the reactor coolant pressure boundary and that penetrate containment and/or the drywell. Items 1 through 4, below, address specifics of these lines.
1. Steam Lines (P124/P116, P416/P414, P122/P115, P415/P415, P422, and P423)
Steam lines include main steam, main steam drain, and reactor core isolation cooling steam lines. Revision 20 6.2-96 October, 2017 The main steam lines from the reactor pressure vessel to the turbine penetrate both drywell and containment. Main steam line drains (one for each main steam line) in the drywell are headered together to form one line which penetrates both drywell and containment. Isolation for the main steam lines and main steam drain line is provided by automatically actuated block valves, one inside the drywell and one outside containment. The steam supply line for the reactor core isolation cooling turbine branches from the main steam line inside the drywell. Isolation for this line is provided by one normally open gate valve and one normally closed globe valve inside the drywell, and one normally open gate valve outside containment. These motor-operated valves are capable of automatic and remote-manual actuation. Use of guard pipes to enclose these steam lines prevents containment overpressurization in the event of line break between the drywell and containment walls. The internal design temperature and pressure for the guard pipes which enclose these steam lines are the same as the design values specified for the enclosed lines.
2. Reactor Water Cleanup Lines (P131/P132, P132, and P424)
The reactor water cleanup pumps are located outside containment; the heat exchangers and filter demineralizers, are located inside containment, but outside the drywell. The reactor water cleanup pump suction line from the reactor recirculation system lines and the reactor bottom head penetrates the drywell and containment. Two automatically actuated, motor-operated valves provide for isolation of this Revision 20 6.2-97 October, 2017 line. One valve is just inside the drywell, the other is outside containment. A guard pipe encloses the line between the drywell and containment walls. The reactor water cleanup pump discharge line to the heat exchangers and filter demineralizers penetrates containment. Two automatically actuated, motor-operated valves (one inside and one outside containment) provide for isolation of this line. A blowdown line from the filter demineralizers penetrates containment and divides to form separate lines to the condenser and radwaste system. Automatically actuated, motor-operated valves, one inside and one outside containment, provide for isolation of this line. The return line from the filter demineralizers penetrates containment and connects to the feedwater line between the outboard feedwater gate valve and the outboard (feedwater) check valve. Two automatically actuated, motor-operated gate valves provide for isolation of this line. One valve is inside, the other outside of containment.
3. Residual Heat Removal Shutdown Cooling Line (P421)
The residual heat removalshutdown cooling line branches from the B reactor recirculation loop and penetrates both the drywell and containment. A check valve, in parallel with a normally closed, remote-manually actuated, motor-operated valve isolates the line inside the drywell; a normally closed, remote-manually actuated, motor-operated valve isolates the line outside containment. A guard pipe encloses this line from the drywell wall to the containment wall to protect against containment overpressurization in the event of a line break. Revision 19 6.2-98 October, 2015
4. Recirculation System Sample Line (NA)
A sample line from the recirculation system penetrates the drywell. This line is 3/4 inches in diameter and is designed in accordance with the requirements of the ASME Code,Section III, Class 2. A sample probe with a 1/8 inch diameter hole is located inside one recirculation discharge line within the drywell. In the event of a line break, this probe acts as a restricting orifice and limits escaping fluid flow. Two air operated valves which fail closed are provided for isolation of this line. Both sample isolation valves are located outside the drywell.
c. Conclusions Concerning General Design Criterion 55 To assure protection against the consequences of accidents involving the release of radioactive material, piping which forms portions of the reactor coolant pressure boundary has been shown to provide adequate isolation capability on a case-by-case basis. In all cases, a minimum of two barriers is shown to protect against release of radioactive materials. Where necessary to protect the containment against overpressure, guard pipes are provided which enclose the process pipes between the drywell and containment walls.
In addition to satisfying the requirements of GDC 55, the pressure retaining components which comprise the reactor coolant pressure boundary are designed to satisfy other appropriate requirements which minimize the probability or consequences of an accident rupture. Quality requirements for these components ensure that they are designed, fabricated and tested to the highest reactor plant component standards. The classification of components which comprise the reactor coolant pressure boundary is Quality Group A; these components are designed in accordance with the ASME Code, Revision 12 6.2-99 January, 2003 Section III, Class 1. Additional information concerning classification is presented by
. The containment and reactor vessel isolation control system is addressed in <Section 7.3>. 6.2.4.2.2.2 Justification with Respect to General Design Criterion 56 GDC 56 requires that lines that penetrate containment and communicate with the containment interior must have two isolation valves, one valve inside containment, the other outside, unless it can be demonstrated that the containment isolation provisions for a specific class of lines are acceptable on some other basis.
lists those lines that penetrate primary containment and connect to the drywell and suppression chamber. The purpose of this table is to summarize the design of each listed line with respect to the requirements of GDC 56. Although a word-for-word comparison with GDC 56 is, in some cases, not practical, it is possible to demonstrate adequate isolation provisions on some other defined basis. It should be noted that this criterion does not reflect consideration of the BWR suppression pool design, since those lines which connect to the suppression pool would require placement of inside containment isolation valve under water. All of the lines which connect to the suppression pool are to or from the individual watertight ECCS pump rooms. Items a, b, c, d, e, and f, below, address influent lines to the suppression pool, effluent lines from the suppression pool, influent and effluent lines from the drywell and suppression pool free volume, airlock leakage control, inclined fuel transfer tube, and conclusions with respect to GDC 56, respectively. Revision 12 6.2-100 January, 2003
a. Influent Lines to the Suppression Pool
1. Low Pressure Core Spray, High Pressure Core Spray, and Residual Heat Removal Test and Pump Minimum Flow Bypass Lines, Residual Heat Removal Heat Exchanger dump to Suppression Pool, and Suppression Pool Cleanup Return. (P105 and P409, and P407 and P408)
The low pressure core spray, high pressure core spray and residual heat removal test lines have isolation capability commensurate with the importance to safety of isolating these lines. Each line has a normally closed, motor-operated valve located outside containment. Containment isolation requirements are satisfied on the basis that the test lines are normally closed, low pressure lines, constructed to the same quality standards as the containment. Furthermore, the consequences of a break in one of these lines result in no significant effect on safety. All of these lines terminate below the minimum suppression pool drawdown level, except for lines through Penetrations P408(RHR) and P409(HPCS). These two lines terminate above the minimum suppression pool draw-down level. Penetration P409 has a vacuum breaker located above normal suppression pool level to mitigate water hammer effects. The test return lines are also used for suppression pool return flow during other modes of operation. This reduces the number of penetrations, minimizing the potential pathways for radioactive material release. Typically, pump minimum flow bypass lines join the test return lines downstream of the test return isolation valve. The bypass lines are isolated by motor-operated valves and a restricting orifice is provided downstream of the valves. Revision 20 6.2-101 October, 2017 The suppression pool cleanup return line via P105/P106 is used for suppression pool return flow during periods of suppression pool cleaning and mixing/cooling. This system is isolated with two motor-operated valves located outside containment. Containment isolation requirements are satisfied on the basis that the return line isolation valve design satisfied GDC 56 (Reference 36), and it is constructed to the same quality standards as the containment. These valves are normally closed when SPCU is not in operation. The consequence of a break in this line results in no significant effect on safety. Two motor-operated valves with separate divisional power are required to meet GDC 56 for influent lines connected directly to the suppression pool which is not a closed system outside containment.
2. Reactor Core Isolation Cooling Pump Minimum Flow Bypass, (P104)
The reactor core isolation cooling pump minimum flow bypass line discharges into the suppression pool and terminates above the pool minimum drawdown level. A motor-operated, remote-manually actuated globe valve isolates the line outside containment. The valve is located as close to containment as possible.
3. Residual Heat Removal Heat Exchanger Vent and Relief Valve Discharge Lines (P118, P107, P431, and P429)
Residual heat removal heat exchanger vent lines discharge to the suppression chamber through P118 and P431. Two normally closed, remote-manually actuated, motor-operated valves outside containment, and a check valve, located between containment and the drywell, provide isolation for P118. Revision 21 6.2-102 October, 2019 Penetration P431 has one normally closed, remote-manually actuated, motor-operated valve and one normally open, automatic closing, remote-manually actuated, motor-operated valve outside containment, and a check valve, located between containment and the drywell. Relief valve discharge lines from the residual heat removal heat exchangers and various emergency core cooling system suction and discharge lines discharge to the suppression pool. These vent lines are isolated by the relief valves. The addition of block valves would defeat the purpose of the relief valves. The relief valves set pressure is greater than 1.5 times containment design pressure. A postaccident sampling system sample return line also ties into the relief valve discharge header and is isolated by two locked closed, remote-manually actuated solenoid valves outside containment.
b. Effluent Lines from the Suppression Pool (P103 and P401 and P101; P102 and P402 and P403)
The low pressure core spray, high pressure core spray, reactor core isolation cooling, and residual heat removal suction lines are equipped with remote-manually actuated, motor-operated gate valves outside containment. These valves provide the ability to isolate in the event of a line break and also provide long term leakage control. In addition, suction piping from the suppression pool is considered an extension of containment since this piping must be available for long term use following a design basis LOCA. Therefore, this piping is designed to the same quality standards as the containment. Thus, the need for isolation is obviated to some Revision 19 6.2-103 October, 2015 degree by providing a high-quality system and by the fact that the piping runs to the water-tight ECCS pump rooms. Also, the emergency core cooling system discharge line fill system (emergency core cooling system waterleg pumps) takes suction from the respective emergency core cooling system pump effluent line from the suppression pool downstream of the isolation valve. The emergency core cooling system discharge line fill system suction line includes a manual valve provided for operational purposes. This system is isolated from containment by the respective emergency core cooling system pump suction valve from the suppression pool
. Also, each ECCS pump room is provided with leak detection capabilities as discussed in <Section 9.3.3>. If leakage from a seal or gasket is detected in one of the pump rooms during normal plant conditions, the remotely operated valve installed in the pump suction line would be closed, thereby isolating the leaking component from the suppression pool water <Section 6.3.2.6>. No seals or gaskets are installed between the containment penetration and the isolation valve. The only potential path for leakage of suppression pool water into the ECCS pump rooms is through the pumps suction lines, since these are the only lines penetrating the containment at an elevation below the suppression pool water level. See <Section 3.6.2.3.5.2> for discussion of unisolable/isolable leaks during non-accident (normal operation) and accident conditions. Therefore, the need to size the ECCS pump rooms so that the volume of suppression pool water needed to fill the ECCS pump room would not reduce the suppression pool level below the minimum drawdown level is not required due to the leak detection and isolation capabilities incorporated in the design. The potential reduction in suppression pool water inventory before detection and isolation Revision 12 6.2-104 January, 2003 of a leaking seal or gasket in the pump room would be insignificant. Suppression pool makeup water during normal plant conditions is from the condensate water storage tank.
c. Influent and Effluent Lines from Drywell and Suppression Pool Free Volume
1. Combustible Gas Control and Post-LOCA Atmosphere Sampling Lines (P302 and P318, P423 and P425)
The combustible gas control system backup purge line which penetrates containment includes two normally closed, remote-manually actuated valves, one inside and one outside containment. The post-LOCA hydrogen sampling system lines which penetrate containment and connect to the drywell and suppression chamber air volume are equipped with a normally closed, solenoid operated isolation valve outside containment, and a 0.25 inch orifice inside containment. The design provides assurance of isolation of these lines. The piping outside containment is a closed loop and is considered an extension of containment since it must be available for long term use following a design basis LOCA. Therefore, it is designed to the same quality standards as containment.
2. Containment Purge and Exhaust Lines (V313 and V314)
The containment purge and exhaust lines are each equipped with four automatically actuated isolation valves. One valve is outside containment, one valve is in a large normally closed branch line inside containment, and two inseries valves are in a smaller intermittently used branch line. Revision 19 6.2-105 October, 2015
3. Reactor Core Isolation Cooling Turbine Exhaust Line and Turbine Exhaust Vacuum Relief Line (P106 and P115)
The RCIC Turbine Exhaust Line (P106) and the associated vacuum break line (P115) share common containment isolation valves: The first containment isolation valves for the penetrations are: E51F068 (automatic) and E12F102 (locked closed). The second containment isolation valve downstream of E51F068 is nozzle check valve E51F040 (not a simple check). Downstream of E12F102 is the RHR Relief Lines to the Suppression Pool (P107 and P429). The first isolation valves/barriers for the RHR Relief Lines (P107 and P429) are also the second isolation valves/barriers for the RCIC Turbine Exhaust Line and the Vacuum Break Line (P106 and P115). These valves/barriers are: E12F005, E12F025A, E12F025B, E12F025C, E12F055A, E12F055B, E21F018, N27F751, P87F264 and spectacle flanges 1E12D015A and 1E12D015B.
d. Containment Airlock Leakage Control System (P305/P312)
These lines serve a leakage control function by processing leakage past an inflatable seal. They are designed such that the open position of the valves provides a position of greater safety. Filtration of leakage is provided by means of an engineered safety feature system (AEGTS).
e. Inclined Fuel Transfer Tube (P205)
When the Inclined Fuel Transfer System (IFTS) blind flange is removed in Operating Mode 1, 2, or 3, the containment boundary inside the containment building is made by the remaining portion of the transfer tube containment isolation assembly, containment Revision 21 6.2-106 October, 2019 bellows, and steel containment penetration, and outside the containment building by the transfer tube, drain line, drain valve, and local leak rate test valve (Reference 35).
f. Conclusions Concerning General Design Criterion 56 To assure protection against the consequences of accidents involving the release of significant amounts of radioactive material, piping that penetrates containment has been shown to provide adequate isolation capability on a case-by-case basis in accordance with GDC 56.
In addition to satisfying the isolation requirements specified by GDC 56, the pressure retaining components of these systems are designed, fabricated and tested in accordance with the requirements of the ASME Code,Section III. In some cases, provision of a high quality system obviates the need for isolation valves due to the diminished probability of a rupture in such a system. Additional information concerning classification is presented by
. The containment and reactor vessel isolation control system is addressed in <Section 7.3>. 6.2.4.2.2.3 (Deleted) 6.2.4.2.3 Consideration of NRC Branch Technical Position CSB 6-4, Containment Purging during Normal Plant Operations The containment vessel and drywell purge system is designed to achieve the objectives stated in Branch Technical Position CSB 6-4. Purge system containment isolation valves are capable of isolating containment within five seconds. The containment purge system is described in <Section 9.4.6>. Revision 12 6.2-107 January, 2003 Radiological consequences for the initial cycle of a postulated LOCA during containment purge system operation have been evaluated in accordance with Branch Technical Position CSB 6-4. Since drywell purge system (approximately 25,000 cfm capacity) operation is restricted to reactor cold shutdown conditions and refueling operations, only the containment purge system (5,000 cfm capacity) was assumed to be operating at the start of the LOCA. The calculated site boundary doses are 0.9 rem to the thyroid and 162 mrem whole body. These doses are a small fraction of the <10 CFR 100> guideline values. This analysis is separate from the radiological dose analysis performed in <Chapter 15> for the limiting design basis LOCA and is not impacted by implementation of the alternative accident source term. Major assumptions used in the dose analysis are as follows (initial cycle):
a. A double ended guillotine break of the recirculation line was assumed to occur instantaneously. This accident was chosen because it represents the worst break and, consequently, the highest doses.
b. Purge system isolation valve closure will isolate containment within five seconds (includes valve closure time of four seconds and an additional maximum time of one second for conservatism).
During this period reactor coolant blowdown was conservatively estimated to be 109,766 pounds
.
c. Forty percent of the blowdown was assumed to flash to steam. It was conservatively assumed that the entire iodine activity in the flashed fraction of the total blowdown was instantaneously released to the containment atmosphere at the instant the accident occurred.
Plate out of iodine was ignored. Retention of iodines in the suppression pool was also ignored although, actually, the flashed activity would first be dumped into the suppression pool and would then slowly evolve into containment. Revision 19 6.2-108 October, 2015
d. Specific activity in the reactor coolant was conservatively assumed to be 6.56 µCi/g of I-131 and 34.9 µCi/g of Xe-133, with other isotopes in proportionate quantities. This corresponds to spike conditions.
e. Turbulence resulting from the high blowdown rates and operation of fan coolers in containment was assumed to ensure good mixing in the entire containment volume.
f. Containment air was assumed to be released through two 18 inch purge lines, one supply and one exhaust, for five seconds.
Constant flow rates through the open purge lines corresponding to the maximum containment pressure of approximately 3.0 psig during the release period <Figure 6.2-2> were used to determine a total flow to the environment of 1,020 pounds. This value is conservative since it ignores lower flow rates due to lower containment pressures and partial closure of the purge isolation valves at times prior to five seconds.
g. No credit was allowed for iodine removal by the 99 percent efficient charcoal adsorbers in the containment purge exhaust lines.
h. Site boundary /Q
was used in the dose calculation. 6.2.4.3 Design Evaluation 6.2.4.3.1 General Evaluation To ensure the accomplishment of the design objective stated in <Section 6.2.4.1>, redundancy is provided in all design aspects of the containment isolation systems. Mechanical components are redundant and each isolation valve is protected, by separation and/or adequate barriers, against the consequences of potential missiles. Also, system Revision 20 6.2-109 October, 2017 design specifications require each containment isolation valve to be operable under the most severe operating conditions to which it may be exposed. A program of testing is inplace to ensure valve operability and leak tightness. Isolation valve arrangements provide backup in the event of accident and satisfy the requirements of GDC 54, 55, 56, and 57, and follow the recommendations of <Regulatory Guide 1.11>. Electrical redundancy is provided by valve arrangements which eliminate dependence upon one power source to achieve isolation. Electrical cables for isolation valves in the same line are routed separately. Cables are selected with consideration of the specific environmental conditions to which they may be subjected, such as magnetic fields, high radiation, high temperature, and high relative humidity. The containment isolation valve arrangements, with appropriate instrumentation, are illustrated by <Figure 6.2-60>. Modes of valve actuation are also redundant. The primary mode is automatic; the secondary mode is remote-manual. No active failure of a single valve or other component can prevent containment isolation. All nonpowered isolation valves are administratively controlled and/or locked to ensure that position is known and maintained. The position of all power operated isolation valves is indicated in the control room. Instrumentation and controls associated with the containment isolation systems are discussed in <Chapter 7>. 6.2.4.3.2 Failure Mode and Effects Analyses A single failure can be defined as a failure of some component in any safety system which results in a loss or degradation of the capability of the system to perform the safety function. Active components are defined as components that must perform a mechanical motion in the process of accomplishing a system safety function. <10 CFR 50, Appendix A> requires that electrical systems also be designed against Revision 12 6.2-110 January, 2003 passive single failures, as well as active single failures. <Chapter 3> describes the implementation of these requirements, as well as GDCs 17, 21, 35, 41, 44, 54, 55, 56, and 57. In single failure analysis of electrical systems, no distinction is made between mechanically active or passive components. All fluid system components, such as valves, are considered electrically active, whether or not mechanical action is required. Electrical systems, as well as mechanical systems, are designed to satisfy the single failure criterion for both mechanical active and passive fluid system components that are required to perform a safety action. 6.2.4.4 Tests and Inspections The containment isolation systems are scheduled to undergo periodic testing during reactor operation. Functional capabilities of power operated isolation valves are tested remote-manually from the control room. By observing position indicators and changes in the operation of the affected system, the operability of a particular isolation valve is verified. Hydraulically testable check valves are used in certain systems, such as in the low pressure core spray, high pressure core spray and residual heat removal influent lines. These valves, located inside containment, are tested from a local panel to ensure functional capability when required to operate. Leakage testing is addressed in <Section 6.2.4.2.1> and <Section 6.2.6>. Revision 12 6.2-111 January, 2003 Instrument isolation valves inside and outside containment can be exercised from the control room and can be locally tested. An inservice inspection program for valves forming parts of the reactor coolant pressure boundary is described in <Section 5.2.4>. 6.2.5 COMBUSTIBLE GAS CONTROL IN CONTAINMENT The control of combustible gas following a LOCA will be accomplished by mixing volumes of relatively high combustible gas concentration with those of low concentration. Prior to the time when the amount of combustible gas reaches critical mixture, electrical hydrogen recombiners are placed in operation. This controls any additional gas produced and subsequently reduces the hydrogen gas inventory. To aid in the long-term cleanup, the containment atmosphere can be purged through the annulus exhaust gas treatment system. 6.2.5.1 Design Bases 6.2.5.1.1 Safety Design Bases The safety design bases are:
a. To evaluate the hydrogen concentration as a function of time following the hypothetical LOCA, the hydrogen generation from the metal-water reaction and core and sump radiolysis is based on parameters found in <Regulatory Guide 1.7>.
b. Hydrogen generated from the metal-water reaction, radiolysis and the corrosion of aluminum and zinc is assumed to evolve to the drywell atmosphere and form a homogeneous mixture. Several natural forces support this assumption. These natural forces include molecular diffusion and natural convection. Natural convection is promoted by temperature gradients existing in the drywell and the Revision 12 6.2-112 January, 2003
cascading effect of the ECCS water exiting through the break. These forces offset the natural buoyancy force of hydrogen and promote mixing in the drywell. Mixing is promoted in the containment by these same natural forces. In addition, the initiation of the containment sprays will create turbulence in the containment and enhance mixing.
c. The system design complies with all applicable requirements of
<10 CFR 50, Appendix A> (Criterion 41) and <Regulatory Guide 1.7>.
d. The system is capable of sampling and measuring the hydrogen concentration in both the drywell and containment vessel, and provide remote indication and alarms in the control room.
e. The system is capable of mixing areas of high hydrogen concentration with areas of low hydrogen concentration to control combustible gas concentration in the drywell and containment vessel without reliance on purging.
f. To control the long term buildup of hydrogen in the containment, recombiners are provided. There are two 100 percent capacity recombiners.
g. Capability to purge the containment vessel and drywell atmospheres through a fission product removal system is also provided and available for long-term cleanup.
h. The mixing subsystem and the electrical hydrogen recombiners meet the quality assurance, redundant instrumentation and power availability requirements assigned to an engineered safety feature system
. Revision 19 6.2-113 October, 2015
i. All components in the mixing and hydrogen control systems are of Seismic Category I design and are capable of withstanding the temperature and pressure transients resulting from a LOCA. They can also withstand the humidity conditions and radiation environment in which the combustible gas control system components are located <Section 3.11>.
j. Protection from postulated missiles and pipe whip is provided as required to ensure proper system operation. All active components of the drywell purge and hydrogen control systems are located in the containment outside the drywell. The major system components and associated performance data are listed in
.
k. Since operation of only one of the two independent combustible gas control systems is required, a single failure will not prevent the system from fulfilling its design function. The combustible gas control system failure analysis is presented in
.
l. The capability to periodically inspect and test systems and system components is discussed in <Section 6.2.5.4>.
m. The hydrogen recombiners are freestanding units located in the containment. Therefore, the protection of personnel from radiation in the vicinity of the recombiners is not required.
n. In accordance with <Regulatory Guide 1.7>, the concentration of hydrogen is the controlling factor for the combustible gas control system since the oxygen concentration is greater than five percent by volume.
o. The combustible gas control system is placed in operation in accordance with Emergency Operating Procedures (EOPs).
Revision 15 6.2-114 October, 2007 6.2.5.2 System Design A tabulation of the design and performance data for each system component is located in
. A detailed discussion of instrumentation features is provided in <Section 7.3>. 6.2.5.2.1 Hydrogen Analysis Subsystem The hydrogen analyzer is a thermal conductivity device that measures the percentage of hydrogen by volume by detecting changes in thermal conductivity. These changes are found by first measuring the thermal conductivity of a sample. The sample is then passed through a catalytic reactor which causes the hydrogen to react and be removed as water. The conductivity of the sample is measured again. The difference between the first and second conductivity measurement is the amount of hydrogen initially present in the sample. These analyses are designed to provide an accuracy of +10 percent to -1 percent of atomic hydrogen concentration. Tests have been conducted to qualify the analyzer in accordance with IEEE 323 (Reference 7), 334 (Reference 14) and 344 (Reference 8). Refer to <Section 3.10> and <Section 3.11>. Since hydrogen is much lighter than air it diffuses rapidly and tends to form a uniform mixture. Because of this, it is unlikely that areas of higher concentrations could form. Any such concentrations would tend to form first at the high points, but only if the hydrogen release point were near the ceiling of an enclosed area and no circulation of atmosphere were to occur (Reference 15). These conditions will not be present after the LOCA since pressure and temperature transients due to the release of steam to the containment and drywell, as well as operation of the ECCS systems, will cause considerable turbulence throughout the area. Since this turbulence will result in a relatively homogeneous mixture of hydrogen, the hydrogen sample locations are representative of the Revision 12 6.2-115 January, 2003 containment and drywell atmosphere. Redundant sample lines from the space between the reactor vessel head and the drywell dome, the top of the drywell area and the containment dome are connected to redundant hydrogen analyzers. Piping and instrumentation for the hydrogen analysis subsystem is presented in <Section 7.3>. Design of the subsystem is Safety Class 2, Seismic Category I. The analyzer panels are located in the auxiliary building at Elevation 620-0 and in the intermediate building at Elevation 654-6 <Figure 1.2-5> and <Figure 1.2-7>. The hydrogen analysis subsystem operates independently of any other subsystem in the containment combustible gas control system. Shielding and remotely operated valves are provided for the sample station to limit radiation exposure of plant personnel. The two redundant hydrogen analyzers and sample systems ensure that no single failure will prevent continuous monitoring of the hydrogen concentrations in the drywell and containment following a LOCA. The analyzers and sample systems are manually initiated by the operator from the control room following a LOCA. The required presence of the operator in the control room and the relatively slow buildup of hydrogen concentrations in containment make delayed startup of these analyzers acceptable. Delaying initiation 15 minutes to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after a LOCA also subjects the analyzer to less severe sample conditions than the maximum LOCA conditions, for which they are designed, thereby increasing the probability of their successful operation. <Figure 6.2-61> indicates that hydrogen concentrations approach three percent in approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> after a LOCA, providing more than sufficient time to initiate manual action. However, since the Three Mile Island event, Revision 12 6.2-116 January, 2003 <NUREG-0737>, <Regulatory Guide 1.97>, and <10 CFR 50.44> have established additional requirements on the use and performance of the hydrogen analyzers <Appendix 1A, Item II.F.1.6>. 6.2.5.2.2 Hydrogen Mixing Subsystem Initial control of the hydrogen concentration following a LOCA will be accomplished by mixing volumes of potentially high and low hydrogen concentrations. Mixing is accomplished by means of redundant, 500 scfm, centrifugal air compressors which take suction from the containment volume just below the service floor (Elevation 689-6) and at the containment dome and discharge into the drywell. This pressurizes the drywell sufficiently to provide increase in drywell bypass leakage and uncover the upper row of suppression pool vents. The Mixing Compressor After Coolers are cooled using the RHR system. The drywell allowable bypass leakage is much larger than the capacity of the compressors. There is a possibility that the drywell will not be pressurized sufficiently to uncover the upper row of suppression pool vents. If the system can be pressurized to uncover the upper row of suppression pool vents, the best mixing is obtained by this method. This is due to the fact that the drywell volume is dispersed to the containment uniformly from around the entire circumference of the drywell at the lowest possible point, while the return to the drywell is from areas just below the service floor and the containment dome. If drywell bypass leakage accounts for the entire flow from the drywell, mixing should still be adequate due to the location of the two suction intakes just below the service floor and at the containment dome. This arrangement precludes any possibility of short circuiting the mixing subsystem. Revision 19 6.2-117 October, 2015 Piping and instrumentation from the mixing subsystem are shown in <Figure 6.2-62>. Locations of the mixing compressors are shown in <Figure 1.2-8>. Physical separation of components in the hydrogen mixing system assures proper operation despite pipe whip, missiles and jet impingement. There are two systems supplying air to the drywell. Supply piping and compressors are on adjacent quadrants outside the drywell. Hence, no single pipe break, missile or jet can disable both systems. This arrangement meets the criteria of <Regulatory Guide 1.46>. The piping is designed for the maximum differential pressure loads and is seismically supported. No ductwork is used in the system. This subsystem is designed as Safety Class 2, Seismic Category I. A prototype drywell purge compressor has been tested under LOCA conditions to ensure operation following a LOCA. The seismic qualification procedure for mechanical and electrical equipment is addressed in <Section 3.10>, and environmental qualification is described in <Section 3.11>. 6.2.5.2.3 Hydrogen Recombination System The hydrogen control system is fully redundant and consists of two 100 percent capacity hydrogen recombiners. <Figure 6.2-61> depicts hydrogen concentration in the drywell and containment as a function of time.
a. Each recombiner subsystem consists of a control panel and a power supply cabinet located in the control complex. The recombiner is located in containment, outside the drywell, at floor Elevation 664-7. Air flows by natural convection through the unit. The recombiner is a completely passive device.
Revision 19 6.2-118 October, 2015
b. The power supply cabinet contains an isolation transformer plus a controller to regulate the power to the recombiner. The controls for the power supply are located in the separate control panel and are manually actuated.
c. Each hydrogen recombiner consists of the following design features:
1. A preheater section consisting of a shroud placed around the central heaters to take advantage of heat conduction through the central walls for preheating incoming air.
2. An orifice plate to regulate the rate of air flow through the unit.
3. A heater section consisting of five banks of metal sheathed electric resistance heaters to heat the air flowing through it to hydrogen-oxygen recombination temperatures. Each bank contains 60 individual U-type heating elements.
4. A mixing chamber which mixes and dilutes the hot effluent with containment air to lower the temperature of the discharge stream.
5. An outer enclosure to protect the unit from impingement by containment spray.
6. Except for electrical power, there is no need of any plant support service.
d. Containment atmosphere is heated within the recombiner in a vertical duct causing it to rise by natural convection. As it rises, replacement air is drawn through intake louvers downward through a preheater section which will temper the air and lower its relative humidity. The preheated air then flows through an orifice Revision 12 6.2-119 January, 2003
plate, sized to maintain a 100 scfm flow rate, to the heater section. The air flow is heated to a temperature above 1,150F, the reaction temperature for the hydrogen-oxygen reaction, and any free hydrogen present reacts with atmospheric oxygen to form water vapor. After passing through the heater section, the flow enters a mixing section which is a louvered chamber where the hot gases are mixed and cooled with containment atmosphere before the gases are discharged directly into the containment. The air discharge louvers are located on three sides of the recombiner. To avoid short circuiting of previously processed air, no discharge louvers are located on the intake side of the recombiner. Tests have verified that the hydrogen-oxygen recombination is not a catalytic surface effect associated with the heaters, but occurs due to the increased temperature of the process gases. As the phenomenon is not a catalytic effect, saturation of the unit cannot occur. Results of testing a prototype and production electric hydrogen recombiner are given in (Reference 16), (Reference 17), (Reference 18), (Reference 19), and (Reference 22). No differences exist between the recombiner system on which the qualification tests were conducted and the recombiner system which was supplied for Perry. For environmental qualification see <Section 3.11>. The system is designed to Class 1E, Seismic Category I requirements. The system is shown on <Figure 6.2-63>. 6.2.5.2.4 Purge Subsystem A purge subsystem is provided to aid in the long-term cleanup of combustible gas from containment and drywell provided that the site release rate is expected to remain below the plant limits. The purge subsystem is also used as a means to provide pressure relief from the drywell during startup and normal plant operation. Purging is accomplished by passing air from the drywell through the annulus exhaust gas treatment system (AEGTS) filters before being discharged to the outside atmosphere. The combustible gas purge subsystem consists of a Revision 12 6.2-120 January, 2003 flow control valve, two isolation valves, and interconnecting pipe. The isolation valves, one inside and one outside containment, are motor-operated to isolate the containment vessel during a LOCA. The flow control valve is in the fail open position to maximize flow for drywell pressure control. Those portions of the purge subsystem associated with containment isolation are designed to meet Safety Class 2, Seismic Category I requirements. The system is shown on <Figure 6.2-62>. 6.2.5.3 Design Evaluation The design evaluation of the combustible gas control system follows the guidelines of NRC Branch Technical Position CSB 6-2, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, and is as follows:
a. Generation of hydrogen from the corrosion of zinc and aluminum exposed to neutral water occurs in the following manner:
Zn 2 H2O Zn OH2 H2 2Al 3 H2O Al2O3 3H2
b. The rate of hydrogen generated from these corrosion equations is defined as follows:
1. Zinc:
7340 [This equation is derived from R 356 e T experimental data as defined in (Reference 22).] Where: T = Temperature in K. R = The hydrogen generation rate in lb-mole/ft2-hr Revision 15 6.2-121 October, 2007
2. Aluminum:
R = 1.79 x 10-7 (Reference 23) Where: R = The hydrogen generation rate in lb-mole/ft2-hr This rate is valid throughout the temperature range to which the aluminum is exposed during an accident.
c. The corrodible surface areas inside the containment and drywell are maintained within the evaluated values listed below:
1. Drywell: Area Galvanized Steel 70,000 ft2
2. Containment:
Galvanized Steel 150,000 ft2 Aluminum surface areas are not shown, since engineering analysis shows that the production of hydrogen from the corrosion of aluminum is negligible compared to other hydrogen generation sources. Additions of aluminum to the plant are evaluated for impact on hydrogen control analyses.
d. The mass of the Zircaloy fuel cladding to a depth of 0.23 mils as specified in <Regulatory Guide 1.7> is 663 pounds.
Revision 20 6.2-122 October, 2017
e. The integrated production of hydrogen for the containment and drywell due to radiolysis of water and corrosion of zinc is shown in <Figure 6.2-64>. The production of hydrogen from the corrosion of aluminum is negligible compared to the other sources.
f. Negligible hydrogen and oxygen is contained in the reactor coolant system with respect to the other components of hydrogen generation following a LOCA.
g. The total fission product decay power as a fraction of operating power versus time is given in
.
h. The fission product distribution model is discussed in
<Section 12.2>.
i. The integrated production of hydrogen in the drywell due to the zirconium-water reaction is 12.6 lb-moles for the first two minutes. There is no zirconium-water reaction after this time.
j. The hydrogen concentration in containment plotted as a function of time is shown in <Figure 6.2-61> for a design basis LOCA.
k. Two methods of hydrogen control are available. They are hydrogen mixing and hydrogen recombination.
shows the design and operating parameters.
l. Since hydrogen is much lighter than air, it diffuses rapidly, tending to form a uniform mixture. Because of this, it is unlikely that areas of higher concentrations could form; however, any such concentrations would tend to form at the high points of containment, where the containment spray lines and mixing system suction lines are located. The initiation of these systems would create turbulence and enhance mixing.
Revision 12 6.2-123 January, 2003
m. The hydrogen mixing system piping is designed for the maximum differential pressure loads and is seismically supported. No ductwork is used in the system.
6.2.5.4 Testing and Inspection The combustible gas control system is visually inspected in accordance with ASME Code Section XI. Compressors are tested by turning them on from the control room and measuring flow. Isolation valves are exercised periodically and position checked on indicators in the control room. Testing of the hydrogen analyzers is done periodically by injecting a calibration gas into the sample lines and comparing the known concentration with the analyzer readout. The hydrogen recombiners are tested in accordance with the Technical Specifications to check the calibration of the unit and proper operation of the heaters by energizing the unit and allowing temperatures to stabilize at the operating conditions. Preoperational tests of the combustible gas control system are conducted during the final stages of plant construction prior to initial startup <Section 14.2>. These tests ensure correct functioning of all controls, instrumentation, compressors, recombiners, piping, and valves. System reference characteristics, such as pressure differentials and flow rates, are documented during the preoperational tests and are used as base points for measurements in subsequent operational tests. In addition, inservice inspection of all ASME,Section III, Class 3 components is done in accordance with <Section 6.6>. Revision 12 6.2-124 January, 2003 6.2.5.5 Instrumentation Requirements Operation of the combustible gas control system is performed manually. On-off status of compressors and position of valves are indicated in the control room. Hydrogen concentration recorders and alarms, low flow, system bypassed alarms, and control switches are located in the control room. The hydrogen analyzer recorder/switching station is located in the control room. The analyzer switching station allows the operator to manually select one of the four sample areas previously discussed. Both Hydrogen Analyzers annunciate high hydrogen concentration by volume at two levels. The setpoints have been selected to assist the Control Room operators in performance of hydrogen control functions. The high alarm is set to alert the operator that the hydrogen concentrations are increasing and that the minimum design concentration for operation of the hydrogen recombiners has been reached. The high-high alarm is set to alert the operator that hydrogen concentrations are continuing to increase and that several actions including operation of the Combustible Gas Mixing System is required prior to reaching four percent hydrogen concentration. All lines in the system that connect the drywell with the containment vessel have isolation valves which close automatically on LOCA signal. Manual initiation and test operation are overridden by the LOCA signal. During normal plant operation, these isolation valves are closed. The hydrogen recombiners do not require any instrumentation inside the drywell or containment for proper operation after a LOCA. A thermocouple readout instrument is provided in the control complex for convenience in test and periodic checkout of the recombiner. A controller is operated from the control complex to regulate the power supply to the recombiner. Proper recombiners operation after an accident is determined by monitoring a watt-meter in the control complex. Revision 12 6.2-125 January, 2003 Design details of the combustible gas control system instrumentation and controls are discussed in <Section 7.3>. 6.2.6 CONTAINMENT LEAKAGE TESTING This section presents the testing program for determination of the primary reactor containment integrated leakage rate (Type A tests), primary containment penetration leakage rates (Type B tests) and primary containment isolation valve leakage rates (Type C tests) that complies with <10 CFR 50, Appendix J>. Testing requirements for piping penetration barriers and valves have been established using the intent of <10 CFR 50, Appendix J> (Option B). Exceptions taken to <10 CFR 50, Appendix J> for Type A, B or C tests are described and justified in
and
. This section also presents the testing program for determination of the drywell integrated leakage rate. The integrated leak rate test system is shown in <Figure 6.2-65>. The primary containment leakage rates shall be demonstrated at the test schedule specified in accordance with the Containment Leakage Rate Testing Program. Periodic Type A, B and C tests are performed to assure that leakage through the primary reactor containment and systems and components that penetrate the primary containment do not exceed allowable leakage rate values as specified in technical specifications. These periodic tests also ensure that proper maintenance and repairs are performed during the service life of the plant. 6.2.6.1 Primary Reactor Containment Integrated Leakage Rate Test During the construction phase, localized leakage testing is employed <Section 3.8> to detect leaks which may affect containment integrity or the results of the initial integrated leak rate test. Revision 12 6.2-126 January, 2003 Structural integrity test of the containment structure for strength requirements, described in <Section 3.8.1> and <Section 3.8.2>, must be satisfactorily completed prior to performance of the preoperational integrated leakage rate tests. Upon completion of construction of the primary reactor containment including installation of all portions of mechanical, fluid, electrical, and instrumentation systems penetrating containment or associated with containment integrity, and upon satisfactory completion of the structural integrity test for strength described above, the preoperational containment integrated leakage rate test is performed to verify that the actual containment leakage rate does not exceed the design limits. The preoperational integrated leakage rate tests are performed at the design basis accident pressure (Pa) to determine the measured leakage rate (Lam). (Operational integrated leakage rate tests are performed in accordance with the Technical Specifications). The leakage rate, Lam, at test pressure, Pa, shall be less than 0.75 of La. Other pertinent test data, including test pressures, test duration and definition of terms are presented in
. Type A testing will be performed in accordance with the Containment Leakage Rate Testing Program <Section 6.2.6.6>. The quantity and types of sensors associated with the primary containment integrated leakage rate instrumentation are listed in
. 6.2.6.2 Containment Penetration Leakage Rate Test Containment penetrations whose design incorporates resilient seals, gaskets or sealant compounds; air locks; equipment and access hatch Revision 12 6.2-127 January, 2003 seals; and electrical penetrations receive preoperational and periodic Type B leakage rate tests in accordance with <10 CFR 50, Appendix J> (Option B). A list of all containment penetrations subject to Type B tests is provided in
. Containment personnel air lock door seals will receive periodic Type B tests. All Type B tests are performed in accordance with the Containment Leakage Rate Testing Program <Section 6.2.6.6>.
a. Personnel Air Lock Leakage Control System The personnel air lock leakage control system controls leakage by placing a vacuum on the space between the pair of door seals on the outer doors of the personnel air locks. The vacuum between the door seals is created by routing a small line into the containment annulus. The containment annulus is kept at a slight negative pressure by the annulus exhaust gas treatment system. Any bypass leakage past the personnel air lock outer door seals is routed back into the containment annulus where it is sent to the annulus exhaust gas treatment system. This system is classified as Safety Class 2 and is designed to survive and function through a single active failure.
6.2.6.3 Containment Isolation Valve Leakage Rate Tests Those containment isolation valves which are Type C tested in accordance with <10 CFR 50, Appendix J> (Option B) are listed in
. See <Section 6.2.6.6> for the Containment Leakage Rate Testing Program. Revision 12 6.2-128 January, 2003 6.2.6.4 Scheduling of Periodic Tests The periodic leakage rate test schedules for Type A, B and C tests are given in the Containment Leakage Rate Testing Program. Type B and C tests may be conducted at any time during normal plant operations or during shutdown periods as long as the time interval between tests for any individual Type B or C test does not exceed the maximum allowable interval specified in the Containment Leakage Rate Testing Program. Each time a Type B or C test is completed the overall total leakage rate for all required Type B and C tests is updated to reflect the most recent test results. 6.2.6.5 Special Testing Requirements 6.2.6.5.1 Drywell Leakage Rate Test Following the drywell structural integrity test described in <Section 3.8.3>, the drywell leakage rate is measured at drywell design pressure. A drywell leakage rate test is also performed at reduced pressure. Subsequently, periodic drywell leakage rate tests are performed at an initial differential pressure of 2.5 psi. The reduced pressure tests verify that drywell to containment leakage does not exceed the allowable suppression pool bypass limits specified in technical specifications. The combination of the design pressure and reduced pressure leakage rate tests also verifies that the drywell will perform adequately for the full range of postulated primary system break sizes. The allowable drywell leakage rate, Ld, is 10 percent of the allowable bypass leakage for the small break accident with containment spray. The allowable bypass leakage is that leakage corresponding to a drywell A / K = 1.68 ft2 <Section 6.2.1.1.5>. La is then the leakage rate corresponding to 0.168 ft2. Revision 21 6.2-129 October, 2019 Drywell leakage rate tests are performed with the drywell isolation valves and system lineups in their postaccident position with the following exceptions:
a. Emergency core cooling systems (ECCS) injection line valves are closed to prevent venting the drywell to the suppression pool.
b. Air supply line isolation valves are closed to prevent the introduction of nonmetered air into the drywell.
c. Control rod drive hydraulic system water supply valves remain open to maintain water flow through the control rod drives. The water flow prevents accumulation of crud in the control rod drives.
Also, reactor water cleanup system valves are left open. The reactor water cleanup system is used to maintain reactor vessel level.
d. Root valves for drywell pressure transmitter instrumentation interlocked with ECCS are closed to prevent ECCS actuation.
Any paths for equalizing drywell and containment pressure open during the Type A test are isolated. The containment air space external to the drywell is vented to atmosphere or to the annulus. Preoperational drywell tests are performed as late as is practical in the construction sequence, but prior to initial operation. For high pressure tests, the upper containment pool is filled to normal water level, the horizontal vents are plugged in order to achieve design pressure, and the suppression pool is filled. Revision 12 6.2-130 January, 2003 After preoperational testing is satisfactorily completed, the drywell vent plugs can be removed and the suppression pool refilled. All subsequent periodic tests are conducted at a reduced pressure (less than that required to bubble drywell air through the top row of vents). For all of the above tests, the drywell atmosphere is allowed to stabilize for one hour after attaining test pressure. When the steady-state conditions are achieved the drywell leakage rate is determined by metering the makeup air flow required to maintain the constant test pressure. Acceptance criteria are specified in technical specifications. Periodic drywell leakage rate tests are performed at the intervals specified in technical specifications. The maximum allowable leakage rate into the annulus and the means to verify that the rate has not exceeded the bypass leakage rate is discussed in <Section 6.2.4>. 6.2.6.6 Primary Containment Leakage Rate Testing Program The Primary Containment Leakage Rate Testing Program implements the leakage rate testing of the primary containment as required by <10 CFR 50.54(o)> and <10 CFR 50, Appendix J> (Option B) as modified by approved exemptions. This option allows the testing frequency for Type A, B, and C tests to be extended based on the leakage rate performance history of the components in the <10 CFR 50, Appendix J> program. This Program is in accordance with the guidelines contained in NEI Topical Report NEI 94-01, Revision 3-A, with conditions and limitations in NEI 94-01, Revision 2-A, with the exceptions as identified in the Program and in USAR
. Revision 21 6.2-131 October, 2019 6.2.7 SUPPRESSION POOL MAKEUP SYSTEM Following a LOCA, the suppression pool makeup system provides water from the upper containment pool to the suppression pool by gravity flow. The quantity of water provided is sufficient to account for all conceivable postaccident entrapment volumes (i.e., places where water can be stored while maintaining long term drywell vent water coverage). 6.2.7.1 Design Bases The following criteria were used in the design of the suppression pool makeup system:
a. The system is redundant with two 100 percent capacity lines. The redundant lines are physically separated and all electrical power and control is separated into two divisions in accordance with IEEE Standard 279.
b. The system is Safety Class 2, Seismic Category I.
c. The minimum long term postaccident suppression pool water coverage over the top of the top drywell vent is 2-0.
d. The minimum normal operation low water level (LWL) suppression pool height above the top drywell vent centerline is 6-9.5.
e. The maximum normal operation high water level (HWL) suppression pool height above the top drywell vent centerline is 7-6.
f. The suppression pool volume, between normal LWL and the minimum postaccident pool level, plus the makeup volume from the upper pool is adequate to supply all possible postaccident entrapment volumes for suppression pool water, and keep the suppression pool at an acceptable water level.
Revision 12 6.2-132 January, 2003
g. The postaccident entrapment volumes causing suppression pool level drawdown include:
1. The free volume inside and below the top of the drywell weir wall.
2. The added water volume needed to fill the vessel from a condition of normal power operation to a postaccident complete fill of the vessel including top dome.
3. Volume in the steam lines out to the first MSIV for three lines and out to the second MSIV on one line.
4. An allowance for containment spray holdup on equipment and structural surfaces.
h. No credit for feedwater or HPCS injection from the condensate storage tank is taken in calculating minimum postaccident suppression pool level.
i. Piping components which would be wetted in the event of a drywell flooding transient (from inadvertent dump of the upper pool (SPMU) with the suppression pool at maximum operating level and under negative drywell pressure conditions) have been analyzed and would not result in adverse consequences to these components.
j. The minimum normal operation suppression pool volume at LWL is adequate to act as a short term energy sink without taking credit for upper pool dump.
k. The long term containment pressure and suppression pool temperature takes credit for the volume added postaccident from the upper containment pool.
Revision 12 6.2-133 January, 2003
l. The system gravity dump time through one of the two redundant lines is less than or equal to the minimum pump time; pump time is determined by dividing pumping volume (upper pool makeup volume plus volume in the suppression pool stored between LLWL and minimum top vent coverage) by the total maximum runout flow rate from all five ECCS pumps.
6.2.7.2 System Design The piping system consists of two lines which penetrate the separator storage section of the upper containment pool through the side walls. One line is located on either side of the separator pool. From there, each line is routed down to the suppression pool on opposite sides of the steam tunnel. The elevation of the separator pool penetrations will limit the volume of water which can be dumped to the lower pool. This volume limitation along with adequate weir wall freeboard ensures that no excessive drywell flooding over the weir wall will occur for inadvertent opening of the valves on the suppression pool makeup lines. The volume of the upper containment pool, which is available for suppression pool makeup, is equivalent to the volume of an 8.25-feet thick slice across the entire upper pool surface area, plus the separator pool volume between the top of the separator wall and the makeup system penetration to the upper pool. This requires that the refueling gate between the reactor well and the dryer storage pool be removed during power operation. The fuel transfer pool gate may be in place, removed, or placed in its stored position during power operation when the 360 Platform Troughs are not submerged in the Upper Containment Pool, since the volume of water in the fuel transfer pool is not then required for SPMU (Reference 32). However, the fuel transfer pool gate must be removed, or placed in its stored position when the 360 Platform Troughs are installed in the Upper Containment Pool during power operations, since the volume of water in the fuel transfer pool is then required for SPMU due to the inventory loss from the installation of the troughs. Revision 22 6.2-134 October, 2021 The volume of water available for dump from the upper containment pool, when combined with the suppression pool, is adequate to supply all postaccident entrapment volumes and keep the suppression pool at an acceptable level (2 feet above the top of the horizontal drywell vents) to condense steam exiting the vents, and to ensure continuous coverage of the RHR A/B Test Return Line postaccident. The need to provide for this sufficient volume of entrapment water results in the operating limit for the minimum suppression pool level being 17-9.5, plus a suppression pool level adjustment factor when a positive differential pressure exists between the drywell and the containment. This adjustment factor varies between 0.0 at 0.0 psid and 4.6 at 2.0 psid (the 2.0 psid value results in a minimum suppression pool level of approximately 18-2). This requirement for applying a limit of 17-9.5 plus the level adjustment factor for positive differential pressures is quite different than the input assumptions for the containment response analyses, which assumed a minimum suppression pool water level of 17-6 concurrent with the maximum drywell-to-containment operating limit of 2.0 psid
. Although the containment response analysis showed that the smaller water volume was sufficient for containment cooling purposes, that smaller volume did not meet the entrapment volume design basis for the SPMU system. The upper containment pool water level is required to be maintained during Operational Conditions 1, 2 and 3 at a level of 22-9 above the RPVflange. The upper pool level may be reduced to 22-5, as long as the suppression pool water level is raised 2.20 inches above the minimum allowable suppression pool water level of 17-9.5 to compensate. Raising the minimum required suppression pool water level provides the same effective volume of water (by transferring a portion of the upper pool dump volume to the suppression pool) and ensures that after a suppression pool make-up system dump, adequate water coverage over the uppermost drywell horizontal vents and the long-term energy sink capability of the suppression pool are maintained (Reference 32). Revision 22 6.2-135 October, 2021 In addition, when the inclined fuel transfer system blind flange is removed in Operational Conditions 1, 2, or 3, the upper containment pool water level is required to be maintained at a minimum level of 22-9 above the reactor vessel flange and the suppression pool water level is required to be maintained at a minimum level of 17-11.7. This is to ensure adequate suppression pool make up inventory in the event of an accident (Reference 39). Also, just prior to a refueling outage, the reactor well to steam dryer pool gate may be installed during Operational Conditions 1, 2, or 3. The upper containment pool water level is required to be maintained at a minimum level of 23 above the reactor vessel flange and the suppression pool water is required to be maintained at a minimum level of 18-3.2. During Operational Condition 3 (when entering a refueling outage with the reactor pressure reduced to or less than 230 psig and the reactor subcritical for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />), the reactor well (cavity) portion of the upper containment pool may be drained to facilitate decontamination of the reactor well. The suppression pool water level will need to be increased and maintained with a prescribed band. The applicable water level bands will ensure adequate suppression pool makeup inventory in the event of an accident (Reference 41). The fuel transfer pool gate may be in place, removed, or placed in its stored position when the 360 Platform Troughs are removed, since the volume of water in the fuel transfer pool is not required for SPMU. The fuel transfer pool gate must be removed, or placed in its stored position when the 360 Platform Troughs are installed, since the volume of water in the fuel transfer pool is required for SPMU due to the inventory loss from the installation of the troughs. Each suppression pool makeup line has two normally closed valves in series. The valves on one line are on the same electrical division. Valves on the other line are on a different electrical division. All valves are powered from an onsite emergency power source which has divisional separation and redundancy. Revision 22 6.2-135a October, 2021 The upper pool is dumped by gravity flow after opening the two normally closed series valves in each line. The valves on both lines receive divisionally separate but simultaneous signals to open. The open signal for each division is derived from either of two suppression pool level sensors. There are a total of four level sensors, two per division. There is also a series permissive signal permitting valve opening only when the LOCA signal exists. This LOCA signal is the same signal which actuates the ECCS pumps. This combination provides high reliability that the upper containment pool will be dumped when required but not dumped inadvertently by spurious signals. The dump of the upper pool on low-low suppression pool level ensures adequate water volume to keep the suppression pool vents covered for all break sizes. In addition to the suppression pool level dump signal, the upper pool will also be dumped automatically from a timer set for LOCA + 30 minutes. This upper pool dump at 30 minutes postaccident insures that adequate heat sink is available long term regardless of break size or energy dump sequence. The suppression pool makeup system will always operate following a DBA-LOCA as long as only one simultaneous equipment failure or operator error is postulated to occur. The suppression pool makeup system is specifically designed with redundant piping, valves and instrumentation to preclude failure to operate if a DBA-LOCA and any single equipment failure or operator error occurs <Figure 6.2-67>. Each of the two dump systems is independent and safety class. The two series valves on each of two makeup system dump lines are located above the top of the drywell and outside the range of pool swell effect. The end of each line terminates in a configuration which provides an unobstructed free fall to the suppression pool. Pool level transmitters are located in the auxiliary building, protected from suppression pool dynamic effects. Revision 12 6.2-136 January, 2003 6.2.7.3 Design Evaluation 6.2.7.3.1 Initiation The opening of the makeup system valves is signaled by a series combination of low-low suppression pool level and a LOCA signal permissive (further discussion in <Section 6.2.7.2>). The low-low level signal is 16 inches below the normal LWL. Since maximum ECCS pump flow lowers the suppression pool at a rate of approximately 0.88 feet per minute, there is a minimum 1-1/2 minute delay between start of ECCS flow and dumping of the upper pool. The delay is actually longer than this because some vessel inventory mass is added to the suppression pool during blowdown steam condensation. The makeup system dump valves can also be signaled to open by a LOCA signal in series with a 30 minute timer where the timer itself is started by the LOCA signal. This path of initiation logic is independent of suppression pool level and is specifically directed towards ensuring that the combined upper pool and suppression pool volumes are available as a heat sink for small breaks which do not lower the suppression pool to the LLWL trip, but continue to dump vessel blowdown energy into the pool. The minimum suppression pool volume, without upper pool dump, is adequate to meet all heat sink requirements for any combination sequence of vessel blowdown energy and decay heat energy out to 30 minutes. A pool dump initiated from the LOCA +30 minute timer could result in higher vent submergence than the initial maximum of 7-6. No problem exists in terms of pool swell since all the air would have been purged out of the drywell by the small break flow and only a small steam suppression pool vent flow would persist out to 30 minutes. Note that action of the drywell vacuum breakers which might reintroduce air into the drywell prior to 30 minutes postaccident will occur only after complete vessel depressurization and drywell steam condensation on the Revision 12 6.2-137 January, 2003 cold ECCS break overflow of a relatively large break. The hypothesized high vent submergence would also have no effect on peak drywell pressure since the high submergence would only occur during small break flow events and after suppression pool vent clearing had already been established. 6.2.7.3.2 Flow The suppression pool makeup volume is dumped in less than 10 minutes through one of two lines. The valves on the suppression pool makeup lines are fully open within 35 seconds of opening signal application. 6.2.7.3.3 Inadvertent Dump The design of the opening signal circuitry for the suppression pool makeup valves assures high probability that no inadvertent dump will occur. The suppression pool level signal (LLWL) to open the valves is in series with a permissive which only allows the open signal to pass through when a LOCA signal exists on that division. Only a simultaneous signal of either suppression pool LLWL combined with LOCA, or LOCA with a 30-minute time delay will open both valves to allow gravity drain of the upper pool to the suppression pool. Even manual action is incapable of opening both series valves unless the administratively key locked dump test permissive switch is in the test mode or a LOCA permissive signal exists. The LOCA signal plus the timer signal after 30 minutes would dump the upper pool. However, the LOCA signal itself is a one out of two twice combination of high drywell pressure and low vessel water level <Figure 6.2-68> and a double failure is required to give a spurious LOCA signal. Four level sensors indicate suppression pool water level with two sensors per electrical division. The two level sensors in one division are paralleled so that either sensor will initiate suppression pool makeup flow (pending LOCA permissive) from the makeup line whose series Revision 12 6.2-138 January, 2003 valves are on the same electrical division as the level sensors. Level sensors on one electrical division cannot initiate flow from the makeup line where valves are in a separate electrical division. There is a remote possibility that a single failure of a suppression pool level sensor and a concurrent LOCA event could initiate suppression pool makeup flow from one line such that the makeup flow started at the instant of LOCA. The flow from one makeup line will raise the suppression pool level at a rate of 0.538 feet per minute following full opening of the valves which normally prevent flow. For a large break DBA, the peak drywell pressure occurs at about one second after the break with the pressure being reduced to the steady flow submergence of the top vent by about 30 seconds. Any pool swell associated loading would occur during the first few seconds while drywell air purge is taking place. Thus, the structural loading which would occur following a DBA would occur prior to any significant flow of water from a makeup line which was erroneously signaled to open at the same instant as the DBA. The peak structural loadings associated with breaks smaller than the DBA are all less than the DBA case and only slightly extended in time. The drywell pressure for all size breaks is reduced to steady flow top vent submergence by one minute after the break. The conclusion is that no increase in maximum structural loading due to a LOCA when an erroneous signal to initiate suppression pool makeup flow occurs at the instant of LOCA. An inadvertent dump of the upper pool during any period of plant operation with a pressurized vessel does not represent, in and of itself, any hazard to the public, the plant operating personnel or any plant equipment. The drywell weir wall has sufficient freeboard height between the suppression pool surface and the top of the weir wall to Revision 12 6.2-139 January, 2003 store most of the upper pool makeup volume on top of the normal suppression pool HWL with limited flooding over the weir wall into the drywell under negative drywell pressure conditions. The piping components which would be affected in this event have been analyzed for the floodings affect, and this event could not initiate a LOCA. The dumped upper pool makeup volume can be transferred back to the upper pool via several flow paths, thus restoring the initial suppression pool water level. No fuel is stored in the upper pool during plant operations, therefore, depth of water shielding over fuel is not a concern for the inadvertent dump of the upper pool during plant operation. The Suppression Pool Makeup system valve initiation logic is designed with a keylocked system mode selector switch so that neither automatic nor manual action can open the suppression pool makeup valves while the plant is in the refueling mode. Revision 15 6.2-140 October, 2007 6.2.7.4 Tests and Inspections The suppression pool makeup valves will be manually tested periodically, one at a time, during plant power operation. An interlock prevents this manual testing unless the other valve in series on the same line is closed. The test will verify that the valve will open and close. Also, instruments will be periodically tested and inspected. Preoperational testing will include a complete flow test of the system including a timed dump of the required makeup volume. Similar flow testing could be performed at any plant shutdown outage; however, the need for such testing occurs only a few times in the plant lifetime. 6.2.7.5 Instrumentation Requirements Suppression pool water level sensors provide a signal to open the suppression pool makeup system valves. Four level instruments, two in each division, are provided. These instruments are the same analog instruments which measure normal water level variation with an extended range for LLWL <Section 7.3.1.>. A level indication for the upper pool is also provided to alert the plant operating personnel if the level drops below that needed for the makeup volume. Level in the upper pool is normally maintained by a continuous overflow of level control weirs. The level is expected to stay constant during plant power operation, except for periods when level is purposely reduced, such as discussed in <Section 6.2.7.2>. The upper pool and suppression pool temperature are monitored to ensure that the temperature does not exceed technical specification values. This ensures adequate heat sink capability of the suppression pool water, both short and long term. Revision 12 6.2-141 January, 2003 A functional control diagram for the suppression pool makeup system is presented in <Section 7.3>. 6.2.8 HYDROGEN CONTROL SYSTEM The accident at Three Mile Island - Unit 2, in 1979, involved a metal-water reaction in the core resulting in the release of amounts of hydrogen beyond the NRCs design basis accident requirements. Following the TMI accident, the NRC required a number of design improvements to all light water reactors. These TMI-related design improvements were for the purpose of further reducing the likelihood and effects of degraded core accidents, beyond the inherent design capability of the plants. Pursuant to these TMI-related items, the NRC staff required that plants with Mark III containments improve the hydrogen control capability by providing a system to control hydrogen generated from a postulated 75% metal-water reaction. The final hydrogen control rule to address improved hydrogen control capability was published as an amendment to <10 CFR 50.44> on January 25, 1985, at 50 Federal Register 3498. For the PNPP Mark III containment design, the new rule requires a hydrogen control system capable of handling, without loss of containment structural integrity, an amount of hydrogen equivalent to that generated from a 75 percent metal-water reaction of the active fuel cladding during recoverable degraded core events. In addition, systems and components necessary to establish and maintain safe shutdown and containment integrity must be capable of performing their functions during and after exposure to the environmental conditions created by the burning of hydrogen. The hydrogen control system, designed to control large amounts of hydrogen, is a distributed igniter system. The system burns hydrogen at low concentrations, thereby maintaining the concentration of hydrogen below levels which could potentially threaten containment integrity or equipment survivability. Revision 12 6.2-142 January, 2003 6.2.8.1 Design Bases 6.2.8.1.1 Safety Design Bases The safety design bases are:
a. The hydrogen control system (HCS) will burn hydrogen at low volumetric concentrations. The igniters are designed to ensure controlled burning of hydrogen equivalent to that generated from a 75% metal-water reaction of the active fuel cladding (2,475 pounds hydrogen mass) as a result of a postulated recoverable degraded core accident.
b. The HCS will be placed in operation upon reactor vessel water level decreasing to the top of active fuel (TAF) or upon hydrogen concentration in the drywell or containment reaching minimum detectable level. The HCS is secured automatically if power to the igniter is lost and manually when hydrogen concentrations inside the drywell or containment cannot be determined to be below predetermined limits.
c. The HCS is designed with suitable redundancy to ensure that no single active component failure, including power supply failures, will prevent functioning of the system.
d. Once activated, the igniters are designed to reliably ignite hydrogen for up to seven days.
e. The HCS is designed as a safety grade system, and is capable of operating for the duration of the hydrogen generation event.
f. The HCS igniter assemblies are classified and designed as electrical Class 1E and Seismic Category I. Each igniter is Revision 20 6.2-143 October, 2017
powered from a Class 1E power supply which can be powered from the associated division diesel generator.
g. All components in the HIS are capable of withstanding the temperature and pressure transients resulting from a LOCA. They can also withstand the humidity conditions and radiation environment in which the components are located. Environmental qualification of the hydrogen igniter assemblies is addressed in
<Section 3.11>, and dynamic qualification is addressed in <Section 3.10>.
h. HCS components located within the containment are demonstrated to survive the expected hydrogen combustion thermal environment where they are located.
i. Igniter locations were based on criteria that considered potential hydrogen release locations, appropriate spacing in open areas, redundancy and potential for pocketing in enclosed regions. Based on these criteria, igniters are located in a ring above the suppression pool and throughout the containment and drywell. The igniters are located approximately every 30 feet with alternating divisional power supplies, such that a distance of approximately 60 feet may exist if only one emergency power division is available. In some cases, a distance of 35 feet and 70 feet may exist if adequate supports are not available or interference exists in the area of interest. These criteria were used except in the open area above the refueling floor in the upper containment and in the reflood region in the drywell. Two igniters, one from each power division, are located in enclosed areas within containment which would be subject to possible hydrogen pocketing.
Revision 12 6.2-144 January, 2003 6.2.8.2 System Design A tabulation of the design and performance data for each system component is located in
. A detailed discussion of instrumentation features is provided in <Section 7.6>. The hydrogen control system (HCS) consists of 102 igniters distributed throughout the drywell and containment. The igniters are designed to ensure controlled burning of hydrogen produced during a hydrogen generation event. The igniter is a thermal ignition device that when activated (by an electric current) produces a resistance at the element (or tip) and an increase in temperature of at least 1,700F. This tip temperature is sufficient to cause combustion of the surrounding hydrogen gases at relatively low concentrations. The 102 igniters are glow plugs of the type commonly used in diesel engines. The igniter is mounted in an igniter assembly or housing with only the top (glow plug) exposed. The housing is constructed of stainless steel and contains a transformer with multiple taps to step down the voltage to each igniter from 120 volt ac, a terminal block for connection of internal wiring, and all of the associated electrical wiring required to make the assembly functional. The housing (assembly) is designed with a spray shield which extends over the glow plug tip, to protect against a reduction in tip temperature caused by the direct impingement of containment spray. A junction box is attached to the exterior of the assembly and contains the cable termination. Gasketing material and sealant are provided to ensure leak-tightness of the igniter enclosure and junction box. The 120 volt ac, 60 Hz, Class 1E power is supplied to the ignitor assemblies through hydrogen ignitor isolation panels. These isolation panels receive their power from Class 1E 480V motor control Revision 12 6.2-145 January, 2003 centers (MCC) through 15 kVA transformers, rated 480-208/120 volt ac, 60 Hz, 3-phases with grounded neutrals, and a fuse panel. The fuse panel consists of a 40 ampere and 45 ampere fuse in series for each line to the hydrogen ignitor isolation panels. Each transformer is fed from a Class 1E MCC which is capable of being powered from one of the standby diesel generators. The 102 igniters are divided into six groups of approximately equal number, three groups in Division 1 and three groups in Division 2. Each group is powered from a separate hydrogen ignitor isolation panel. Disconnect devices are provided for maintenance and are normally closed (NC) so the igniters can be energized by operating the control room handswitches. The HCS is manually energized by means of two handswitches located in the control room. There is one handswitch for the three Division 1 groups and one for the three Division 2 groups. The instrumentation and controls for the HCS are discussed in <Section 7.6>. The hydrogen igniters are arranged in several rings at different elevations within the drywell and containment. At least two igniters are located in each enclosed volume or area within the containment that are subject to possible hydrogen pocketing; each of the two igniters is powered from a separate power division to maintain divisional redundancy. <Figure 6.2-82> shows the locations of the igniter assemblies within containment. 6.2.8.3 Design Evaluation A preliminary evaluation of the PNPP hydrogen control system has been completed. This evaluation meets and exceeds the requirements of <10 CFR 50.44> for preliminary analysis. The details of the analysis are provided in (Reference 29). The program included definition of hydrogen generation events, determination of hydrogen and steam release Revision 12 6.2-146 January, 2003 histories for recoverable degraded cores, definition of hydrogen combustion thermal environments, and preliminary analyses of the survivability of essential equipment when exposed to the thermal and pressure environment inside containment during hydrogen combustion. An additional program of test and analysis has been conducted to support the final evaluation which was submitted to the NRC in accordance with <10 CFR 50.44>. The preliminary evaluation is based on the analyses of two degraded core accident scenarios. One scenario involved a stuck-open relief valve (SORV) accompanied by a failure of ECCS. The second scenario involved a small steam line break in the drywell (DWB). These two scenarios were selected to define temperature and pressure responses in the containment and drywell. The SORV transient scenario was considered to be the more probable event and to create a more thermally limiting environment in the containment. The drywell break scenario was chosen only because of the potential for hydrogen combustion in the drywell and therefore a limiting thermal environment in the drywell. For the two cases analyzed (using the CLASIX-3 code), the peak calculated containment pressure was approximately 21 psig and brief duration temperature peaks ranged from 643F in the drywell to 760F in the containment to 1,762F in the wetwell. The results are provided in
. The peak calculated containment pressure is significantly below the containment pressure vessel capability <Section 3.8.2.3.6>. Revision 20 6.2-147 October, 2017 A preliminary evaluation was performed to identify equipment inside containment that is required to survive a hydrogen burn. A list of equipment required to survive a hydrogen burn was established using the following criteria:
a. Equipment and systems which must function to mitigate the consequences of the event.
b. Equipment and structures required to maintain the integrity of the containment pressure boundary.
c. Systems and components required to maintain the core in a safe shutdown condition.
d. Instrumentation and systems which are used to monitor the course of the event and provide guidance to the operator for initiating actions in accordance with the emergency procedures.
e. Components whose failure could preclude the ability of the above systems to fulfill their intended functions.
The list of equipment required to survive a hydrogen burn is found in
and
. Preliminary equipment survivability was demonstrated by showing that the equipment survivability analyses performed for the Grand Gulf Nuclear Station (GGNS) are applicable to PNPP. The GGNS analyses had been previously reviewed and approved by the NRC. Equipment thermal survivability was demonstrated by comparing the temperature profiles, thermal response analysis and equipment list of PNPP to those of GGNS. The temperature profiles of the PNPP and GGNS CLASIX-3 containment response analyses are comparable with the exception of minor differences. Further analysis of the thermal response of the Revision 12 6.2-148 January, 2003 hydrogen igniter assembly showed that the PNPP CLASIX-3 temperature profile produced a lower maximum equipment temperature than the GGNS CLASIX-3 temperature profile. It was also shown that the list of equipment identified for PNPP was similar to that of GGNS. Therefore, it was concluded that the GGNS analyses are applicable to PNPP and that PNPP equipment will survive the temperatures produced during a hydrogen burn. Equipment pressure survivability was demonstrated by comparing the qualification or design pressure to calculated peak pressures. The qualification or design pressures of required equipment bound the calculated peak pressures
in all cases. 6.2.8.4 Testing and Inspection The hydrogen control system (HCS) is tested by energizing each igniter assembly, verifying a surface temperature of at least 1,700F for each accessible igniter and verifying by measurement, sufficient current/voltage to develop a surface temperature of 1,700F for each of the remaining igniters. Surveillance testing is periodically done by energizing all the igniter assemblies and performing a current and voltage measurement of each circuit to identify any inoperable igniters (see Technical Specifications). 6.2.8.5 Instrumentation Requirements Operation of the hydrogen control subsystems is performed manually. The controls are in the control room. The igniters are energized by means of two handswitches. There is one handswitch for the three Division 1 groups and one for the three Division 2 groups. The switch positions Revision 12 6.2-149 January, 2003 are OFF-NORM-ON with red-green indication lights. Input is provided to the hydrogen control system out-of-service annunciator in the control room on loss of control or motive power. 6.

2.9 REFERENCES

FOR SECTION 6.2

1. Bilanin, W. J., The General Electric Mark III Pressure Suppression Containment Analytical Model, General Electric Company, NEDO-20533, June 1974.
2. Bilanin, W. J., The General Electric Mark III Pressure Suppression Containment Analytical Model, Supplement 1, General Electric Company, NEDO-20533-1, September 1975.
3. Moody, F. J., Maximum Two Phase Vessel Blowdown from Pipes, General Electric Company, Topical Report APED-4827, 1965.
4. General Electric Company, Drywell Integrity Study: Investigation of Potential Cracking for BWR6/Mark III Containment, Licensing Topical Report NEDO-10977, August 1973.
5. Modified version of CONTEMPT-LT: L. L. Wheat, R. J. Wagner, G. F. Niederauer, and C. F. Ohenchain, CONTEMPT - A Computer Program for Predicting the Containment Pressure - Temperature Response to a Loss-of-Coolant Accident, RNCR-1219, June 1975.
6. Savery, W. C., Huang, Y. S., and Kowal, G. M., Simulation of Hypothetical High Pressure Line Rupture Accidents in Sub-Divided Buildings, presented at the 1974 American Nuclear Society Winter Meeting, Washington, D.C., October 27-31, 1974.
7. Institute of Electrical and Electronics Engineers, Qualifying Class 1E Electric Equipment for Nuclear Power Generating Stations, IEEE Standard 323, 1974.

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8. Institute of Electrical and Electronics Engineers, Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, IEEE Standard 344, 1975.
9. Institute of Electrical and Electronics Engineers, Criteria for Protection Systems for Nuclear Power Generating Stations, IEEE Standard 279, 1971.
10. Institute of Electrical and Electronic Engineers, Criteria for Separation of Class 1E Equipment and Circuits, IEEE Standard 384, 1972.
11. Gido, R. G., Grimes, C. I., Lawton, R. G., and Kudrick, J. A.,

COMPARE: A Computer Program for the Transient Calculation of a System of Volumes Connected by Flowing Vents, U.S. Nuclear Regulatory Commission, LA-NUREG-6488-MS, September 1976.

12. Moore, K. V., Rettig, N. H., RELAP4/MOD3 - A Computer Program for Transient Thermal Hydraulic Analysis, Aerojet Nuclear Co.,

TID-4500, December 1973.

13. McAdams, William H., Heat Transmission, MGraw-Hill Book Company, Inc.
14. Institute of Electrical and Electronics Engineers, Type Tests of Continuous Duty Class 1E Motors for Nuclear Power Generating Stations, IEEE Standard 334, 1975.
15. Shapiro, Z. M., Moffette, T. R., Hydrogen Flammability Data and Application to PWR Loss-of-Coolant Accident, WAPD-SC-545, September 1957.
16. WCAP 7709-L, Supplement 1, Electric Hydrogen Recombiner, April 1972.

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17. WCAP 7709-L, Supplement 2, Electric Hydrogen Recombiner Equipment Qualification Report, September 1973.
18. WCAP 7709-L, Supplement 3, Electric Hydrogen Recombiner Long Term Tests, January 1974.
19. WCAP 7709-L, Supplement 4, Electric Hydrogen Recombiner, April 1972.
20. (Deleted)
21. (Deleted)
22. Daniel Van Rooyen, Hydrogen Release Rates From Corrosion of Zinc and Aluminum, BNL-NUREG-24532, May 1978.
23. National Association of Corrosion Engineers, Corrosion Data Survey, 1967.
24. (Deleted)
25. Flow of Fluids Through Valves, Fittings and Pipe, Crane Technical Paper No. 410
26. General Electric Nuclear Data Package 22A6926, Revision 0, Sheets 29 through 31, 6-15-79 BWR Equipment Environmental Interface Data.
27. (Deleted)
28. (Deleted)
29. Cleveland Electric Illuminating Co., Preliminary Evaluation of the Perry Nuclear Power Plant Hydrogen Control System, March 21, 1985.

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30. Letter, M. R. Edelman (CEI) to W. R. Butler (NRC), Combustible Gas Control, PY-CEI/NRR-0502L, July 17, 1986.
31. Young, C. T., Perry Technical Specifications Improvement-Contain-ment Response Analysis, General Electric Company, NEDC-31940, March 1991.
32. Letter, M. D. Lyster (Centerior) to USNRC, Revisions to the Suppression Pool Makeup Specification to Operate with a Reduced Upper Containment Pool Water Level Provided the Suppression Pool Water is Raised to Compensate, PY-CEI/NRR-1537L, November 16, 1992.
33. (Deleted)
34. Utility Resolution Guidance for ECCS Suction Strainer Blockage, NEDO-32686, November 1996.
35. License Amendment No. 100 dated February 24, 1999, D. Pickett (NRC) to L. Myers (FENOC).
36. License Amendment No. 21 dated May 23, 1989, T. Colburn (NRC) to A. Kaplan (CEI).
37. GE Data Book 22A3759AL Rev. 2, March 29, 1991, Containment and NSSS Interface.
38. NUREG-0800 SRP 6.2.1.1.c, Pressure-Suppression Type BWR Containment.
39. License Amendment No. 123 dated March 7, 2003, S. Sands (NRC) to W. Kanda (FENOC).

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40. (Deleted)
41. License Amendment No. 174 dated February 16, 2017.

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TABLE 6.2-1 KEY DESIGN AND MAXIMUM ACCIDENT PARAMETERS FOR PRESSURE SUPPRESSION CONTAINMENT Maximum Design Calculated Parameter Value Accident Value Containment Pressure, psig 15 6.4 Suppression Pool Temperature, F 185 181.3 Drywell Pressure, psig 30 23.45 Drywell Temperature, F 330 329.0 Revision 14 6.2-154 October, 2005

TABLE 6.2-2 CONTAINMENT DESIGN PARAMETERS Drywell Containment Drywell and Containment Negative Design Pressure, psig -21.0 -0.8 Positive Design Pressure, psig 30 15 Design Temperature, F 330 185 Maximum Allowable Leak Rate A / K = 1.68 ft2 0.2%/day Suppression Pool Depth, ft Low Level 17.79 17.79 High Level 18.5 18.5 Vent System Number of Vents 120 Nominal Vent Diameter, ft 2.29 Total Vent Area, ft2 495 Vent Centerline Submergence (low level), ft Top Row 6.5 Middle Row 11.0 Bottom Row 15.5 Vent Loss Coefficient (varies with number of vents open) 2.5-3.5 Revision 12 6.2-155 January, 2003

TABLE 6.2-3 ENGINEERED SAFETY FEATURE SYSTEMS PERFORMANCE PARAMETERS FOR CONTAINMENT RESPONSE ANALYSES Full Containment Analysis Value Capacity Case A Case B Containment Spray Number of RHR Pumps 2 0 0 Number of Lines 2 0 0 Number of Heat Exchangers 2 0 0 Flow Rate, gpm/pump 5,250 0 0 Containment Cooling System Number of RHR Pumps 2 2 1 Pump Capacity, gpm/pump 7,100 7,100 7,100 RHR Heat Exchangers Type Inverted U-tube, single pass shell, multipress tube, vertical mounting Number 2 2 1 Heat Transfer Area, ft2/unit 14,850 - -

Overall Heat Transfer Coefficient, Btu/hr-ft2-F/unit 200 - -

Emergency Service Water Temperature,F Minimum Design 32 - -

Maximum Design 85 85 85 Revision 13 6.2-156 December, 2003

TABLE 6.2-3 (Continued)

Full Containment Analysis Value Capacity Case A Case B Containment Heat Removal Capability (using 85F emergency service water and 185F pool temperature),

Btu/hr/unit 158.4E+06 - -

Revision 12 6.2-157 January, 2003

TABLE 6.2-4 ACCIDENT ASSUMPTIONS AND INITIAL CONDITIONS FOR CONTAINMENT RESPONSE ANALYSES (at 3833 MWt)

Components of Effective Break Area (Recirculation Line Break), ft2 Recirculation Line 2.127 Cleanup Line 0.080 Jet Pumps 0.468 Primary Steam Energy Distribution(1), 106 Btu Steam Energy 23.6 Liquid Energy 299.6 Sensible Energy Reactor Vessel 89.62 Reactor Internals (less core) 51.59 Primary System Piping 35.55 Fuel(2) 7.3 Other Assumptions Used in Analysis Main Steam Closure Time, sec Recirculation Break 3.5 Main Steam Line Break 5.5 Scram Time, sec <1 NOTES:

(1)

All energy values, except fuel, are based upon a 32F datum.

(2)

Fuel energy is based upon a datum of 285F.

Revision 12 6.2-158 January, 2003

TABLE 6.2-5 INITIAL CONDITIONS EMPLOYED IN CONTAINMENT RESPONSE ANALYSES (at 3833 MWt)

Drywell Free Volume, ft3 279,528 Containment Free Volume, ft3 1.156 x 106 Drawdown makeup system capacity, ft3 32,573 Temperature of makeup water, F 110 Suppression Pool Volume for Long Term Response Calculations, ft3 (assumes initial pool level of 17.79 feet when drywell-to-containment dP is 2.0 psig, and includes the upper pool dump volume.) 144,292 Suppression Pool Volume for Short Term Response Calculations, ft3 (assumes initial pool level of 18.5 feet when drywell-to-containment dP is -0.5 psig.) 118,131 Horizontal Vent I.D., inches 27.5 Total Number of Vents 120 Weir Annulus Width, inches 27.25 Submergence of Vent Centerline - 1st vent, ft 7.5 (HWL-STR) 6.5 (LWL-LTR)

Submergence of Vent Centerline - 2nd vent, ft 12.0-STR 11.0-LTR Submergence of Vent Centerline - 3rd vent, ft 16.5-STR 15.5-LTR Net Vent Area, ft2 495 Drywell Air Temperature, F 60-145(2)

(145 for long-term response; 135 for short-term response)

Revision 12 6.2-159 January, 2003

TABLE 6.2-5 (Continued)

Drywell Pressure, psig -0.5 to 2.0(2)

(2.0 for long-term response; 0.5 for short-term response)

Drywell Humidity, % normal; 40-50; (40)(2)

Containment Air Temperature, F normal; 95 (104)(2)

Containment Pressure, psig -0.1 to 1.0(2)

(0 for long-term response; 1 for short-term response)

Containment Humidity, % normal; 50-60; (50)(2)

Reactor Primary System Data Reactor Power, MWt 3,833 Vessel Steam Output, lbm/hr 16,689,000 Steam Dome Pressure, psia 1,060 Total Reactor Fluid Inventory, lbm 5.641E5 Total Mass of Vessel and Internal Structures, lb (not including fuel) 2.764E6 Total Mass of UO2 in core, lbm 3.416 x 105 Total Mass of Active Zircaloy in core, lbm 80,694 Main Steam Line Isolation Valve Closure Period, sec 4 1(1)

NOTES:

(1)

For mass release calculations, 0.5 seconds must be added to account for instrumentation time needed to initiate main steam line isolation valve closure.

(2)

The analyses are valid for the values and ranges shown. Values actually used in the analyses are shown in parentheses.

Revision 12 6.2-160 January, 2003

TABLE 6.2-6

SUMMARY

OF SHORT TERM CONTAINMENT RESPONSES TO RECIRCULATION LINE AND MAIN STEAM LINE BREAKS (up to 30 seconds)

Recirculation Main Steam Line Break Line Break Peak Drywell Pressure, psig 22.84 23.45 Peak Drywell Differential Pressure, psid 21.07 21.35 Time of Peak Pressure, sec 1.79 1.80 Peak Drywell Temperature, F 308.3 329.0 Peak Wetwell Pressure, psig 6.6 11.4 Time of Peak Wetwell Pressure, sec 3.0 3.0 Calculated Drywell Margin, % 23.9 21.8 Revision 12 6.2-161 January, 2003

TABLE 6.2-7

SUMMARY

OF LONG TERM CONTAINMENT RESPONSES TO RECIRCULATION LINE OR MAIN STEAM LINE BREAK (at 3729 MWt)

Case A(1) Case B1(2)

Peak Containment Pressure, psig 5.8 7.8 Time of Peak Containment Pressure, sec 67,953 99,853 Peak Suppression Pool Temperature, F 178.6 182.7 Calculated Containment Margin, % 61.4 48.3 HPCS Flow Rate, gpm 6,000 6,000 LPCS Flow Rate, gpm 6,000 6,000 RHRS Flow Rate, gpm 14,200(3) 7,100(3) 7,100(4) 7,100(4)

NOTES:

(1)

Case A - Offsite Power Available, All ECCS Equipment Operating.

(2)

Case B1 - Loss-of-Offsite Power, Minimum ECCS Equipment Operating.

(3)

Suppression Pool Cooling Flow; None for First 30 minutes.

(4)

LPCI Mode of RHR.

Revision 12 6.2-162 January, 2003

TABLE 6.2-7a

SUMMARY

OF LONG TERM CONTAINMENT RESPONSES TO RECIRCULATION LINE OR MAIN STEAM LINE BREAK (at 3833 MWt)

Case B2(1)

Peak Containment Pressure, psig 6.4 Time of Peak Containment Pressure, sec 31,308 Peak Suppression Pool Temperature, F 181.3 Calculated Containment Margin, % 56.7 HPCS Flow Rate, gpm 7,000 LPCS Flow Rate, gpm 7,000 RHRS Flow Rate, gpm 7,100(2) 7,100(3)

NOTES:

(1)

Case B2 - Loss-of-Offsite Power, Minimum ECCS Equipment Operating.

(2)

Suppression Pool Cooling Flow; None for First 30 minutes.

(3)

LPCI Mode of RHR.

Revision 14 6.2-163 October, 2005

TABLE 6.2-8 ENERGY BALANCE FOR MAIN STEAM LINE BREAK ACCIDENT (at 3729 MWt)

Energy (Btu)

Initial Drywell End of Long Term Peak (time zero) Peak Pressure Blowdown Wetwell Pressure Reactor Coolant 3.2E+08 2.9E8 1.8E8 1.7E8 Fuel and Cladding Fuel 7.3E6 7.2E+06 0 0 Cladding 3.4E+06 3.4E+06 3.1E6 1.4E6 Core Internals 8.4E7 8.4E7 7.4E7 3.5E7 Reactor Vessel 9.0E7 9.0E7 8.4E7 4.6E7 Metal Reactor Coolant Included in Core Internals, above.

System Piping, Pumps, and Valves Blowdown Enthalpy Liquid 0 0 0 0 Steam 0 3.4E7 4.1E8 4.1E9 Decay Heat 0 1.4E6 8.1E7 3.2E9 Metal-Water Reaction Heat 0 6.1E4 1.9E6 1.9E6 Drywell Structures 4.3E7 4.3E7 4.5E7 8.2E7 Drywell Air 2.0E6 4.5E5 0 0 Drywell Steam 1.1E6 1.4E7 1.8E7 2.2E7 Containment Air 7.6E+06 9.7E6 1.0E+07 1.0E7 Containment Steam 1.9E6 2.5E+06 2.7E6 9.8E6 Suppression Pool 4.0E8 4.3E8 7.7E8 1.2E9 Water Revision 12 6.2-164 January, 2003

TABLE 6.2-8 (Continued)

Energy (Btu)

Initial Drywell End of Long Term Peak (time zero) Peak Pressure Blowdown Wetwell Pressure Upper Pool Dump 1.6 1.6 1.6 0 Inventory Energy Transferred 0 0 0 3.9E+08 by Heat Exchangers Passive Heat Sinks(1) 6.4E7 6.4E7 6.4E7 8.4E7 (in Containment Airspace and Suppression Pool)

NOTE:

(1)

A new strainer design, which has the strainer resting on the floor of the suppression pool, replaces the individual strainers for the ECCS and RCIC system pumps in response to <NRC Bulletin 96-03>. The new strainer adds ~426 ft3 of steel to the suppression pool, however, the strainer displaces ~426 ft3 of suppression pool water. Analysis has shown that the addition of the strainers steel and displacement of the water results in a negligible effect on the passive heat sinks available in the suppression pool and does not invalidate existing analyses.

Revision 12 6.2-165 January, 2003

TABLE 6.2-9 ACCIDENT CHRONOLOGY FOR MAIN STEAM LINE BREAK ACCIDENT (at 3729 MWt)

Time (sec)

All ECCS Minimum ECCS Event in Operation Available First Row Vent Cleared 0.934 0.934 Second Row Vent Cleared 1.171 1.171 Third Row Vent Cleared 1.550 1.550 Drywell Reaches Peak Pressure 3.733 3.733 Maximum Positive Differential Pressure Occurs 1.28 1.28 Third Row Vent Recovered 28.4 28.4 Initiation of ECCS Operation 30 30 Second Row Vent Recovered 47.8 47.8 End of Blowdown 319 360 First Row Vent Recovered 344 344 Initiation of RHR Heat Exchanger Operation 1,980 1,980 Containment Peak Pressure Reached 67,953 99,853 Revision 12 6.2-166 January, 2003

TABLE 6.2-10 AVAILABLE CONTAINMENT HEAT SINKS Surface Item Volume (ft3) Area (ft2) Material Drywell Structures 4,556 54,891 Concrete Containment Shell 9,122 72,975 Steel Miscellaneous Steel Structures and Equipment 7,512(1) 169,189 Steel Miscellaneous Concrete Structures 38,836 21,360 Concrete NOTE:

(1)

A new strainer design, which has the strainer resting on the floor of the suppression pool, replaces the individual strainers for the ECCS and RCIC system pumps in response to <NRC Bulletin 96-03>. The new strainer adds ~426 ft3 of steel to the suppression pool, however, the strainer displaces ~426 ft3 of suppression pool water. Analysis has shown that the addition of the strainers steel and displacement of the water results in a negligible effect on the passive heat sinks available in the suppression pool and does not invalidate existing analyses.

Revision 12 6.2-167 January, 2003

DELETED Revision 12 6.2-168 January, 2003 TABLE 6.2-12 REACTOR ANNULUS
a. Recirculation Suction Line Biological Shield Wall Control Volume Bottom Initial Conditions Calculated Design Volume Height Volume Flow Area Elevation Temperature Pressure Peak P(1)(2) Pressure(2)
No. Description (ft) (ft3) (ft2) (ft) (F) (psia) Quality (psid) (psid) 1 Volume 1 - Level 1 5.81 91.56 16.80 6.83 212.0 14.696 0.926 22.06 28.78 2 Volume 2 - Level 1 8.71 138.46 16.80 6.83 212.0 14.696 0.926 9.44 12.59 3 Volume 3 - Level 1 8.71 142.96 16.80 6.83 212.0 14.696 0.926 5.66 8.81 4 Volume 4 - Level 1 8.71 205.13 25.20 6.83 212.0 14.696 0.926 2.06 3.43 5 Volume 5 - Level 1 8.71 212.77 25.20 6.83 212.0 14.696 0.926 0.40 0.71 6 Volume 6 - Level 2 5.81 82.56 16.80 18.44 212.0 14.696 0.926 8.13 10.37 7 Volume 7 - Level 2 8.71 128.13 16.80 15.54 212.0 14.696 0.926 4.44 5.71 8 Volume 8 - Level 2 8.71 132.63 16.80 15.54 212.0 14.696 0.926 3.65 5.38 9 Volume 9 - Level 2 8.71 195.00 25.20 15.54 212.0 14.696 0.926 1.23 2.07 10 Volume 10 - Level 2 8.71 210.31 25.20 15.54 212.0 14.696 0.926 0.15 0.31 11 Volume 11 - Level 3 6.875 100.64 16.80 24.25 212.0 14.696 0.926 6.02 8.34 12 Volume 12 - Level 3 6.875 112.45 16.80 24.25 212.0 14.696 0.926 3.39 5.01 13 Volume 13 - Level 3 6.875 112.45 16.80 24.25 212.0 14.696 0.926 2.61 4.14 14 Volume 14 - Level 3 6.875 166.72 25.20 24.25 212.0 14.696 0.926 0.68 1.16 15 Volume 15 - Level 3 6.875 174.59 25.20 24.25 212.0 14.696 0.926 0.09 0.21 16 Volume 16 - Level 4 6.925 147.00 25.20 31.125 212.0 14.696 0.926 3.13 4.94 17 Volume 17 - Level 4 6.925 158.88 25.20 31.125 212.0 14.696 0.926 1.63 2.60 18 Volume 18 - Level 4 6.925 166.76 25.20 31.125 212.0 14.696 0.926 0.36 0.63 19 Volume 19 - Level 4 6.925 174.57 25.20 31.125 212.0 14.696 0.926 0.03 0.10 20 Volume 20 - Level 4 13.66 297.69 25.20 38.05 212.0 14.696 0.926 0.00 0.04 21 Volume 21 - Level 4 13.66 325.41 25.20 38.05 212.0 14.696 0.926 0.10 0.22 22 Volume 22 - Level 4 13.66 316.20 25.20 38.05 212.0 14.696 0.926 0.00 0.04 23 Volume 23 - Level 4 13.66 344.37 25.20 38.05 212.0 14.696 0.926 0.00 0.00 24 Volume 24 - Drywell 90.00 139,000.0 1544.0 0.0 212.0 14.696 0.52 - - 25 Volume 25 - Blowdown Node 5.80 71.48 16.80 12.64 212.0 14.696 0.926 17.10 22.90 26 Volume 26 - Level 5 6.50 188.25 25.20 51.71 212.0 14.696 0.926 0.00 0.01 27 Volume 27 - Level 5 6.50 178.42 25.20 51.71 212.0 14.696 0.926 0.00 0.03 28 Volume 28 - Level 5 6.50 178.42 25.20 51.71 212.0 14.696 0.926 0.00 0.00 29 Volume 29 - Level 5 6.50 188.25 25.20 51.75 212.0 14.696 0.926 0.00 0.00 Revision 12 6.2-169 January, 2003 TABLE 6.2-12 (Continued)
b. Recirculation Discharge Line Biological Shield Wall Control Volume Bottom Initial Conditions Calculated Design Volume Height Volume Flow Area Elevation Temperature Pressure Peak P(1)(2) Pressure(2)
No. Description (ft) (ft3) (ft2) (ft) (F) (psia) Quality (psid) (psid) 1 Volume 1 - Level 1 5.81 91.56 16.80 6.83 212.0 14.696 0.926 31.49 44.09 2 Volume 2 - Level 1 8.71 138.46 16.80 6.83 212.0 14.696 0.926 11.80 16.51 3 Volume 3 - Level 1 8.71 142.96 16.80 6.83 212.0 14.696 0.926 8.19 11.47 4 Volume 4 - Level 1 8.71 205.13 25.20 6.83 212.0 14.696 0.926 3.03 4.23 5 Volume 5 - Level 1 8.71 212.77 25.20 6.83 212.0 14.696 0.926 0.65 0.91 6 Volume 6 - Level 2 5.81 82.56 16.80 18.44 212.0 14.696 0.926 12.79 17.89 7 Volume 7 - Level 2 8.71 128.13 16.80 15.54 212.0 14.696 0.926 5.90 8.26 8 Volume 8 - Level 2 8.71 132.63 16.80 15.54 212.0 14.696 0.926 4.27 5.96 9 Volume 9 - Level 2 8.71 195.00 25.20 15.54 212.0 14.696 0.926 1.74 2.44 10 Volume 10 - Level 2 8.71 210.31 25.20 15.54 212.0 14.696 0.926 0.28 0.39 11 Volume 11 - Level 3 6.875 100.64 16.80 24.25 212.0 14.696 0.926 8.98 12.57 12 Volume 12 - Level 3 6.875 112.45 16.80 24.25 212.0 14.696 0.926 4.74 6.64 13 Volume 13 - Level 3 6.875 112.45 16.80 24.25 212.0 14.696 0.926 3.55 4.96 14 Volume 14 - Level 3 6.875 166.72 25.20 24.25 212.0 14.696 0.926 1.05 1.47 15 Volume 15 - Level 3 6.875 174.59 25.20 24.25 212.0 14.696 0.926 0.20 0.28 16 Volume 16 - Level 4 6.925 147.00 25.20 31.125 212.0 14.696 0.926 4.41 6.16 17 Volume 17 - Level 4 6.925 158.88 25.20 31.125 212.0 14.696 0.926 2.26 3.16 18 Volume 18 - Level 4 6.925 166.76 25.20 31.125 212.0 14.696 0.926 0.56 0.78 19 Volume 19 - Level 4 6.925 174.57 25.20 31.125 212.0 14.696 0.926 0.10 0.13 20 Volume 20 - Level 4 13.66 297.69 25.20 38.05 212.0 14.696 0.926 0.04 0.06 21 Volume 21 - Level 4 13.66 325.41 25.20 38.05 212.0 14.696 0.926 0.20 0.28 22 Volume 22 - Level 4 13.66 316.20 25.20 38.05 212.0 14.696 0.926 0.04 0.06 23 Volume 23 - Level 4 13.66 344.37 25.20 38.05 212.0 14.696 0.926 0.00 0.00 24 Volume 24 - Drywell 90.00 139,000.0 1544.0 0.0 212.0 14.696 0.52 - - 25 Volume 25 - Blowdown Node 5.80 71.48 16.80 12.64 212.0 14.696 0.926 28.19 39.47 26 Volume 26 - Level 5 6.50 188.25 25.20 51.71 212.0 14.696 0.926 0.02 0.03 27 Volume 27 - Level 5 6.50 178.42 25.20 51.71 212.0 14.696 0.926 0.03 0.04 28 Volume 28 - Level 5 6.50 178.42 25.20 51.71 212.0 14.696 0.926 0.00 0.00 29 Volume 29 - Level 5 6.50 188.25 25.20 51.75 212.0 14.696 0.926 0.00 0.00 NOTES: (1) With respect to drywell. (2) Biological shield wall design pressures are for time-step 0.024 seconds. A study was performed to determine which pressure loading would cause maximum shear and moment at the base of the structure. The controlling time-step pressures (0.024 sec for recirculation discharge break) were then used as the design loading case. Revision 12 6.2-170 January, 2003 TABLE 6.2-13 REACTOR ANNULUSFEEDWATER LINE BREAK Biological Shield Wall Control Volume Bottom Initial Conditions Calculated Design Volume Height Volume Flow Area Elevation Temperature Pressure Peak P(1)(2) Pressure(2) No. Description (ft) (ft3) (ft2) (ft) (F) (psia) Quality (psid) (psid) 1 Volume 1 - Level 1 9.44 137.31 16.93 5.5 212.0 14.696 0.926 14.04 19.66 2 Volume 2 - Level 1 9.44 205.27 25.39 5.5 212.0 14.696 0.926 14.03 19.64 3 Volume 3 - Level 1 9.44 272.93 33.86 5.5 212.0 14.696 0.926 14.05 19.66 4 Volume 4 - Level 1 9.44 280.55 33.86 5.5 212.0 14.696 0.926 14.29 20.01 5 Volume 5 - Level 1 9.44 284.02 33.86 5.5 212.0 14.696 0.926 14.11 19.75 6 Volume 6 - Level 1 9.44 282.10 33.86 5.5 212.0 14.696 0.926 14.00 19.60 7 Volume 7 - Level 1 9.44 179.28 25.39 5.5 212.0 14.696 0.926 14.04 19.66 8 Volume 8 - Level 2 9.44 121.97 16.93 14.94 212.0 14.696 0.926 17.49 24.49 9 Volume 9 - Level 2 9.44 200.65 25.39 14.94 212.0 14.696 0.926 16.81 23.53 10 Volume 10 - Level 2 9.44 272.93 33.86 14.94 212.0 14.696 0.926 15.65 21.91 11 Volume 11 - Level 2 9.44 293.93 33.86 14.94 212.0 14.696 0.926 14.27 19.98 12 Volume 12 - Level 2 9.44 292.15 33.86 14.94 212.0 14.696 0.926 14.38 20.12 13 Volume 13 - Level 2 9.44 266.93 33.86 14.94 212.0 14.696 0.926 15.07 21.10 14 Volume 14 - Level 2 9.44 189.49 25.39 14.94 212.0 14.696 0.926 16.50 23.10 15 Volume 15 - Level 3 6.50 94.81 16.93 24.38 212.0 14.696 0.926 16.35 22.89 16 Volume 16 - Level 3 6.50 149.73 25.39 24.38 212.0 14.696 0.926 17.19 24.07 17 Volume 17 - Level 3 6.50 207.92 33.86 24.38 212.0 14.696 0.926 15.55 21.77 18 Volume 18 - Level 3 6.50 219.92 33.86 24.38 212.0 14.696 0.926 13.60 19.04 19 Volume 19 - Level 3 6.50 219.63 33.86 24.38 212.0 14.696 0.926 14.55 20.37 20 Volume 20 - Level 3 6.50 201.92 33.86 24.38 212.0 14.696 0.926 15.34 21.46 21 Volume 21 - Level 3 6.50 146.89 25.39 24.38 212.0 14.696 0.926 16.52 23.13 22 Volume 22 - Level 4 6.50 99.81 16.83 30.88 212.0 14.696 0.926 17.37 24.32 23 Volume 23 - Level 4 6.50 149.87 30.88 30.88 212.0 14.696 0.926 16.97 23.76 24 Volume 24 - Level 4 6.50 202.63 33.86 30.88 212.0 14.696 0.926 15.14 21.18 25 Volume 25 - Level 4 6.50 220.09 33.86 30.88 212.0 14.696 0.926 9.83 13.76 26 Volume 26 - Level 4 6.50 220.09 33.86 30.88 212.0 14.696 0.926 14.83 20.75 27 Volume 27 - Level 4 6.50 220.63 33.86 30.88 212.0 14.696 0.926 15.23 21.32 28 Volume 28 - Level 4 6.50 154.83 35.39 30.88 212.0 14.696 0.926 13.57 19.00 29 Volume 29 - Level 5 6.50 93.88 17.33 37.38 212.0 14.696 0.926 69.59 97.43 30 Volume 30 - Level 5 6.50 120.07 17.33 37.38 212.0 14.696 0.926 159.01 222.61 31 Volume 31 - Level 5 6.50 194.00 17.33 37.38 212.0 14.696 0.926 16.14 22.60 32 Volume 32 - Level 5 6.50 211.46 17.33 37.38 212.0 14.696 0.926 0.58 0.81 33 Volume 33 - Level 5 6.50 209.67 17.33 37.38 212.0 14.696 0.926 8.56 11.98 34 Volume 34 - Level 5 6.50 182.96 17.33 37.38 212.0 14.696 0.926 12.88 18.03 35 Volume 35 - Level 5 6.50 134.20 17.33 37.38 212.0 14.696 0.926 21.52 30.13 36 Volume 36 - Level 6 6.50 102.43 17.33 43.88 212.0 14.696 0.926 15.22 21.31 37 Volume 37 - Level 6 6.50 157.45 17.33 43.88 212.0 14.696 0.926 12.95 18.13 38 Volume 38 - Level 6 6.50 212.51 17.33 43.88 212.0 14.696 0.926 1.71 2.39 Revision 12 6.2-171 January, 2003 TABLE 6.2-13 (Continued) Biological Shield Wall Control Volume Bottom Initial Conditions Calculated Design Volume Height Volume Flow Area Elevation Temperature Pressure Peak P(1)(2) Pressure(2) No. Description (ft) (ft3) (ft2) (ft) (F) (psia) Quality (psid) (psid) 39 Volume 39 - Level 6 6.50 220.01 17.33 43.88 212.0 14.696 0.926 0.00 0.00 40 Volume 40 - Level 6 6.50 219.86 17.33 43.88 212.0 14.696 0.926 4.68 6.55 41 Volume 41 - Level 6 6.50 212.51 17.33 43.88 212.0 14.696 0.926 15.49 21.69 42 Volume 42 - Level 6 6.50 155.98 17.33 43.88 212.0 14.696 0.926 21.30 29.82 43 Volume 43 - Level 7 6.50 102.43 16.93 50.38 212.0 14.696 0.926 0.02 0.0 44 Volume 44 - Level 7 6.50 142.39 25.39 50.38 212.0 14.696 0.926 0.00 0.0 45 Volume 45 - Level 7 6.50 204.82 33.86 50.38 212.0 14.696 0.926 0.00 0.0 46 Volume 46 - Level 7 6.50 212.32 33.86 50.38 212.0 14.696 0.926 0.40 0.56 47 Volume 47 - Level 7 6.50 219.86 33.86 50.38 212.0 14.696 0.926 0.12 0.17 48 Volume 48 - Level 7 6.50 186.82 33.86 50.38 212.0 14.696 0.926 0.00 0.0 49 Volume 49 - Level 7 6.50 148.79 25.39 50.38 212.0 14.696 0.926 0.00 0.0 50 Volume 50 - Drywell 90.0 278,000 3089.0 0.0 212.0 14.696 0.52 - - NOTES: (1) With respect to drywell. (2) Biological shield wall design pressures are for time-step 0.500 seconds. A study was performed to determine which time-step pressures would cause maximum shear and moment at the base of the structure. The controlling time-step pressures (at 0.500 sec for feedwater break) were then used as the design loading case. Revision 12 6.2-172 January, 2003 TABLE 6.2-14 DRYWELL HEAD REGION ANALYSIS Initial Conditions Calculated Design Control Volume Temperature Pressure Rel. Hum. Peak P(1) Pressure Volume No. Description (ft3) (F) (psia) (%) (psid) (psid) 1 Drywell Head 7,610 150 14.696 100 6.6 9.2 2 Drywell 2.70E+05 150 14.696 0 - - NOTE: (1) Calculated peak pressure differentials are with respect to containment. Revision 12 6.2-173 January, 2003 TABLE 6.2-15 STEAM TUNNEL Initial Conditions Calculated Design Control Volume Temperature Pressure Rel. Hum. Peak P(1) Pressure Volume No. Description (ft3) (F) (psia) (%) (psid) (psid) 1 Steam Tunnel 8,950 144 14.696 100 0.88 1.6 Inside Contain-ment 2 Containment 1.156E+06 120 14.696 100 - - NOTE: (1) Calculated peak pressure differentials are with respect to containment. Revision 15 6.2-174 October, 2007 TABLE 6.2-16 REACTOR WATER CLEANUP ROOMS ANALYSIS Initial Conditions Calculated Design Control Volume Temperature Pressure Rel. Hum. Peak P(1) Pressure Volume No. Description (ft3) (F) (psia) (%) (psid) (psid) 1 RWCU Heat 12,600 120 14.696 100.0 8.05 10.9 Exchanger Room 2 Corridor 412 120 14.696 100.0 - - 3 Containment 1.156+6 120 14.696 100.0 - - 1 RWCU Filter Demineralizer Valve Room 6,580 120 14.696 100.0 7.18 9.3 2 Corridor 302 120 14.696 100.0 - - 3 Containment 1.156+6 120 14.696 100.0 - - 1 RWCU Filter Demineralizer Room 3,430 120 14.696 100.0 4.89 6.3 2 Containment 1.156+6 120 14.696 100.0 - - 1 RWCU Drain Valve Nest Room 2,915 120 14.696 100.0 8.33 10.8 2 Corridor 179 120 14.696 100.0 - - 3 Containment 1.156+6 120 14.696 100.0 - - NOTE: (1) Calculated peak pressure differentials are with respect to containment. Revision 15 6.2-175 October, 2007 TABLE 6.2-16a DRYWELL BULKHEAD PLATE P ANALYSIS VOLUME DESCRIPTION Initial Conditions Calculated Design Control Volume Temperature Pressure Rel. Hum. Peak P(1) Pressure Volume No. Description (ft3) (F) (psia) (%) (psid) (psid) 1 252 to 288 365 145 14.696 50 28.0 30.0 2 217 to 252 364 145 14.696 50 27.8 30.0 3 288 to 72 1,499 145 14.696 50 4.0 30.0 4 72 to 217 1,491 145 14.696 50 4.0 30.0 5 Head Region 7,610 145 14.696 50 6 Inside Bio-Wall 10,367 145 14.696 50 7 Remainder of Drywell 255,990 145 14.696 50 NOTE: (1) Differential pressure across bulkhead plate. Revision 12 6.2-176 January, 2003 TABLE 6.2-17 MASS AND ENERGY RELEASES
a. From Recirculation Suction Line Break With One Inch Flow Diverter Time Into Annulus Into Drywell Enthalpy (sec) (lbm/sec) (lbm/sec) (Btu/lbm) 0 2,642.6 1,570.2 533 1.0 2,638.2 1,567.6 533 2.0 2,635.2 1,568.2 533
b. Into Annulus from Recirculation Discharge Break Time Mass Flow Rate Enthalpy (Sec) (lbm/sec) (Btu/lbm) 0.0 3,802.5 551.5 2.0 3,802.5 551.5 Revision 12 6.2-177 January, 2003
TABLE 6.2-18 MASS AND ENERGY INTO REACTOR ANNULUS DUE TO FEEDWATER BREAK USED FOR ANALYSIS Time Mass Enthalphy (Sec) (lbm/sec) (Btu/lbm) 0.0 5,515.0 497.4 0.00075 11,575.0 497.4 0.00175 9,833.3 497.4 0.00875 9,050.0 497.4 0.01105 9,270.0 497.4 0.0401 11,023.3 497.4 0.0521 12,421.7 497.4 0.0761 12,421.7 497.4 0.1001 13,423.3 497.4 0.1961 12,613.3 497.4 0.4941 13,596.7 497.4 0.7376 13,880.0 497.4 1.0 13,240.0 497.4 2.0 13,240.0 497.4 Revision 12 6.2-178 January, 2003 TABLE 6.2-19 REACTOR WATER CLEANUP SYSTEM DOUBLE ENDED PIPE BREAK(1) LIQUID BLOWDOWN Time Total Flow Rate Enthalpy (sec) (lbm/sec) (Btu/lbm) 0 582 528.53 1.34 1163 528.53 18 1163 528.53 20 1018 528.35 21 945 528.35 22 872 528.35 23 800 528.35 24 727 528.35 25 654 528.35 26 582 528.35 28 436 528.35 30 291 528.35 32 145 528.35 34 0 - NOTE: (1) Suction line pipe size is 6-inch Schedule 80; discharge line pipe size is 4-inch Schedule 80. Revision 15 6.2-179 October, 2007 TABLE 6.2-20 REACTOR ANNULUS RECIRCULATION LINE BREAK Minimum Inertia Head Loss,K Junction From To Elevation Flow Area (L/A) Friction Contrac-No. CV CV (ft) (ft2) (ft-1) Bends (fL/D) Expansion tion Total(1) 1 1 2 9.74 12.03 0.558 0.15 0.0235 - - 0.20 2 1 25 12.64 14.23 0.544 - 0.0226 - - 0.05 3 2 3 11.19 20.45 0.324 0.15 0.0235 - - 0.20 4 2 7 15.59 0.10 0.639 - 0.0226 - - 0.05 5 2 25 14.09 0.01 0.820 0.15 0.0235 - - 0.20 6 3 4 11.19 14.89 0.580 0.15 0.0235 - - 0.20 7 3 8 15.54 3.57 0.592 - 0.0226 - - 0.05 8 4 5 11.19 18.09 0.461 0.15 0.0235 - - 0.20 9 4 9 15.54 0.10 0.457 - 0.0226 - - 0.05 10 5 10 15.54 19.64 0.343 - 0.0226 - - 0.05 11 6 7 21.35 9.88 0.629 0.15 0.0235 - - 0.20 12 6 11 24.25 11.64 0.710 - 0.0226 - - 0.05 13 6 25 18.44 11.64 0.706 - 0.0226 - - 0.05 14 7 8 19.90 7.54 0.392 0.15 0.0235 - - 0.20 15 7 12 24.25 14.38 0.695 - 0.0226 - - 0.05 16 7 25 16.99 0.01 0.820 0.15 0.0235 - - 0.20 17 8 9 19.90 9.52 0.673 0.15 0.0235 - - 0.20 18 8 13 24.25 14.38 0.695 - 0.0226 - - 0.05 19 9 10 19.90 10.74 0.925 0.15 0.0235 - - 0.20 20 9 14 24.25 20.30 0.485 - 0.0226 - - 0.05 21 10 15 24.25 24.79 0.307 - 0.0226 - - 0.05 22 11 12 27.69 15.03 0.518 0.15 0.0235 - - 0.20 23 11 16 31.125 3.14 0.588 - 0.0226 - - 0.05 24 12 13 27.69 11.74 0.427 0.15 0.0235 - - 0.20 25 12 16 31.125 5.41 0.406 - 0.0226 - - 0.05 26 12 17 31.125 0.62 0.390 - 0.0226 - - 0.05 27 13 14 27.69 15.03 0.776 0.15 0.0235 - - 0.20 28 13 17 31.125 12.14 0.390 - 0.0226 - - 0.05 Revision 12 6.2-180 January, 2003 TABLE 6.2-20 (Continued) Minimum Inertia Head Loss, K Junction From To Elevation Flow Area (L/A) Friction Contrac-No. CV CV (ft) (ft2) (ft-1) Bends (fL/D) Expansion tion Total(1) 29 14 15 27.69 15.33 0.519 0.15 0.0235 - - 0.20 30 14 18 31.125 15.81 0.310 - 0.0226 - - 0.05 31 15 19 31.125 24.35 0.339 - 0.0226 - - 0.05 32 16 17 34.59 3.04 0.618 0.15 0.0235 - - 0.20 33 16 20 38.05 0.10 1.328 - 0.0226 - - 0.05 34 17 18 34.59 17.42 0.774 0.15 0.0235 - - 0.20 35 17 21 38.05 12.24 0.882 - 0.0226 - - 0.05 36 18 19 34.59 14.53 0.580 0.15 0.0235 - - 0.20 37 18 22 38.05 8.58 0.970 - 0.0226 - - 0.05 38 19 23 38.05 20.06 0.933 - 0.0226 - - 0.05 39 20 21 44.885 19.71 0.494 0.15 0.0235 - - 0.20 40 20 26 51.71 6.73 0.397 - 0.0226 - - 0.05 41 21 22 44.885 16.73 0.454 0.15 0.0235 - - 0.20 42 21 27 51.71 12.39 0.565 - 0.0226 - - 0.05 43 22 23 44.885 26.29 0.473 0.15 0.0235 - - 0.20 44 22 28 51.71 5.36 0.565 - 0.0226 - - 0.05 45 23 29 51.71 15.80 0.397 - 0.0226 - - 0.05 46 26 27 54.96 17.33 0.549 0.15 0.0235 - - 0.20 47(2) 26 24 54.96 70.41 0.036 - - 1.0 - 1.00 48 27 28 54.96 5.77 1.209 0.15 0.0235 - - 0.20 49(2) 27 24 54.96 66.72 0.037 - - 1.0 - 1.00 50 28 29 54.96 17.33 0.549 0.15 0.0235 - - 0.20 51(2) 28 24 54.96 66.72 0.037 - - 1.0 - 1.00 52(2) 29 24 54.96 70.41 0.036 - - 1.0 - 1.00 53 0 25 15.44 1.00 0.0 - - - - 0.0 54 0 24 15.54 1.00 0.0 - - - - 0.0 NOTES: (1) All horizontal flow paths are assumed to have a K of 0.20; all vertical flow paths are assumed to have a K of 0.05. (2) Air seals rupture at 15 psid. Revision 12 6.2-181 January, 2003 TABLE 6.2-21 REACTOR ANNULUSFEEDWATER LINE BREAK Minimum Inertia Head Loss, K Junction From To Elevation Flow Area (L/A) Friction Contrac-No. CV CV (ft) (ft2) (ft-1) Bends (fL/D) Expansion tion Total(1) 1 1 2 10.22 18.43 0.701 0.084 0.019 - - 0.20 2 1 7 10.22 13.94 0.777 0.084 0.019 - - 0.20 3 1 8 14.94 0.01 2.125 - 0.0244 - - 0.05 4 2 3 10.22 16.01 0.875 0.112 0.026 - - 0.20 5 2 9 14.94 0.01 0.820 - 0.0199 - - 0.05 6 3 4 10.22 14.49 1.732 0.112 0.029 - - 0.20 7 3 10 14.94 0.01 0.593 - 0.0173 - - 0.05 8 4 5 10.22 19.97 1.258 0.112 0.029 - - 0.20 9 4 11 14.94 12.26 0.592 - 0.0173 - - 0.05 10 5 6 10.22 19.67 1.387 0.112 0.029 - - 0.20 11 5 12 14.94 14.43 0.675 - 0.0173 - - 0.05 12 6 7 10.22 14.50 1.132 0.112 0.026 - - 0.20 13 6 13 14.94 0.01 0.597 - 0.0173 - - 0.05 14 7 14 14.94 0.01 1.086 - 0.0199 - - 0.05 15 8 9 19.66 8.01 0.968 0.084 0.019 - - 0.20 16 8 14 19.66 7.36 0.875 0.084 0.019 - - 0.20 17 8 15 24.38 13.27 0.471 - 0.0206 - - 0.05 18 9 10 19.66 8.68 1.241 0.112 0.026 - - 0.20 19 9 16 24.38 22.39 0.341 - 0.0168 - - 0.05 20 10 11 19.66 8.68 1.870 0.112 0.029 - - 0.20 21 10 17 24.38 30.86 0.271 - 0.0146 - - 0.05 22 11 12 19.66 18.02 1.628 0.112 0.029 - - 0.20 23 11 18 24.38 33.53 0.235 - 0.0146 - - 0.05 24 12 13 19.66 8.01 2.248 0.112 0.029 - - 0.20 25 12 19 24.38 33.20 0.235 - 0.0146 - - 0.05 26 13 14 19.66 7.35 1.581 0.112 0.026 - - 0.20 27 13 20 24.38 25.85 0.275 - 0.0146 - - 0.05 28 14 21 24.38 16.72 0.374 - 0.0168 - - 0.05 Revision 12 6.2-182 January, 2003 TABLE 6.2-21 (Continued) Minimum Inertia Head Loss, K Junction From To Elevation Flow Area (L/A) Friction Contrac-No. CV CV (ft) (ft2) (ft-1) Bends (fL/D) Expansion tion Total(1) 29 15 16 27.63 5.93 0.679 0.084 0.023 - - 0.20 30 15 21 27.63 9.02 0.511 0.084 0.023 - - 0.20 31 15 22 30.88 7.92 0.689 - 0.0168 - - 0.05 32 16 17 27.63 5.93 1.310 0.112 0.031 - - 0.20 33 16 23 30.88 11.98 0.614 - 0.0137 - - 0.05 34 17 18 27.63 9.35 3.144 0.112 0.035 - - 0.20 35 17 24 30.88 21.08 0.253 - 0.0119 - - 0.05 36 18 19 27.63 15.89 1.553 0.112 0.035 - - 0.20 37 18 25 30.88 33.19 0.243 - 0.0119 - - 0.05 38 19 20 27.63 7.91 10.548 0.112 0.035 - - 0.20 39 19 26 30.88 31.64 0.355 - 0.0119 - - 0.05 40 20 21 27.63 0.71 7.449 0.112 0.031 - - 0.20 41 20 27 30.88 22.74 0.260 - 0.0119 - - 0.05 42 21 28 30.88 16.65 0.358 - 0.0137 - - 0.05 43 22 23 34.13 11.50 0.941 0.084 0.023 - - 0.20 44 22 28 34.13 6.64 0.666 0.084 0.023 - - 0.20 45 22 29 37.38 8.59 0.828 - 0.0168 - - 0.05 46 23 24 34.13 6.71 2.192 0.112 0.031 - - 0.20 47 23 30 37.38 0.01 0.655 - 0.0137 - - 0.05 48 24 25 34.13 12.55 0.796 0.112 0.035 - - 0.20 49 24 31 37.38 14.70 0.660 - 0.0119 - - 0.05 50 25 26 34.13 17.33 0.796 0.112 0.035 - - 0.20 51 25 32 37.38 28.41 0.493 - 0.0119 - - 0.05 52 26 27 34.13 7.77 1.259 0.112 0.035 - - 0.20 53 26 33 37.38 27.41 0.565 - 0.0119 - - 0.05 54 27 28 34.13 17.33 0.703 0.112 0.031 - - 0.20 55 27 34 37.38 11.97 0.703 - 0.0119 - - 0.05 56 28 35 37.38 11.48 0.782 - 0.0137 - - 0.05 57 29 30 40.63 5.87 0.701 0.084 0.023 - - 0.20 58 29 35 40.63 12.55 0.943 0.084 0.023 - - 0.20 Revision 12 6.2-183 January, 2003 TABLE 6.2-21 (Continued) Minimum Inertia Head Loss, K Junction From To Elevation Flow Area (L/A) Friction Contrac-No. CV CV (ft) (ft2) (ft-1) Bends (fL/D) Expansion tion Total(1) 59 29 36 43.88 13.37 0.459 - 0.0168 - - 0.05 60 30 31 40.63 0.01 1.382 0.112 0.031 - - 0.20 61 30 37 43.88 1.34 0.406 - 0.0137 - - 0.05 62 31 32 40.63 4.00 1.793 0.112 0.035 - - 0.20 63 31 38 43.88 21.49 0.422 - 0.0119 - - 0.05 64 32 33 40.63 13.00 1.623 0.112 0.035 - - 0.20 65 32 39 43.88 28.41 0.422 - 0.0119 - - 0.05 66 33 34 40.63 2.33 2.052 0.112 0.035 - - 0.20 67 33 40 43.88 27.85 0.482 - 0.0119 - - 0.05 68 34 35 40.63 0.99 1.602 0.112 0.031 - - 0.20 69 34 41 43.88 18.76 0.433 - 0.0119 - - 0.05 70 35 42 43.88 15.88 0.419 - 0.0137 - - 0.05 71 36 37 47.13 11.90 0.663 0.084 0.023 - - 0.20 72 36 42 47.13 15.44 0.511 0.084 0.023 - - 0.20 73 36 43 50.38 10.53 0.479 - 0.0168 - - 0.05 74 37 38 47.13 11.90 1.198 0.112 0.031 - - 0.20 75 37 44 50.38 8.31 0.549 - 0.0137 - - 0.05 76 38 39 47.13 13.33 1.149 0.112 0.035 - - 0.20 77 38 45 50.38 23.75 0.234 - 0.0119 - - 0.05 78 39 40 47.13 16.67 1.543 0.112 0.035 - - 0.20 79 39 46 50.38 30.41 0.338 - 0.0119 - - 0.05 80 40 41 47.13 15.00 1.641 0.112 0.035 - - 0.20 81 40 47 50.38 31.19 0.312 - 0.0119 - - 0.05 82 41 42 47.13 13.55 1.056 0.112 0.031 - - 0.20 83 41 48 50.38 19.75 1.222 - 0.0119 - - 0.05 84 42 49 50.38 15.06 0.322 - 0.0137 - - 0.05 85 43 44 53.63 1.66 1.345 0.084 0.023 - - 0.20 86 43 49 53.63 11.37 0.511 0.084 0.023 - - 0.20 87(2) 43 50 53.63 38.17 0.054 - - 1.00 - 1.00 88 44 45 53.63 1.66 1.172 0.112 0.031 - - 0.20 Revision 12 6.2-184 January, 2003 TABLE 6.2-21 (Continued) Minimum Inertia Head Loss, K Junction From To Elevation Flow Area (L/A) Friction Contrac-No. CV CV (ft) (ft2) (ft-1) Bends (fL/D) Expansion tion Total(1) 89(2) 44 50 53.63 53.54 0.043 - - 1.00 - 1.00 90 45 46 53.63 2.62 2.036 0.112 0.035 - - 0.20 91(2) 45 50 53.63 83.11 0.033 - - 1.00 - 1.00 92 46 47 53.63 14.11 1.543 0.112 0.035 - - 0.20 93(2) 46 50 53.63 88.59 0.032 - - 1.00 - 1.00 94 47 48 53.63 10.92 2.386 0.112 0.035 - - 0.20 95(2) 47 50 53.63 91.34 0.031 - - 1.00 - 1.00 96 48 49 53.63 0.01 3.555 0.112 0.031 - - 0.20 97(2) 48 50 53.63 72.09 0.035 - - 1.00 - 1.00 98(2) 49 50 53.63 56.70 0.041 - - 1.00 - 1.00 99 0 29 40.69 1.00 0.0 - - - - 0.0 NOTES: (1) All horizontal flow paths are assumed to have a K of 0.20. All vertical flow paths are assumed to have a K of 0.05. (2) Air seals rupture at 15.0 psid. Revision 12 6.2-185 January, 2003 TABLE 6.2-22 DRYWELL HEAD FLOW PATH DATA (1) (1) Minimum Entrance Head Losses, K Exit Head Losses, K Junc- Flow Inertia Fric- Fric-tion From To Area L/A tion Expan- Contrac- tion Expan- Contrac-No. CV CV (ft2) (ft-1) Bends (f L/D) sion tion Total Bends (f L/D) sion tion Total 1 1 2 13.1 0.77 - - - 0.5 0.5 - 0.02 1.0 - 1.02 NOTE: (1) Head loss terms are with respect to minimum flow area. Revision 12 6.2-186 January, 2003 TABLE 6.2-23 REACTOR WATER CLEANUP ROOMS FLOW PATH DATA (1) (1) Minimum Entrance Head Losses, K Exit Head Losses, K Junc- Flow Inertia Fric- Fric-tion From To Area L/A tion Expan- Contrac- tion Expan- Contrac-No.(2) CV CV (ft2) (ft-1) Bends (f L/D) sion tion Total Bends (f L/D) sion tion Total
a. 1 1 2 16.25 0.444 0.000 0.000 0.000 0.500 0.500 0.497 0.021 0.080 0.000 0.598 2 2 3 16.93 0.356 0.683 0.023 0.000 0.225 0.931 0.000 0.000 1.000 0.000 1.000
b. 1 1 2 16.25 0.247 0.000 0.000 0.000 0.500 0.500 0.390 0.007 0.120 0.000 0.517 2 2 3 24.43 0.175 0.000 0.016 0.000 0.000 0.016 0.882 0.000 1.000 0.150 2.032
c. 1 1 2 17.7 0.258 0.300 0.029 0.000 0.500 0.829 0.000 0.000 1.000 0.000 1.000
d. 1 1 2 16.93 0.717 0.780 0.025 0.000 0.189 0.994 0.000 0.012 0.000 0.195 0.207 2 2 3 16.25 0.191 0.719 0.012 0.000 0.000 0.731 0.000 0.000 1.000 0.051 1.051 NOTES:
(1) Head loss terms are with respect to minimum flow area. (2) RWCU rooms are as follows:
a. Heat Exchanger Room
b. Filter Demineralizer Valve Room
c. Filter Demineralizer Room
d. Drain Valve Nest Room Revision 12 6.2-187 January, 2003
TABLE 6.2-24 STEAM TUNNEL FLOW PATH DATA (1) (1) Minimum Entrance Head Losses, K Exit Head Losses, K Junc- Flow Inertia Fric- Fric-tion From To Area L/A tion Expan- Contrac- tion Expan- Contrac-No. CV CV (ft2) (ft-1) Bends (f L/D) sion tion Total Bends (f L/D) sion tion Total 1 1 2 16.76 0.92 1.53 0.06 - 0.51 2.1 - - 1.0 - 1.0 2 1 2 25.8 0.24 - - - 0.5 0.5 - 0.16 1.0 - 1.16 NOTE: (1) Head loss terms are with respect to minimum flow area. Revision 12 6.2-188 January, 2003 TABLE 6.2-24a DRYWELL BULKHEAD PLATE P ANALYSIS FLOW PATH DESCRIPTION Minimum Inertia Forward Direction Reverse Direction Junction From To Flow Area L/A Entrance Loss Exit Loss Entrance Loss Exit Loss No. CV CV (ft2) (ft-1) (K) (K) (K) (K) 1 1 2 27.8 0.234 0.173 0.086 0.173 0.086 2 1 3 27.8 0.550 0.202 0.086 0.202 0.086 3 1 6 14.5 0.992 0.365 0.053 0.152 0.232 4 1 7 37.9 0.126 0.007 0.401 0.324 0.0 5 2 4 39.4 0.536 0.091 0.0 0.091 0.0 6 2 6 19.55 0.983 0.365 0.053 0.155 0.229 7 2 7 38.4 0.128 0.007 0.398 0.323 0.0 8 3 4 27.8 0.887 0.339 0.176 0.339 0.176 9 3 5 5.17 0.285 0.493 0.923 0.501 0.893 10 3 6 97.0 0.244 0.286 0.0 0.076 0.177 11 3 7 197.8 0.031 0.007 0.421 0.331 0.0 12 4 5 7.4 0.344 0.494 0.939 0.499 0.915 13 4 6 97.0 0.244 0.304 0.006 0.094 0.183 14 4 7 192.4 0.031 0.416 0.007 0.330 0.0 Revision 12 6.2-189 January, 2003 TABLE 6.2-25 REACTOR BLOWDOWN DATA FOR RECIRCULATION SUCTION LINE BREAK (at 3729 MWt) Reactor Vessel Liquid Liquid Steam Steam Time Pressure Flow Enthalpy Flow Enthalpy (sec) (psia) (lbs/sec) (Btu/lb) (lbs/sec) (Btu/lb) 0 1060. 19380. 530.0 0.003 1060. 29070. 530.0 1.00 1050. 28460. 530.0 --- --- 2.00 1039. 24220. 530.0 --- --- 2.01 1039. 22202. 549.0 --- --- 2.50 1036. 21990. 548.0 --- --- 3.06 1036. 21990. 548.0 --- --- 6.06 1062. 22240. 551.9 --- --- 8.00 1075. 22370. 553.9 --- --- 10.87 1081. 22430. 554.8 --- --- 19.29 1021. 21850. 545.8 --- --- 19.30 1020. 11490. 545.8 3025. 1192.1 24.66 767. 9192. 503.9 2457. 1200.3 26.04 712. 8705. 493.8 2318. 1201.6 30.73 550. 7312. 461.0 1856. 1204.3 35.73 413. 6398. 427.6 1399. 1204.7 40.10 330. 5807. 403.7 1106. 1203.6 50.45 193. 5006. 352.4 598.3 1197.9 60.45 126. 4815. 316.7 330.3 1191.3 70.95 95.8 4842. 295.4 204.8 1186.4 100.65 64.8 4736. 267.4 82.2 1179.1 149.65 54.7 4756. 256.1 36.9 1175.8 200.65 54.8 4892. 256.2 23.5 1165.9 300.25 40.9 4168. 237.5 7.6 1170.2 375.91 31.2 65.0 221.2 0.06 1164.9 375.94 31.2 --- --- --- --- Revision 12 6.2-190 January, 2003 TABLE 6.2-26 REACTOR BLOWDOWN DATA FOR MAIN STEAM LINE BREAK - Minimum ECCS (at 3729 MWt) Reactor Vessel Liquid Liquid Steam Steam Time Pressure Flow Enthalpy Flow Enthalpy (sec) (psia) (lbs/sec) (Btu/lb) (lbs/sec) (Btu/lb) 0 1060. 0 551.6 9850. 1190.7 0.05 1056. 0 551.0 11440. 1190.8 0.22 1047. 0 549.7 8259. 1191.1 0.999 1018. 0 545.4 8025. 1192.3 1.000 1018. 27000. 545.3 1094. 1192.3 2.01 1017. 26670. 545.2 1200. 1192.3 4.01 1011. 25890. 544.2 1419. 1192.5 6.00 1007. 19730. 543.6 1273. 1192.7 8.03 1001. 19130. 542.7 1425. 1192.9 10.03 985. 18430. 540.2 1560. 1193.5 15.03 908. 16340. 528.0 1805. 1196.1 20.03 789. 14040. 507.8 1880. 1199.7 25.03 658. 11810. 492.7 1794. 1201.7 30.03 542. 9877. 492.3 1634. 1201.8 50.06 202. 5769. 356.5 652.6 1198.5 70.06 96.1 5132. 295.7 230.6 1186.5 90.15 72.0 5083. 274.7 125.7 1181.1 100.9 62.5 4984. 265.0 91.0 1178.4 119.9 56.2 4980. 257.8 62.9 1176.4 140.4 53.8 5022. 254.9 47.7 1175.5 200.4 53.8 5213. 255.0 29.1 1175.5 300.3 40.2 4450. 236.5 10.2 1170.9 350.9 30.9 1207. 220.7 1.6 1164.7 359.9 30.2 112.3 219.3 0.14 1164.3 Revision 12 6.2-191 January, 2003 TABLE 6.2-27 CORE DECAY HEAT FOLLOWING LOSS-OF-COOLANT ACCIDENT FOR CONTAINMENT ANALYSIS (at 3729 MWt) Normalized Time (sec) Core Heat(1) 0 1.084 2.0 0.5574 6.0 0.5491 10.0 0.3856 20.0 0.125 60.0 0.04692 100.0 0.0426 120.0 0.041 200.0 0.0358 800.0 0.026 1,000.0 0.0245 8,000.0 0.013 20,000.0 0.0101 60,000.0 0.00739 200,000.0 0.00512 600,000.0 0.0036 2,000,000.0 0.00237 NOTE: (1) Normalized to 3729 MWt; includes fuel relaxation energy. Revision 12 6.2-192 January, 2003 TABLE 6.2-27a CORE DECAY HEAT FOLLOWING LOSS-OF-COOLANT ACCIDENT FOR LONG-TERM CONTAINMENT ANALYSIS (at 3833 MWt) Time (sec) Core Heat(1) 0 1.0000 2.0 0.1554 4.0 0.07437 10.0 0.05306 20.0 0.04611 60.0 0.03741 100.0 0.03373 150.0 0.03124 200.0 0.02960 800.0 0.02249 1,000.0 0.02130 8,000.0 0.01162 20,000.0 0.009216 60,000.0 0.007025 100,000.0 0.006116 NOTE: (1) Using decay heat standard ANSI/ANS 5.1-1979 and two sigma. Does not include heat from metal-water reactions or sensible heat stored in fuel and structure. Revision 14 6.2-193 October, 2005 TABLE 6.2-28 ADDITIONAL INFORMATION TO BE PROVIDED FOR DUAL CONTAINMENT PLANTS I. Secondary Containment Design A. Free volume @ 106F, ft3 392,548 B. Pressure, inches water gauge -0.25 C. Leak rate at postaccident pressure, %/day 100 D. Exhaust fans
1. Number 2
2. Type Centrifugal E. Filters
1. Number 2
2. Type Charcoal filter train consisting of a demister, roughing filter, electric heating coil, HEPA filters, charcoal filters (4 inches deep), and HEPA filter.
II. Transient Analysis A. Initial annulus conditions
1. Pressure, psia 14.682
2. Temperature, F 106
3. Outside air temperature, F 95
4. Thickness of secondary containment wall, inches 36
5. Thickness of primary containment wall, inches 1.5 Revision 20 6.2-194 October, 2017
TABLE 6.2-28 (Continued) B. Thermal characteristics
1. Primary containment wall
a. Coefficient of linear expansion, in/in-F at 185F 6.34 x 10-6
b. Modulus of elasticity, psi at 185F 27.7 x 106
c. Thermal conductivity, Btu/hr-ft-F 26
d. Thermal capacitance, Btu/ft3-F 51
2. Secondary containment wall
a. Thermal conductivity, Btu/hr-ft-F 0.8
b. Thermal capacitance, Btu/ft3-F 30
3. Heat transfer coefficients
a. Primary containment atmos-phere to primary containment wall, Btu/hr-ft2-Fabsolute
b. Primary containment wall to secondary containment atmosphere, Btu/hr-ft2-Fabsolute 1.2
c. Secondary containment wall to secondary containment atmosphere, Btu/hr-ft2-Fabsolute 1.2 Revision 15 6.2-195 October, 2007
TABLE 6.2-29 DELETED Revision 15 6.2-196 October, 2007 TABLE 6.2-30 DELETED Revision 15 6.2-197 October, 2007 TABLE 6.2-31 OVERALL HEAT TRANSFER COEFFICIENTS AS A FUNCTION OF TIME(1) Time T hc hr hT (hours) (F) Btu/hr-ft2-F Btu/hr-ft2-F Btu/hr-ft2-F 0.0 0.0 0.0 0.0 0.0 2.788E-04 5.0 0.449 0.808 1.257 5.556E-04 10.0 0.533 0.819 1.372 8.333E-04 15.0 0.590 0.830 1.420 1.389E-03 25.0 0.671 0.853 1.524 1.667E-03 30.0 0.702 0.865 1.567 2.778E-03 33.1 0.720 0.872 1.592 4.167E-03 36.9 0.739 0.881 1.620 5.556E-03 40.8 0.758 0.890 1.648 8.333E-03 48.5 0.792 0.909 1.701 1.250E-02 60.0 0.835 0.937 1.772 1.389E-02 60.3 0.836 0.938 1.774 2.778E-02 63.5 0.847 0.946 1.793 5.556E-02 69.8 0.867 0.962 1.829 8.333E-02 76.1 0.886 0.978 1.864 1.111E-01 82.4 0.904 0.995 1.899 1.389E-01 88.7 0.921 1.012 1.933 1.677E-01 95.0 0.937 1.028 1.965 2.778E-01 95.0 0.937 1.028 1.965 24.0 95.0 0.937 1.028 1.965 NOTE: (1) Values support original analysis. Changes to input parameters affecting these values are reviewed to ensure analysis results remain valid. Revision 20 6.2-198 October, 2017 TABLE 6.2-32 CONTAINMENT ISOLATION VALVE

SUMMARY

(1)(2)

GDC/ Line Figure System Type Actuation Valve Position Power Norm.

Reg. Size Essential 6.2-60 and Valve C Pipe Valve Mode Shut Post Power Isolation Closure Source Flow Penetration No.(3) Guide System Number Fluid (in) System(4) Arr. No. Number Loc(5) Test Length(6) Type Oper. Pri. Sec. Norm down Acc. Fail(7) Signal(8) Time(sec)(9) 1E Bus(10) Dir.

P101 GDC56 RCIC Pump Suction Water 6 Yes(23) 21 E51F031 O No(27) 20-8 Gate EM E M CL CL OP or CL AI RMs,T,J,K,M, 30 1 Out F,V,Q P102 GDC56, RHR A Pump Suction Water 24 Yes 13 E12F004A O No(27) 18-4 Gate EM E M OP CL OP AI RMs Std. 1 Out RG1.11 Suppression Pool Makeup Water 3/4 Yes 55 G43F050A O No <10 Globe S E - OP OP OP AI RMc <3 1 -

P103 GDC56 LPCS Pump Suction Water 24 Yes 6 E21F001 O No(27) 14-7 Gate EM E M OP OP OP AI RMc Std. 1 Out P104 GDC56 RCIC Pump Discharge Water 2 Yes(23) 18 E51F019 O Yes NA Globe EM E M CL CL OP or CL AI RMs,BB,FF,EE 8 1 In Min. Flow to Sup. Pool P105 GDC56 RHR A Min. Flow & Test; Water 18 Yes 15 E12F024A O No(27) 15-9 Globe EM E M CL CL OP or CL AI C,G,RMs,AA 100 1 In LPCS Pump Min. Flow & Test; Water 4 Yes 15 E12F011A O No(27) 18-9 Globe EM E M CL CL CL AI C,G,RMS Std. 1 In RHR Heat Exchanger Water 12 Yes 15 E21F012 O No(27) 21-9 Globe EM E M CL CL CL AI C,G,RMc Std. 1 In Dump to Suppression Pool Water 4 Yes 15 E21F011 O No(27) 24-0 Gate EM E M OP OP OP or CL AI RMc,BB 23.5 1 In Suppression Pool Cleanup Water 6 Yes 15 E12F064A O No(27) 77-7 Gate EM E M OP OP OP or CL AI RMs,BB 15 1 In Return Water 6 No 56 E12F609 O No(27) Gate EM E M CL CL CL AI B,G,RMc Std. 1 In Water 6 No 56 E12F610 O No(27) Gate EM E M CL CL CL AI B,G,RMc Std. 2 In Cont. Atmos. 18 Yes 15 E12D003A I No(16) NA - - - - - - - - - - - -

P106 GDC56 RCIC Turbine Exhaust Cont. Atmos. 12 Yes(23) 10(b) E51F068 O Yes 13-0 Gate EM E M OP OP CL AI RMs,J,G 65 1 In Cont. Atmos. 1-1/2 Yes 10(a) E12F102 O Yes 48-8 Globe M M - LC LC LC - - - - -

Cont. Atmos. 10 Yes(23) 10(b) E51F040 O Yes NA Noz.Chk - M - CL CL OP or CL - - - - In Water 2 Yes 37 E12F025A O Yes NA Rel P P - CL CL CL AI - - - In Water 2 Yes 57 E12F025B O Yes NA Rel P P - CL CL CL AI - - - In Water 2 Yes 57 E12F025C O Yes NA Rel P P - CL CL CL AI - - - In Water 6 Yes 37 E12F055A O Yes NA Rel P P - CL CL CL AI - - - In Water 6 Yes 57 E12F055B O Yes NA Rel P P - CL CL CL AI - - - In Water 1 Yes 57 E12F005 O Yes(16) NA Rel P P - CL CL CL AI - - - In Water 2 Yes 37 E21F018 O Yes NA Rel P P - CL CL CL AI - - - In Water 1 Yes(23) 37 N27F751 O Yes NA Globe M M - LC LC LC AI - - - In Water 1/2 No 57 P87F264 O Yes NA Globe S E - CL CL OP or CL FC RMP <3 - In Cont. Atmos. 1 Yes(23) 37 E12D015A O No(16) NA - - - - - - - - - - - In Cont. Atmos. 1 Yes(23) 57 E12D015B O No(16) NA - - - - - - - - - - - In P107 GDC56 RHR A Loop Relief Line Water 2 Yes 37 E12F025A O Yes 29-6 Rel P P - CL CL CL AI - - - In to Sup. Pool Water 2 Yes 57 E12F025B O Yes 45-6 Rel P P - CL CL CL AI - - - In Water 2 Yes 57 E12F025C O Yes 39-6 Rel P P - CL CL CL AI - - - In Water 6 Yes 37 E12F055A O Yes 77-3 Rel P P - CL CL CL AI - - - In Water 6 Yes 57 E12F055B O Yes 92-6 Rel P P - CL CL CL AI - - - In Water 1 Yes 57 E12F005 O Yes 91-9 Rel P P - CL CL CL AI - - - In Cont. Atmos. 1 Yes(23) 37 N27D0027 O No(16) - - - - - - - - - - - In Water 2 Yes 37 E21F018 O Yes 73-1 Rel P P - CL CL CL AI - - - In Water 1 Yes(23) 37 N27F751 O Yes NA Globe M M - LC LC LC AI - - - In Cont. Atmos. 12 Yes(23) 10(b) E51F068 O Yes NA Gate EM E M OP OP CL AI RMs,J,G Std. 1 In Water 1/2 No 57 P87F083 O Yes 12 Globe S E - CL CL OP or CL FC RMp <3 - In Water 1/2 No 57 P87F264 O Yes NA Globe S E - CL CL OP or CL FC RMp <3 - In Cont. Atmos.,

Water, Steam 1-1/2 Yes 10(a) E12F102 O Yes 135-1 Globe M M - LC LC LC - - - - -

Cont. Atmos. 1 Yes(23) 37 E12D015A O No(16) NA - - - - - - - - - - - In Cont. Atmos. 1 Yes(23) 57 E12D015B O No(16) NA - - - - - - - - - - - In P108 GDC56 Condensate Supply Cond. 12 Yes(23) 27(a) P11F060 O Yes 10-9 Bfly EM E M OP OP CL AI B,G,RMc 35 1 In 12 Yes(23) 27(a) P11F545 I Yes NA Chk P P - CL CL CL - Rev. Flow - - In P109 GDC56 Containment Leak Rate Cont. Atmos. 8 No 35(b) Spect. Flange O No(16) 12-9-1/2 - - - - - - - - - - - Out Test Connection Blowdown Cont. Atmos. 6 No 35(b) Spect. Flange I No(16) NA - - - - - - - - - - - Out Line Cont. Atmos. 8 No 35(b) Blind Flange I No NA - - - - - - - - - - - Out Revision 22 6.2-199 October, 2021

TABLE 6.2-32 (Continued)

GDC/ Line Figure System Type Actuation Valve Position Power Norm.

Reg. Size Essential 6.2-60 and Valve C Pipe Valve Mode ___ Shut Post Power Isolation Closure Source Flow Penetration No.(3) Guide System Number Fluid (in) System(4) Arr. No. Number Loc(5) Test Length(6) Type Oper. Pri. Sec. Norm down Acc. Fail(7) Signal(8) Time(sec)(9) 1E Bus(10) Dir.

P111 GDC56 Condensate Return Water 10 No 27(b) P11F080 O Yes 12-0 Bfly EM E M CL CL CL AI B,G,RMc 30 1 Out (Containment Pool Drain Water 10 No 27(b) P11F090 I Yes NA Bfly EM E M CL CL CL AI B,G,RMc 35 2 Out Line) Water 1/2 No 27(b) P11F629 I Yes NA Rel P P - CL CL OP or CL - - - - -

P112 GDC55 LPCS Pump Discharge to Water 12 Yes 7 E21F005 O No(27) 29-0 Gate EM E M CL CL OP AI RMc32(19) 1 In Reactor Pressure Vessel Water 12 Yes 7 E21F006 I No(27) NA Chk P See Note(11) - CL CL OP - Rev. Flow - - In P113 GDC55 LPCI A to Reactor and RHR Water 12 Yes 11 E12F027A O No(27) 25-9 Gate EM E M OP OP OP AI RMs Std. 1 In to Containment Spray and Water 12 Yes 11 E12F042A I No(27) NA Gate EM E M CL CL OP AI RMs,AA 32(19) 1 In Containment Pool Cooling Water 12 Yes 11 E12F037A I No(27) NA Globe EM E M CL OP OP or CL AI A,U,M,RMs Std. 1 In 12 Yes 11 E12F028A I No(27) NA Gate EM E M CL CL OP AI RMs <90 1 In P114 GDC56 Containment Vacuum Atmos. 24 Yes 19 M17F015 O Yes 2-6 Bfly EM E M OP OP CL AI B,G,X,RMc 5 1 In Relief Atmos. 24 Yes 19 M17F010 I Yes NA Chk P V - CL CL CL - Rev. Flow - - In P115 GDC56 RCIC Turbine Exhaust Cont. Atmos. 1-1/2 Yes 10(a) E12F102 O Yes 33-3 Globe M M - LC LC LC - - - - -

Vacuum Relief Water 2 Yes 37 E12F025A O Yes NA Rel P P - CL CL CL AI - - - In Water 2 Yes 57 E12F025B O Yes NA Rel P P - CL CL CL AI - - - In Water 2 Yes 57 E12F025C O Yes NA Rel P P - CL CL CL AI - - - In Water 6 Yes 37 E12F055A O Yes NA Rel P P - CL CL CL AI - - - In Water 6 Yes 57 E12F055B O Yes NA Rel P P - CL CL CL AI - - - In Water 1 Yes 57 E12F005 O Yes NA Rel P P - CL CL CL AI - - - In Cont. Atmos. 1 Yes(23) 37 E12D015A O No(16) NA - - - - - - - - - - - In Cont. Atmos. 1 Yes(23) 57 E12D015B O No(16) NA - - - - - - - - - - - In Water 2 Yes 37 E21F018 O Yes NA Rel P P - CL CL CL AI - - - In Water 1 Yes(23) 37 N27F751 O Yes NA Globe M M - LC LC LC AI - - - In Water 1/2 No 57 P87F264 O Yes NA Globe S E - CL CL OP or CL FC RMp <3 - In Cont. Atmos. 12 Yes(23) 10(b) E51F068 O Yes 18-0 Gate EM E M OP OP CL AI RMs,J,G Std. 1 In Cont. Atmos. 10 Yes(23) 10(b) E51F040 O Yes NA Noz. Chk EM E M CL CL OP or CL AI - - - In P116 GDC57 Air Supply to ADS Air 1 Yes 33 P57F524B I Yes NA Chk P P - CL CL - Rev. Flow - - In Accumulator Air 1 Yes 33 P57F015B O Yes 10 Globe EM E M OP OP OP AI RMc Std. 2 In P117 GDC56 Nitrogen Supply to Nitrogen 2 No 41 P86F002 O Yes <20 Globe EM E M CL CL CL AI B,G,RMc Std. 1 In Control Rod Drive Nitrogen 2 No 41 P86F528 I Yes NA Chk P P - CL CL CL - Rev. Flow - - In P118 GDC56 RHR Heat Exchanger Vent Noncondens. 1 Yes 45 E12F073A O Yes 13-9 Globe EM E M CL CL CL - RMc Std. 1 In to Suppression Pool 1 Yes 45 E12F558A I Yes NA Chk P P - CL CL CL - Rev. Flow - - In P119 GDC56 Containment Leak Rate Cont. Atmos. 1/2 No 35 Spect. Flange O No(16) 19-9-3/16 - - - - - - - - - - - Out Test PI Cont. Atmos. 1/2 No 35 Spect. Flange I No(16) NA - - - - - - - - - - - Out P120 GDC56 Containment Leak Rate - Air 8 No 35(b) Spect. Flange O No(16) 12-9-1/2 - - - - - - - - - - - In Pressurization Line Air 6 No 35(b) Spect. Flange I No(16) NA - - - - - - - - - - - In Air 8 No 35(b) Blind Flange I No(16) NA - - - - - - - - - - - In P121 GDC55 Feedwater A, RHR, and Water 20 Yes(23) 2 B21F065A O Yes 26-9-5/8 Gate EM E M OP CL OP or CL AI RMc Std. 1(20) In RWCU Return to Reactor Water 20 Yes(23) 2 B21F032A O No(21) NA Chk P P - OP CL OP or CL - Rev. Flow - - In Pressure Vessel Water 20 Yes(23) 2 N27F559A I No(21) NA Chk P P - OP CL OP or CL - Rev. Flow - - In Water 12 Yes 2 E12F053A O Yes 39-7-2/8 Globe EM E M CL OP CL AI RMc,A,U 33 1 In P122 GDC55 Main Steam Line C Steam 26 Yes(23) 1(a) B21F028C O Yes 17-2-3/4 Globe A A SP OP CL CL FC C,E,F,S,N,P,RMc See Note(13) - Out Steam 26 Yes(23) 1(a) B21F022C I Yes NA Globe A A SP OP CL CL FC C,E,F,S,N,P,RMc See Note(13) - Out P123 GDC55 RCIC Pump Discharge and Water 6 Yes(23) 5 E51F066 I No(27) NA Chk P See Note(11) - CL CL OP or CL - Rev. Flow - - In RHR Head Spray Water 6 Yes(23) 5 E51F013 O No(27) 43-6 Gate EM E M CL CL OP or CL AI RMs,EE,FF 15 1 In Water 6 Yes 5 E12F023 O No(27) 50-5 Globe EM E M Cl Cl OP or CL AI A,M,U,RMs Std. 1 In P124 GDC55 Main Steam Line A Steam 26 Yes(23) 1(a) B21F028A O Yes 16-5-7/8 Globe A A SP OP CL CL FC C,E,F,S,N,P,RMc See Note(13) - Out Steam 26 Yes(23) 1(a) B21F022A I Yes NA Globe A A SP OP CL CL FC C,E,F,S,N,P,RMc See Note(13) - Out Revision 22 6.2-200 October, 2021

TABLE 6.2-32 (Continued)

GDC/ Line Figure System Type Actuation Valve Position Power Norm.

Reg. Size Essential 6.2-60 and Valve C Pipe Valve Mode ___ Shut Post Power Isolation Closure Source Flow Penetration No.(3) Guide System Number Fluid (in) System(4) Arr. No. Number Loc(5) Test Length(6) Type Oper. Pri. Sec. Norm down Acc. Fail(7) Signal(8) Time(sec)(9) 1E Bus(10) Dir.

P131 GDC55 RWCU Pump Suction Water 6 Yes(23) 49 G33F001 I Yes NA Gate EM E M OP OP CL AI L,B,F,H,Y,RMc 20 2 Out Water 6 Yes(23) 49 G33F004 O Yes 14-0 Gate EM E M OP OP CL AI L,B,F,H,W,Y, 20 1 Out RMc,RMf P132 GDC55 RWCU Line from Regenerative Water 6 Yes(23) 44 G33F040 I Yes NA Gate EM E M OP OP CL AI L,B,F,H,RMc 27 2 Out Heat Exchanger to Feedwater Water 6 Yes(23) 44 G33F039 O Yes 10-9 Gate EM E M OP OP CL AI B,F,H,L,RMc 27 1 Out P201 GDC56 Drywell Atmosphere Drywell Atmos. 1 No 52 D17F079A O Yes <10 Globe S E - OP OP CL AI B,G,RMc <3 1 In Radiation Monitor Line Drywell Atmos. 1 No 52 D17F079B I Yes <10 Globe S E - OP OP CL AI B,G,RMc <3 2 In Drywell Atmos. 1 No 52 D17F071A O Yes <10 Ball EM E M OP OP CL FC B,G,RMc <3 1 Out Drywell Atmos. 1 No 52 D17F071B I Yes <10 Ball EM E M OP OP CL FC B,G,RMc <3 2 Out P203 GDC56 Fuel Pool Cooling Supply Water 8 No 26(a) G41F100 O Yes 10-9 Bfly EM E M OP OP CL AI B,G,RMc 35 1 In Water 8 No 26(a) G41F522 I Yes NA Chk P P - OP OP CL - Rev. Flow - - In P204 GDC55 Control Rod Drive to Reactor Condensate 2-1/2 Yes(23) 3 C11F083 O Yes 18-0 Gate EM E M OP OP CL AI RMc Std. 1 In Pressure Vessel Condensate 2-1/2 Yes(23) 3 C11F122 I Yes NA Chk P P - OP OP CL - Rev. Flow - - In P205 GDC56 Fuel Transfer Tube Water 24 No 36 Double gasket I No NA - - - - - - - - - - - -

See Note(14) See Note(14)

P208 GDC56 Containment Vacuum Atmos. 24 Yes 19 M17F025 O Yes 2-6 Bfly EM E M OP OP CL AI B,G,X,RMc 5 1 In Relief Atmos. 24 Yes 19 M17F020 I Yes NA Chk P V - CL CL CL - Rev. Flow - - In P210 GDC56 Carbon Dioxide to Fire CO2 4 No 42 P54F340 O Yes 12-6 Gate EM E M CL CL CL AI B,G,RMc 20 1 In Protection System CO2 4 No 42 P54F1098 I Yes NA Chk P P - CL CL CL - Rev. Flow - - In P301 GDC56 Fuel Pool Cooling Water 10 No 26(b) G41F145 O Yes 13-0 Bfly EM E M OP OP CL AI B,G,RMc 35 1 Out Return Water 10 No 26(b) G41F140 I Yes NA Bfly EM E M OP OP CL AI B,G,RMc 35 2 Out Water 3/4 No 26(b) G41F801 I Yes NA Check P P - CL CL OP or CL - Rev. Flow - - -

P302 GDC56 Backup Hydrogen Drywell Atmos. 2 Yes 39(b) M51F110 O Yes 18-0 Globe EM E M CL OP CL AI C,G,GG,RMc Std. 1 Out Purge System or CL Drywell Atmos. 2 Yes 39(b) M51F090 I Yes NA Globe EM E M CL OP CL AI C,G,GG,RMc Std. 2 Out P304 GDC56 Air Supply to ADS Air 1 Yes 33 P57F015A O Yes 10-6 Globe EM E M OP OP OP AI RMc,RMf Std. 1 In Accumulators Air 1 Yes 33 P57F524A I Yes NA Chk P P - CL CL CL - - - - In P305 GDC56 Lower Personnel Airlock Air 3/4 Yes(23) 56 P53F010 O Yes <10 Globe S E - CL CL CL AI B,G,RMc <3 2 In Air 3/4 Yes(23) 56 P53F015 O(22) Yes <10 Globe S E - CL CL CL AI B,G,RMc <3 2 In Air 3/4 Yes(23) 56 P53F070 O Yes <10 Globe S E - OP OP CL FC B,G,RMc <3 1 In Air 3/4 Yes(23) 56 P53F030 O Yes <10 Globe S E - OP OP OP AI RMc,B,G <3 1 Out Air 3/4 No 56 P53F035 O Yes <10 Globe S E - CL CL CL AI RMc,B,G <3 1 Out Air 3/4 Yes(23) 56 P52F160 O Yes <10 Globe S E - OP OP CL FC RMc,B,G <3 1 In Air 3/4 Yes(23) 56 Inflatable I No(16) NA - - - - - - - - - - - -

gaskets Air 1/2 No - P53F556 I Yes <10 Needle M M - OP OP OP AI - - - -

Air 1 No - P53F536 O(22) Yes <10 Globe M M - LC LC LC AI - - - -

Air 1 No - P53F570 O Yes <10 Globe M M - LC LC LC AI - - - -

Air 1 No - P53F579A O Yes <10 Ball M M - CL CL CL AI - - - -

Air 1 No - P53F579B I(22) Yes <10 Ball M M - CL CL CL AI - - - -

Air 1 No - P53F580A O(22) Yes <10 Ball M M - CL CL CL AI - - - -

Air 1 No - P53F580B I Yes <10 Ball M M - CL CL CL AI - - - -

Air 1 No - P53F581 I(22) Yes <10 Relief - - - CL CL CL AI - - - In Air 1 No - P53F582 I Yes <10 Relief - - - CL CL CL AI - - - In P306 GDC57 Instrument Air Air 2 Yes(23) 34 P52F200 O Yes 24-6 Globe EM E M OP OP CL AI C,G,RMc Std. 1 In Air 1-1/2 Yes(23) 34 P52F550 I Yes NA Chk P P - OP OP CL - Rev. Flow - - In Revision 21 6.2-201 October, 2019

TABLE 6.2-32 (Continued)

GDC/ Line Figure System Type Actuation Valve Position Power Norm.

Reg. Size Essential 6.2-60 and Valve C Pipe Valve Mode ___ Shut Post Power Isolation Closure Source Flow Penetration No.(3) Guide System Number Fluid (in) System(4) Arr. No. Number Loc(5) Test Length(6) Type Oper. Pri. Sec. Norm down Acc. Fail(7) Signal(8) Time(sec)(9) 1E Bus(10) Dir.

P308 GDC56 Service Air Air 2-1/2 No 32 P51F150 O Yes 11-3 Globe A A M OP OP CL FC B,G,RMc 15 - In Air 2-1/2 No 32 P51F530(26) I Yes NA Chk P P - CL CL CL - Rev. Flow - - In P309 GDC56 Demineralized Water Demin. Wtr. 3 No 29 P22F010 O Yes 17-3 Gate EM E M OP OP CL AI B,G,RMc 22 Max. 1 In Demin. Wtr. 3 No 29 P22F577 I Yes NA Chk P P - CL CL CL - Rev. Flow - - In P310 GDC56 Nuclear Closed Cooling Water 12 No 25(a) P43F055 O Yes 8-6 Bfly EM E M OP OP CL AI C,G,RMc 35 1 In Water Supply Water 12 No 25(a) P43F721 I Yes NA Chk P P - OP OP CL - Rev. Flow - - In P311 GDC56 Nuclear Closed Cooling Water 12 No 25(b) P43F140 O Yes 8-6 Bfly EM E M OP OP CL AI C,G,RMc 30 1 Out Water Return Water 12 No 25(b) P43F215 I Yes NA Bfly EM E M OP OP CL AI C,G,RMc 35 2 Out Water 1/4 No 25(b) 1P43F851 I Yes NA Relief P P - CL CL OP or CL - - - - -

P312 GDC56 Upper Personnel Airlock Air 3/4 Yes(23) 56 P53F020 O Yes <10 Globe S E - CL CL CL AI B,G,RMc <3 2 In Air 3/4 Yes(23) 56 P53F025 O(22) Yes <10 Globe S E - CL CL CL AI B,G,RMc <3 2 In Air 3/4 Yes(23) 56 P53F075 O Yes <10 Globe S E - OP OP CL FC B,G,RMc <3 1 In Air 3/4 Yes(23) 56 P53F040 O Yes <10 Globe S E - OP OP OP AI RMc,B,G <3 1 Out Air 3/4 No 56 P53F045 O Yes <10 Globe S E - CL CL CL AI RMc,B,G <3 1 Out Air 3/4 Yes(23) 56 P52F170 O Yes <10 Globe S E - OP OP CL FC B,G,RMc <3 1 In Air 3/4 Yes(23) 56 Inflatable I No(16) NA - - - - - - - - - - - -

gaskets Air 1/2 No - P53F561 I Yes <10 Needle M M - OP OP OP AI - - - -

Air 1 No - P53F541 O(22) Yes <10 Globe M M - LC LC LC AI - - - -

Air 1 No - P53F571 O Yes <10 Globe M M - LC LC LC AI - - - -

Air 1 No - P53F593A O Yes <10 Ball M M - CL CL CL AI - - - -

Air 1 No - P53F593B I(22) Yes <10 Ball M M - CL CL CL AI - - - -

Air 1 No - P53F594A O(22) Yes <10 Ball M M - CL CL CL AI - - - -

Air 1 No - P53F594B I Yes <10 Ball M M - CL CL CL AI - - - -

Air 1 No - P53F595 I(22) Yes <10 Relief - - - CL CL CL AI - - - In Air 1 No - P53F596 I Yes <10 Relief - - - CL CL CL AI - - - In V313 GDC56 Containment Purge Cont. Atmos. 42 No 30(a) M14F040 O Yes 2-0 Bfly A A - CL OP CL FC B,G,RMc,Z 4 - In Supply Cont. Atmos. 42 No 30(a) M14F045 I Yes NA Bfly A A - CL OP CL FC B,G,RMc,Z 4 - In Cont. Atmos. 18 No 30(a) M14F190 I Yes NA Bfly A A - CL OP CL FC B,G,RMc,Z 4 - In Cont. Atmos. 18 No 30(a) M14F195 I Yes NA Bfly A A - CL OP CL FC B,G,RMc,Z 4 - In V314 GDC56 Containment Purge Cont. Atmos. 42 No 30(b) M14F090 O Yes 2-0 Bfly A A - CL OP CL FC B,G,RMc,Z 4 - Out Exhaust Cont. Atmos. 42 No 30(b) M14F085 I Yes NA Bfly A A - CL OP CL FC B,G,RMc,Z 4 - Out Cont. Atmos. 18 No 30(b) M14F200 I Yes NA Bfly A A - CL OP CL FC B,G,RMc,Z 4 - Out Cont. Atmos. 18 No 30(b) M14F205 I Yes NA Bfly A A - CL OP CL FC B,G,RMc,Z 4 - Out P315 GDC56 SLC Tank Refill Sodium 2 Yes(23) 60 C41F518 O Yes 29 Globe M M - LC LC LC - - - - In Pentaborate C41F520 I Yes NA Chk P P - CL CL CL - Rev. Flow - - In Solution P317 GDC56 Containment Atmosphere Cont. Atmos. 1 No 54 D17F089A O Yes <10 Globe S E - OP OP CL AI B,G,RMc <3 1 In Radiation Monitor Line Cont. Atmos. 1 No 54 D17F089B I Yes NA Globe S E - OP OP CL AI B,G,RMc <3 2 In Cont. Atmos. 1 No 54 D17F081A O Yes <10 Ball EM E M OP OP CL FC B,G,RMc <3 1 Out Cont. Atmos. 1 No 54 D17F081B I Yes NA Ball EM E M OP OP CL FC B,G,RMc <3 2 Out GDC56 Containment Leak Rate Cont. Atmos. 1/2 No 35 Spect. Flange O No(16) 12-2-1/4 - - - - - - - - - - - Out Cont. Atmos. 1/2 No 35 Pipe Cap I No(16) NA - - - - - - - - - - - Out Cont. Atmos. 3/4 No 35 Spect. Flange O No(16) 12-2-1/4 - - - - - - - - - - - Out Cont. Atmos. 3/4 No 35 Pipe Cap I No(16) NA - - - - - - - - - - - Out Cont. Atmos. 3/4 No 35 E61F550 I Yes NA Globe M M - LC LC LC - - - - Out or OP Cont. Atmos. 1/2 No 35 E61F549 I Yes NA Globe M M - LC LC LC - - - - Out or OP Revision 22 6.2-202 October, 2021

TABLE 6.2-32 (Continued)

GDC/ Line Figure System Type Actuation Valve Position Power Norm.

Reg. Size Essential 6.2-60 and Valve C Pipe Valve Mode ___ Shut Post Power Isolation Closure Source Flow Penetration No.(3) Guide System Number Fluid (in) System(4) Arr. No. Number Loc(5) Test Length(6) Type Oper. Pri. Sec. Norm down Acc. Fail(7) Signal(8) Time(sec)(9) 1E Bus(10) Dir.

P318 RG1.11 Combustible Gas Control Cont. Atmos. 1/2 Yes 58(b) M51F210B O Yes <10 Globe S E - CL CL OP AI RMc <3 2 Out Postaccident Hydrogen Drywell Atmos. 1/2 Yes 58(b) M51F220B O Yes F10 Globe S E - CL CL OP AI RMc <3 2 Out Analyzer Drywell Atmos. 1/2 Yes 58(b) M51F230B O Yes <10 Globe S E - CL CL OP AI RMc <3 2 Out Sup. Pool Atmos. 1/2 Yes 58(b) M51F240B O Yes <10 Globe S E - CL CL OP AI RMc <3 2 Out Analyzer Exhaust 1/2 Yes 58(b) M51F250B O Yes <10 Globe S E - CL CL OP FC RMc <3 2 In Sup. Pool Atmos. 1/2 No 58(b) P87F071 O Yes <15 Globe S E - CL CL OP or CL FC RMp <3 - Out Gas Sample Return 1/2 No 58(b) P87F065 O Yes <15 Globe S E - CL CL OP or CL FC RMp <3 - In Drywell Atmos. 1/2 No 58(b) P87F077 O Yes <15 Globe S E - CL CL OP or CL FC RMp <3 - Out Cont. Atmos. 1/2 No 58(b) P87F074 O Yes <15 Globe S E - CL CL OP or CL FC RMp <3 - Out P319 RG1.11 Containment Atmosphere Cont. Atmos. 3/4 Yes(23) 38(b) D23F030B O No <10 Globe S E - OP OP OP AI RMc <3 2 -

Monitoring Cont. Atmos. 3/4 Yes(23) 38(b) 1/4 orifice I No NA - - - - - - - - - - - -

Drywell Atmos. 3/4 Yes(23) 38(a) D23F040B O No <10 Globe S E - OP OP OP AI RMc <3 2 -

Drywell Atmos. 3/4 Yes(23) 38(a) 1/4 orifice I No NA - - - - - - - - - - - -

GDC56 Containment Leak Rate Cont. Atmos. 3/4 No 35 Spect. Flange O No(16) 14-11 - - - - - - - - - - - Out Cont. Atmos. 3/4 No 35 E61F551 I Yes NA Globe M M - LC LC LC - - - - Out or OP Cont. Atmos. 3/4 No 35 Pipe Cap I No(16) NA - - - - - - - - - - - Out Cont. Atmos. 1/2 No 35 Spect. Flange O No(16) 15-11 - - - - - - - - - - - Out Cont. Atmos. 1/2 No 35 E61F552 I Yes NA Globe M M - LC LC LC - - - - Out or OP Cont. Atmos. 1/2 No 35 Pipe Cap I No(16) NA - - - - - - - - - - - Out P320 GDC56 Containment Vacuum Relief Cont. Atmos. 3/4 Yes 59 M17F065 O No <10 Globe S E - OP OP OP AI RMc <3 2 -

Cont. Atmos. 3/4 Yes 59 1/4 orifice I No NA - - - - - - - - - - - -

RG1.11 Containment Atmosphere Cont. Atmos. 3/4 Yes(23) 38(b) D23F020B O No <10 Globe S E - OP OP OP AI RMc <3 2 -

Monitoring Cont. Atmos. 3/4 Yes(23) 38(b) 1/4 orifice I No NA - - - - - - - - - - - -

Cont. Atmos. 3/4 Yes(23) 38(b) D23F010B O No <10 Globe S E - OP OP OP AI RMc <3 2 -

Cont. Atmos. 3/4 Yes(23) 38(b) 1/4 orifice I No NA - - - - - - - - - - - -

P401 GDC56 HPCS Pump Suction Water 24 Yes 8 E22F015 O No(27) 18-3 Gate EM E M CL CL OP or CL AI RMc 24 3 Out RG1.11 Suppression Pool Makeup Water 3/4 Yes 55 G43F060 O No <10 Globe S E - OP OP OP AI RMc <3 - -

Postaccident Sampling (PASS) Water 3/4 No 55 P87F037 O Yes <15 Globe S E - CL CL OP or CL FC RMp <3 - Out P402 GDC56 RHR B Pump Suction Water 24 Yes 13 E12F004B O No(27) 17-8/16 Gate EM E M OP CL OP AI RMc Std. 2 Out RG1.11 Suppression Pool Makeup Water 3/4 Yes 55 G43F050B O No <10 Globe S E - OP OP OP AI RMc <3 2 -

P403 GDC56 RHR C Pump Suction Water 24 Yes 13 E12F105 O No(27) 20-11/16 Gate EM E M OP CL OP AI RMc Std. 2 Out P404 GDC56 Chilled Water Supply Water 6 Yes 28(a) P50F060 O Yes 9-6 Bfly EM E M OP OP CL AI B,G,RMc 30 1 In Water 6 Yes 28(a) P50F539 I Yes NA Chk P P - OP OP CL - Rev. Flow - - In P405 GDC56 Chilled Water Return Water 6 Yes 28(b) P50F150 O Yes 10-3 Bfly EM E M OP OP CL AI B,G,RMc 35 1 Out Water 6 Yes 28(b) P50F140 I Yes NA Bfly EM E M OP OP CL AI B,G,RMc 35 2 Out Water 1/4 No 28(b) P50F606 I Yes NA Relief P P - CL CL OP or CL - - - - -

P406 GDC56 Fire Protection Water Nitrogen(24) 4 No 51 P54F726 O Yes 13-3 Gate M M - LC LC LC - - - - In Nitrogen(24) 4 No 51 P54F727 I Yes NA Gate M M - LC LC LC - - - - In P407 GDC56 RHR B Test and Pump Water 18 Yes 17 E12F024B O No(27) 20-3 Globe EM E M CL CL OP or CL AI C,G,RMc,AA 100 2 In Minimum Flow Line, Water 4 Yes 17 E12F011B O No(27) 15-9 Globe EM E M CL CL CL AI C,G,RMc Std. 2 In RHR Heat Exchanger Water 6 Yes 17 E12F064B O No(27) 78-0 Gate EM E M OP OP OP or CL AI RMc,BB 15 2 In Dump to Suppression Pool Cont. Atmos. 18 Yes 17 E12D003B I No(16) NA - - - - - - - - - - - -

Revision 21 6.2-203 October, 2019

TABLE 6.2-32 (Continued)

GDC/ Line Figure System Type Actuation Valve Position Power Norm.

Reg. Size Essential 6.2-60 and Valve C Pipe Valve Mode ___ Shut Post Power Isolation Closure Source Flow Penetration No.(3) Guide System Number Fluid (in) System(4) Arr. No. Number Loc(5) Test Length(6) Type Oper. Pri. Sec. Norm down Acc. Fail(7) Signal(8) Time(sec)(9) 1E Bus(10) Dir.

P408 GRDC56 RHR C Test and Pump Water 18 Yes 23 E12F021 O Yes 18-7-1/2 Globe EM E M CL CL CL AI C,G,RMc 90 2 In Minimun Flow Line Water 6 Yes 22 E12F064C O Yes 97-0 Gate EM E M OP OP OP or CL AI RMc,BB 15 2 In P409 GRD56 HPCS Minimum Flow Water 12 Yes 24 E22F023 O Yes 27-9 Globe EM E M CL CL CL AI B,G,RMc Std. 3 In Line and Test Line to Water 12 Yes 24 E22F012 O Yes 17-0 Gate EM E M CL CL OP or CL AI RMc,BB,CC 8 3 In Suppression Pool Water 2 Yes 24 E22F035 O Yes 29-8-1/2 Relief P P - CL CL CL - - - - In P410 GDC55 HPCS to Reactor Water 12 Yes 9 E22F004 O No(27) 22-0 Gate EM E M CL CL OP AI RMc,DD 16(19) 3 In Pressure Vessel Water 12 Yes 9 E22F005 I No(27) NA Chk P See Note(11) - CL CL OP - Rev. Flow - - In P411 GDC55 LPCI C to Reactor Water 12 Yes 12 E12F042C O No(27) 22-9 Gate EM E M CL CL OP AI RMc 32(19) 2 In Water 12 Yes 12 E12F041C I No(27) NA Chk P See Note(11) - CL CL OP - Rev. Flow - - In P412 GDC55 LPCI B to Reactor and Water 12 Yes 11 E12F027B O No(27) 19-3 Gate EM E M OP OP OP AI RMc Std. 2 In RHR to Containment Water 12 Yes 11 E12F042B I No(27) NA Gate EM E M CL CL OP AI RMc,AA 32(19) 2 In Spray and Containment Water 12 Yes 11 E12F037B I No(27) NA Globe EM E M CL OP OP or CL AI A,M,U,RMc Std. 2 In Pool Cooling Water 12 Yes 11 E12F028B I No(27) NA Gate EM E M CL CL OP AI RMc <90(19) 2 In P413 GDC56 PASS Water 3/4 No 61 P87F049 I Yes NA Globe S E - CL CL OP or CL FC RMp <3 - Out Water 3/4 No 61 P87F055 O Yes <10 Globe S E - CL CL OP or CL FC RMp <3 - Out Air(24) 3/4 No 61 P87F046 I Yes NA Globe S E - CL CL OP or CL FC RMp <3 - Out Air(24) 3/4 No 61 P87F052 O Yes <10 Globe S E - CL CL OP or CL FC RMp <3 - Out Water 1/4 No 61 P87F277 I Yes NA Rel P P - CL CL OP or CL - - - - Out P414 GDC55 Feedwater B, RHR and Water 20 Yes(23) 2 B21F065B O Yes 26-9-5/8 Gate EM E M OP CL OP or CL AI RMc Std. 1(20) In RWCU Return to Reactor Water 20 Yes(23) 2 B21F032B O No(21) NA Chk P P - OP CL OP or CL - Rev. Flow - - In Pressure Vessel Water 20 Yes(23) 2 N27F559B I No(21) NA Chk P P - OP CL OP or CL - Rev. Flow - - In Water 12 Yes 2 E12F053B O Yes 39-7-3/8 Globe EM E M CL OP CL AI RMc,A,U 33 2 In P415 GDC55 Main Steam Line D Steam 26 Yes(23) 1(a) B21F028D O Yes 16-5-7/8 Globe A A SP OP CL CL FC C,E,F,S,N,P,RMc See Note(13) - Out Steam 26 Yes(23) 1(a) B21F022D I Yes NA Globe A A SP OP CL CL FC C,E,F,S,N,P,RMc See Note(13) - Out P416 GDC55 Main Steam Line B Steam 26 Yes(23) 1(a) B21F028B O Yes 17-4-3/4 Globe A A SP OP CL CL FC C,E,F,S,N,P,RMc See Note(13) - Out Steam 26 Yes(23) 1(a) B21F022B I Yes NA Globe A A SP OP CL CL FC C,E,F,S,N,P,RMc See Note(13) - Out P417 GDC56 Drywell and Containment Water 3 No 40 G61F080 O Yes 26-6 Gate EM E M OP OP CL AI B,G,RMc 22 1 Out Equipment Drain Sump to Water 3 No 40 G61F075 I Yes NA Gate EM E M OP OP CL AI B,G,RMc 22 2 Out Radwaste Water 3/4 No 40 G61F0655 I Yes NA Check P P - CL CL OP or CL - Rev. Flow - - -

P418 GDC56 Drywell and Containment Water 3 No 43 G61F170 O Yes 28-3 Gate EM E M OP OP CL AI B,G,RMc 22 1 Out Floor Drain Sump to Water 3 No 43 G61F165 I Yes NA Gate EM E M OP OP CL AI B,G,RMc 22 2 Out Radwaste Water Water 3/4 No 43 G61F657 I Yes NA Check P P - CL CL OP or CL - Rev. Flow - - -

P419 GDC55 RWCU Pump Discharge Water 4 No 48 G33F054 O Yes 10-6 Gate EM E M OP OP CL AI L,B,F,H,RMc 15.5(25) 1 In Water 4 No 48 G33F053 I Yes NA Gate EM E M OP OP CL AI L,B,F,H,RMc 15.5(25) 2 In P420 GDC56 RWCU Backwash Transfer Water 4 No 46 G50F277 O Yes 12-0 Gate EM E M OP OP CL AI B,G,RMc Std. 1 Out Pump to Radwaste Water 4 No 46 G50F272 I Yes NA Gate EM E M OP OP CL AI B,G,RMc Std. 2 Out Water 1/2 No 46 G50F823 I Yes NA Relief P P - CL CL OP or CL - - - - -

P421 GDC55 RHR Reactor Shutdown Water 20 Yes 20 E12F008 O No(27) 14-0 Gate EM E M CL OP CL AI U,A,M,RMs <33 1 Out Cooling Suction Water 20 Yes 20 E12F009 I No(27) NA Gate EM E M CL OP CL AI U,A,M,RMs <33 2 Out Water 3/4 Yes 20 E12F550 I No(27) NA Chk P P - CL CL CL - Rev. Flow - - Out P422 GDC55 RCIC Steam Supply Steam 10 Yes(23) 1(c) E51F063 I Yes NA Gate EM E M OP CL OP or CL AI J,F,K,M,T,RMs, 20 2 Out V,Q Steam 10 Yes(23) 1(c) E51F064 O Yes 13-2 Gate EM E M OP CL OP or CL AI J,F,K,M,T,RMs, 20 1 Out V,Q Steam 1 Yes(23) 1(c) E51F076 I Yes NA Globe EM E M CL CL CL AI J,F,K,M,T,RMs, Std. 2 Out V,Q Revision 22 6.2-204 October, 2021

TABLE 6.2-32 (Continued)

GDC/ Line Figure System Type Actuation Valve Position Power Norm.

Reg. Size Essential 6.2-60 and Valve C Pipe Valve Mode ___ Shut Post Power Isolation Closure Source Flow Penetration No.(3) Guide System Number Fluid (in) System(4) Arr. No. Number Loc(5) Test Length(6) Type Oper. Pri. Sec. Norm down Acc. Fail(7) Signal(8) Time(sec)(9) 1E Bus(10) Dir.

P423 GDC55 Main Steam Line Drain Water 3 No 1(b) B21F019 O Yes 13-0 Gate EM E M OP CL CL AI C,E,F,S,N,P, 25 1 Out RMc,RMf Water 3 No 1(b) B21F016 I Yes NA Gate EM E M OP CL CL AI C,E,F,S,N,P,RMc 25 2 Out P424 GDC55 RWCU to Main Condenser Water 4 No 14 G33F034 O Yes 8-6 Gate EM E M CL CL CL AI L,B,F,H,RMc 20(25) 1 Out and Radwaste Water 4 No 14 G33F028 I Yes NA Gate EM E M CL CL CL AI L,B,F,H,RMc 20(25) 2 Out Water 1/4 No 14 G33F0646 I Yes NA Rel P P - CL CL OP or CL - - - - -

P425 RG1.11 Combustible Gas Control Cont. Atmos. 1/2 Yes 58(a) M51F210A O Yes <10 Globe S E - CL CL OP AI RMc 3 1 Out Postaccident Hydrogen Drywell Analyzer Atmos. 1/2 Yes 58(a) M51F220A O Yes <10 Globe S E - CL CL OP AI RMc 3 1 Out Drywell Atmos. 1/2 Yes 58(a) M51F230A O Yes <10 Globe S E - CL CL OP AI RMc 3 1 Out Sup. Pool Atmos. 1/2 Yes 58(a) M51F240A O Yes <10 Globe S E - CL CL OP AI RMc 3 1 Out Analyzer Exhaust 1/2 Yes 58(a) M51F250A O Yes <10 Globe S E - CL CL OP FC RMc 3 1 In RG1.11 Containment Atmosphere Cont. Atmos. 3/4 Yes(23) 38(b) D23F050 O No <10 Globe S E - OP OP OP AI RMc 3 3 -

Monitoring Cont. Atmos. 3/4 Yes(23) 38(b) 1/4 orifice I No NA - - - - - - - - - - - -

P428 GDC56 Containment Vacuum Atmos. 24 Yes 19 M17F035 O Yes 2-6 Bfly EM E M OP OP CL AI B,G,X,RMc 5 2 In Relief Atmos. 24 Yes 19 M17F030 I Yes NA Chk P V - CL CL CL - Rev. Flow - - In P429 GDC56 RHR Relief Line to Water 2 Yes 37 E12F025A O Yes 29-6 Rel P P - Cl Cl CL AI - - - In Suppression Pool Water 2 Yes 57 E12F025B O Yes 45-6 Rel P P - CL CL CL AI - - - In Water 2 Yes 57 E12F025C O Yes 39-6 Rel P P - CL CL CL AI - - - In Water 6 Yes 37 E12F055A O Yes 77-3 Rel P P - CL CL CL AI - - - In Water 6 Yes 57 E12F055B O Yes 92-6 Rel P P - CL CL CL AI - - - In Water 1 Yes 57 E12F005 O Yes 91-9 Rel P P - CL CL CL AI - - - In Cont. Atmos. 1 Yes(23) 37 N27D006 O No(16) NA - - - - - - - - - - - In Water 2 Yes 37 E21F018 O Yes 73-1 Rel P P - CL CL CL AI - - - In Water 1 Yes(23) 37 N27F751 O Yes NA Globe M M - LC LC LC AI - - - In Cont. Atmos. 12 Yes(23) 10(b) E51F068 O Yes NA Gate EM E M OP OP CL AI RMs,J,G Std. 1 In Water 1/2 No 57 P87F083 O Yes 12 Globe S E - CL CL OP or CL FC RMp <3 - In Water 1/2 No 57 P87F264 O Yes NA Globe S E - CL CL OP or CL FC RMp <3 - In Cont. Atmos.

Water, Steam 1-1/2 Yes 10(a) E12F102 O Yes 221-8 Globe M M - LC LC LC - - - - -

Cont. Atmos. 1 Yes(23) 37 E12D015A O No(16) NA - - - - - - - - - - - In Cont. Atmos. 1 Yes(23) 57 E12D015B O No(16) NA - - - - - - - - - - - In P431 GDC56 RHR Heat Exchanger Vent Noncondens., 1 Yes 45 E12F073B O Yes 12-9 Globe EM E M OP CL CL AI RMc,A,G,M Std. 2 In to Suppression Pool Steam 1 Yes 45 E12F558B I Yes NA Chk P P - CL CL CL - Rev. Flow - - In SDC Header Leak-off P433 RG1.11 Containment Atmosphere Cont. Atmos. 3/4 Yes(23) 38(b) D23F030A O No <10 Globe S E - OP OP OP AI RMc <3 1 -

Monitoring System Cont. Atmos. 3/4 Yes(23) 38(b) 1/4 orifice I No NA - - - - - - - - - - - -

Drywell Atmos. 3/4 Yes(23) 38(a) D23F040A O No <10 Globe S E - OP OP OP AI RMc <3 1 -

Drywell Atmos. 3/4 Yes(23) 38(a) 1/4 orifice I No NA - - - - - - - - - - - -

P434 RG1.11 Containment Atmosphere Cont. Atmos. 3/4 Yes(23) 38(b) D23F010A O No <10 Globe S E - OP OP OP AI RMc <3 1 -

Monitoring Cont. Atmos. 3/4 Yes(23) 38(b) 1/4 orifice I NO NA - - - - - - - - - - - -

Cont. Atmos. 3/4 Yes(23) 38(b) D23F020A O No <10 Globe S E - OP OP OP AI RMc <3 1 -

Cont. Atmos. 3/4 Yes(23) 38(a) 1/4 orifice I No NA - - - - - - - - - - - -

GDC56 Containment Vaccum Cont. Atmos. 3/4 Yes(23) 59 M17F055 O No <10 Globe S E - OP OP OP AI RMc <3 1 -

Relief Cont. Atmos. 3/4 Yes(23) 59 1/4 orifice I No NA - - - - - - - - - - - -

P436 GDC56 Containment Vaccum Atmos. 24 Yes 19 M17F045 O Yes 2-6 Bfly EM E M OP OP CL AI B,G,X,RMc 5 2 In Relief Atmos. 24 Yes 19 M17F040 I Yes NA Chk P V - CL CL CL NA Rev. Flow - - In Revision 22 6.2-205 October, 2021

TABLE 6.2-32 (Continued)

NOTES:

(1) Through line leakage classification is discussed in <Section 6.2.3>.

(2) Abbreviations used are as follows:

A - Air LPCS - Low Pressure Core Spray System ADS - Automatic Depressurization System M - Manual AI - As is NA - Not applicable Bfly - Butterfly valve OP - Open Chk - Check valve P - Process fluid Cl - Closed RCIC - Reactor Core Isolation Cooling System E - Electric Rel - Relief Valve EH - Electrohydraulic RHR - Residual Heat Removal System EM - Electric Motor RWCU - Reactor Water Cleanup System FC - Fail Closed S - Solenoid H - Hydraulic SLC - Standby Liquid Control System HPCS - High Pressure Core Spray System SP - Spring LC - Locked or Sealed in Closed Position V - Vacuum in containment LPCI - Low Pressure Coolant Injection System (3) Penetrations not listed are spares and are capped, except penetration P202 which is the equipment hatch.

(4) Essential systems are engineered safety feature systems which are required for shutdown.

(5) Location inside (I) or outside (O) of containment.

(6) Length of pipe from containment to outermost isolation valve.

(7) All motor-operated isolation valves remain in last position upon failure of valve power. All air operated valves close upon loss of motive air.

(8) Remote-manual (RM) valves can be opened or closed by remote-manual switch operation during any mode of reactor operation, except when an automatic signal is present. All remote-manual valves have position indicator lights at the remote-manual switch, and a subset of these valves have an additional set of position indicating lights at the control room isolation status panel. Isolation signals are defined as follows:

Signal Description A Reactor vessel low water level - Level 3. (A scram occurs at this level. This is the highest of the three isolation low water level signals.)

B Reactor vessel low water level - Level 2. (This is the second of the three low water level signals. The reactor core isolation cooling and high pressure core spray systems are activated at this level.)

C Reactor vessel low water level - Level 1. (This is the lowest of the three water level signals. Main steam line isolation occurs at this level. The low pressure core spray and low pressure coolant injection systems are also activated at this level.)

D Spare.

E Line break - main steam line (steam line high steam flow).

F Line break - main steam line (main steam line tunnel high space ambient high temperature).

G High drywell pressure.

H Line break in reactor water cleanup system (high ambient high temperature).

J Line break in the steam supply line to reactor core isolation cooling system (low steam line pressure).

K Line break in reactor core isolation cooling system steam line to turbine (high steam flow).

L High differential flow in the reactor water cleanup system.

M Line break in residual heat removal system (high ambient high temperature).

N Low main condenser vacuum.

P Low main steam line pressure at inlet to turbine (RUN mode, only).

Q Line break in reactor core isolation cooling system (high ambient).

S High main steam line temperature, turbine building.

Revision 19 6.2-206 October, 2015

TABLE 6.2-32 (Continued)

NOTES: (Continued)

Signal Description T High pressure reactor isolation cooling turbine exhaust diaphragm.

U High reactor vessel pressure - close residual heat removal - shutdown cooling valves and head cooling valves.

V Line break in the steam supply line to reactor core isolation cooling system (high steam flow).

W High temperature at outlet of cleanup system nonregenerative heat exchanger.

X Containment to atmosphere differential pressure greater than 0.0 psid.

Y Standby liquid control system actuated.

Z High radiation, containment and drywell ventilation exhaust.

RMc Remote-manual switch from control room. (All automatically actuated containment isolation valves are capable of remote operation from the control room.)

RMf Remote-manual switch from motor control center. (Provided for control room isolation and remote shutdown of the valve. In case a fire occurs inside the control room per <10 CFR 50, Appendix R>, Method A.

RMs Remote-manual switch from shutdown panel. (Provided in addition to RMc, noted above, on selected valves as indicated.)

RMp Remote-manual switch from Postaccident Sampling System panel. Switches are keylocked closed.

AA Containment spray initiated.

BB Injection flow above setpoint (minimum flow valve control).

CC Discharge pressure below setpoint (minimum flow valve control).

DD Reactor vessel high water level - Level 8.

EE E51F510 closes.

FF E51F045 closes.

GG High drywell atmospheric radiation (9) Standard (Std) closure time, based upon nominal pipe diameter, is approximately 12 inches/minute for gate valves and approximately 4 inches/minute for globe valves. The standard closure time for butterfly valves is 30 to 60 seconds.

(10) AC motor-operated valves required for isolation functions are powered from the ac standby power buses. DC operated isolation valves are powered from the batteries.

(11) Testable check valves are designed for remote opening with zero differential pressure across the valve seat. The valves close under reverse flow conditions, even if the test switch is positioned to open. The valves open when pump pressure exceeds reactor pressure, even if the test switch is positioned to close.

(12) (Deleted)

(13) Main steam line isolation valves require that both solenoid pilots be de-energized to close. Accumulator air pressure plus spring act to close valves when both pilots are de-energized. Voltage failure at only one pilot does not cause valve closure. These valves are designed to close fully in 2.5 to 5 seconds <Section 5.4.5.3>.

(14) During reactor operation, a blind flange is installed on the outboard end of the transfer tube as the containment boundary. The IFTS containment isolation assembly receives a Type B test. When the blind flange is removed in Mode 1, 2, or 3, the containment boundary inside the containment building is made by the remaining portion of the transfer tube containment isolation assembly, containment bellows, and steel containment penetration, and outside the containment building by the transfer tube, drain line, drain valve, and local leak rate test valve. The portion of the tube outside of the blind flange receives a Type C test out to the drain line valve 1F42-F003. Opening of the drain line valve during Mode 1, 2, or 3 with the blind flange removed is addressed by administrative controls. These require a designated individual to take manual action to close the valve in the event of an accident.

(15) (Deleted)

(16) This receives a Type B test.

(17) (Deleted)

(18) (Deleted)

(19) The ECCS response time requirement for these injection valves is met with the valves partially opened. Times shown in this table are for full (100%) valve strokes.

(20) Division 3 power is also available by postaccident operator manual action (procedurally controlled).

(21) The feedwater check valves utilize an alternate non-type water leak testing methodology per the Inservice Testing Program to verify their proper closure.

(22) Location (see Note 5) of these valves inside (I) or outside (O) of containment varies depending on whether the inner or outer airlock door is open and/or inoperable.

(23) Non-ESF systems that would be desirable to use to mitigate the consequence of an accident.

(24) Applicable in Operational Modes 1, 2 and 3.

(25) Time delay associated with these valves. Maximum time to close (stroke time and delay) is 60 seconds or less.

(26) P51F0530 is a 2.0 check valve installed in the 2.5 line via reducers.

(27) This valve has been excluded from Type C testing since it does not constitute a potential primary containment atmospheric pathway during and following a Design Basis Accident (DBA).

Revision 20 6.2-207 October, 2017

TABLE 6.2-33 POTENTIAL SECONDARY CONTAINMENT BYPASS LEAKAGE PATHS(1)(2)(4)(5)(9)(10)(14)

Primary Line Bypass Expected Containment Size Leakage Air Leakage Penetration No. Description Valve No. Valve Type Loc. (in.) Barrier(3) Rate (SCCM)

P106 RCIC Turbine E51-F0068 Gate O 12.00 10(b) 190.0 Exhaust, RCIC E51-F0040 Noz.Chk. O 10.00 10(b) 2.0 Turbine Exhaust Vacuum Relief, and E12-F102 Glb. O 1.5 10(a) 23.8 RHR A&B Relief Valve Discharge to N27-F751 Glb. O 1.0 37 0.08 Suppression Pool P87-F083 Glb. O 0.50 57 0.0 P87-F264 Glb. O 0.50 57 0.0 See Note(15)

P108 Condensate Supply P11-F060 Btf. O 12.00 27(a) 0.63 P11-F545 Chk. I 12.00 27(a) 384.48 P109 ILRT Blowdown Line See Note(6) - - 8.00 35 0.00 P111 Condensate Return P11-F080 Btf. O 10.00 27(b) 0.52 P11-F090 Btf. I 10.00 27(b) 0.52 P11-F629 Relief I 0.50 27(b) See Note(17)

P114 Containment Vacuum M17-F015 Btf. O 24.00 19 3.60 Relief M17-F010 Chk. I 24.00 19 3.40 O-rings I 24.00 19 See Note(13)

P115 See P106 P117 Nitrogen Supply to P86-F002 Glb. O 2.00 41 64.88 CRD P86-F528 Chk. I 2.00 41 64.88 P119 ILRT Pressure See Note(6) - - 0.50 35 0.00 Indicating Line Revision 21 6.2-208 October, 2019

TABLE 6.2-33 (Continued)

Primary Line Bypass Expected Containment Size Leakage Air Leakage Penetration No. Description Valve No. Valve Type Loc. (in.) Barrier(3) Rate (SCCM)

P120 ILRT Pressurization See Note(6) - - 8.00 35(b) 0.00 Line P422 RCIC Turbine Supply E51-F0063 Gate I 10.00 1(c) 158.3 E51-F0064 Gate O 10.00 1(c) 158.3 E51-F0076 Glb. I 1.00 1(c) 15.8 P131 RWCU Pump Suction G33-F001 Gate I 6.00 49 192.24 G33-F004 Gate O 6.00 49 192.24 P201 Drywell Atm. Rad. D17-F079A Glb. O 1.00 52 0.58 Monitor Line D17-F079B Glb. I 1.00 52 0.58 D17-F071A Ball O 1.00 52 0.06 D17-F071B Ball I 1.00 52 0.06 P203 Fuel Pool Cooling G41-F100 Btf. O 8.00 26(a) 0.42 Supply G41-F522 Chk. I 8.00 26(a) 256.32 P204 CRD Supply C11-F083 Gate O 2.50 4 80.10 C11-F122 Chk. I 2.50 4 80.10 P205 Fuel Transfer Tube See Note(6)(16) - - - 36 0.00 F42-F003 Ball O 4.00 36 0.00 P208 Containment Vacuum M17-F025 Btf. O 24.00 19 3.60 Relief M17-F020 Chk. I 24.00 19 3.40 O-rings I 24.00 19 See Note(13)

P210 CO2 to Fire P54-F340 Gate O 4.00 42 128.16 Protection System P54-F1098 Chk. I 4.00 42 128.16 Revision 20 6.2-209 October, 2017

TABLE 6.2-33 (Continued)

Primary Line Bypass Expected Containment Size Leakage Air Leakage Penetration No. Description Valve No. Valve Type Loc. (in.) Barrier(3) Rate (SCCM)

P301 Fuel Pool Cooling G41-F145 Btf. O 10.00 26(b) 0.52 Return G41-F140 Btf. I 10.00 26(b) 0.52 G41-F801 Chk. I 0.75 26(b) See Note(17)

P305 Containment P53-F536/ Glb. O(18)/ 1.00 56 32.04 Personnel Air F570 O Locks(8) P53-F579A Ball O 1.00 56 -

P53-F579B Ball I(18) 1.00 56 -

P53-F580A Ball O(18) 1.00 56 -

P53-F580B Ball I 1.00 56 -

P53-F581 Relief I(18) 1.00 56 -

P53-F582 Relief I 1.00 56 -

P53-F010 Glb. O 0.75 - -

P53-F015 Glb. O(18) 0.75 - -

P53-F070 Glb. O 0.75 - -

P53-F556 Needle I 0.5 - -

P306 Instrument Air P52-F200 Glb. O 2.00 34 64.88 P52-F550 Chk. I 1.50 34 15.00 P308 Service Air P51-F150 Glb. O 2.50 32 0.13 P51-F530(19) Chk. I 2.50 32 80.10 P309 Demineralized P22-F010 Gate O 3.00 29 96.12 Water P22-F577 Chk. I 3.00 29 96.12 P310 NCC Water Supply P43-F055 Btf. O 12.00 25(a) 0.63 P43-F721 Chk. I 12.00 25(a) 384.48 Revision 21 6.2-210 October, 2019

TABLE 6.2-33 (Continued)

Primary Line Bypass Expected Containment Size Leakage Air Leakage Penetration No. Description Valve No. Valve Type Loc. (in.) Barrier(3) Rate (SCCM)

P311 NCC Water Return P43-F140 Btf. O 12.00 25(b) 0.63 P43-F215 Btf. I 12.00 25(b) 0.63 P43-F851 Relief I 0.25 25(b) See Note(17)

P312 Containment P53-F541/ Glb. O(18)/ 1.00 56 32.04 Personnel Air F571 O Locks(8) P53-F593A Ball O 1.00 56 -

P53-F593B Ball I(18) 1.00 56 -

P53-F594A Ball O(18) 1.00 56 -

P53-F594B Ball I 1.00 56 -

P53-F595 Relief I(18) 1.00 56 -

P53-F596 Relief I 1.00 56 -

P53-F020 Glb. O 0.75 - -

P53-F025 Glb. O(18) 0.75 - -

P53-F075 Glb. O 0.75 - -

P53-F561 Needle I 0.5 - -

V313 Containment Purge M14-F040 Btf. O 42.00 30(a) 6.30 Supply M14-F045 Btf. I 42.00 30(a) 6.30 M14-F190 Btf. I 18.00 30(a) 2.70 M14-F195 Btf. I 18.00 30(a) 2.70 V314 Containment Purge M14-F090 Btf. O 42.00 30(b) 6.30 Exhaust M14-F085 Btf. I 42.00 30(b) 6.30 M14-F200 Btf. I 18.00 30(b) 2.70 M14-F205 Btf. I 18.00 30(b) 2.70 P315 Standby Liquid C41-F518 Glb. O 2.00 60 0.16 Control C41-F520 Chk. I 2.00 60 0.16 Revision 21 6.2-211 October, 2019

TABLE 6.2-33 (Continued)

Primary Line Bypass Expected Containment Size Leakage Air Leakage Penetration No. Description Valve No. Valve Type Loc. (in.) Barrier(3) Rate (SCCM)

P317 Containment Radia- D17-F089A Glb. O 1.00 54 0.00 tion Monitoring D17-F089B Glb. I 1.00 54 0.00 Supply and Return D17-F081A Ball O 1.00 54 0.00 D17-F081B Ball I 1.00 54 0.00 ILRT Instrumentation See Note(6)

E61-F549 Glb. I 0.50 16.02 E61-F550 Glb. I 0.75 24.03 P318 Postaccident P87-F065 Sol. Glb. O 0.50 58 (b) 0.43 Sampling P87-F071 Sol. Glb. O 0.50 58 (b) 0.43 P87-F074 Sol. Glb. O 0.50 58 (b) 0.43 P87-F077 Sol. Glb. O 0.50 58 (b) 0.43 P319 ILRT E61-F551 Glb. I 0.75 24.03 Instrumentation E61-F552 Glb. I 0.50 16.02 See Note(6)

P401 Postaccident P87-F037 Sol. Glb. O 0.75 55 See Note(12)

Sampling P404 Chilled Water P50-F060 Btf. O 6.00 28(a) 0.32 Supply P50-F539 Chk. I 6.00 28(a) 192.24 P405 Chilled Water P50-F150 Btf. O 6.00 28(b) 0.32 Return P50-F140 Btf. I 6.00 28(b) 0.32 P50-F606 Relief I 0.25 28(b) See Note(17)

P406 Fire Protection P54-726 Gate O 4.00 51 128.16 Water P54-727 Gate I 4.00 51 128.16 Revision 19 6.2-212 October, 2015

TABLE 6.2-33 (Continued)

Primary Line Bypass Expected Containment Size Leakage Air Leakage Penetration No. Description Valve No. Valve Type Loc. (in.) Barrier(3) Rate (SCCM)

P413 Postaccident P87-F049 Sol. Glb. I 0.75 61 0.43 Sampling P87-F055 Sol. Glb. O 0.75 61 0.43 P87-F046 Sol. Glb. I 0.75 61 0.43 P87-F052 Sol. Glb. O 0.75 61 0.43 P87-F277 Relief I 0.25 61 0.0 P417 Drywell and G61-F080 Gate O 3.00 40 96.12 Containment Equip G61-F075 Gate I 3.00 40 96.12 Sump to Radwaste G61-F0655 Check I 0.75 40 0.0 P418 Drywell and G61-F170 Gate O 3.00 43 96.12 Containment G61-F165 Gate I 3.00 43 96.12 Floor Drain Sump G61-F657 Chk. I 0.75 43 See Note(17) to Radwaste P419 RWCU Pump Discharge G33-F054 Gate O 4.00 48 128.16 G33-F053 Gate I 4.00 48 128.16 P420 RWCU Backwash G50-F277 Gate O 4.00 46 128.16 Transfer Pump to G50-F272 Gate I 4.00 46 128.16 Radwaste G50-F823 Relief I 0.50 46 See Note(17)

P423 Main Steam Line B21-F019 Gate O 3.00 1(b) 90.78 Drain B21-F016 Gate I 3.00 1(b) 90.78 P424 RWCU to Main G33-F034 Gate O 4.00 14 128.16 Condenser and G33-F028 Gate I 4.00 14 128.16 Radwaste G33-F0646 Relief I 0.25 14 0.0 Revision 22 6.2-213 October, 2021

TABLE 6.2-33 (Continued)

Primary Line Bypass Expected Containment Size Leakage Air Leakage Penetration No. Description Valve No. Valve Type Loc. (in.) Barrier(3) Rate (SCCM)

P428 Containment Vacuum M17-F035 Btf. O 24.00 19 3.60 Relief M17-F030 Chk. I 24.00 19 3.40 O-rings I 24.00 19 See Note(13)

P429 RHR A&B Relief Valve Discharge to Suppression Pool, RCIC Turbine Exhaust and RCIC Pump Turbine Exhaust Vacuum Relief E12-F102 Glb. O 1.5 10(a) 23.8 E51-F068 Gate O 12.00 10(b) 190.0 N27-F751 Glb. O 1.0 37 0.08 P87-F083 Glb. O 0.50 57 0.0 P87-F264 Glb. O 0.50 57 0.0 See Note(15)

P436 Containment Vacuum M17-F045 Btf. O 24.00 19 3.60 Relief M17-F040 Chk. I 24.00 19 3.40 O-rings I 24.00 19 See Note(13)

Revision 19 6.2-214 October, 2015

TABLE 6.2-33 (Continued)

Size of Line Expected Penetrating Bypass Leakage Primary Termination Leakage Rate Containment (in.) Region Barrier (SCCM)

Lines Enclosed by Guard Pipes Main Steam 38 Environment Welded Conn. 0 Main Steam Drains 14 Environment Welded Conn. 0 Feedwater 32 Environment Welded Conn. 0 Reactor Core Isolation Cooling Steam Supply 22 Environment Welded Conn. 0 Reactor Core Isolation Cooling Pump Discharge and Residual Heat Removal Head Spray 18 Environment Welded Conn. 0 Reactor Water Cleanup Pump Suction 18 Environment Welded Conn. 0 Low Pressure Core Spray Pump Suction from Suppression Pool 36 Environment Welded Conn. 0 High Pressure Core Spray Pump Suction from Suppression Pool 36 Environment Welded Conn. 0 Residual Heat Removal A, B and C Suction from Suppression Pool 36 Environment Welded Conn. 0 Reactor Core Isolation Cooling Suction from Suppression Pool 18 Environment Welded Conn. 0 Residual Heat Removal Shutdown Supply Suction 32 Environment Welded Conn. 0 Reactor Water Cleanup Pump Discharge 16 Environment Welded Conn. 0 Reactor Water Cleanup from Regenerative Heat Exchanger to Feedwater 16 Environment Welded Conn. 0 Personnel Airlocks(8) 9-7 Environment Resilent Seals 0 Revision 12 6.2-215 January, 2003

TABLE 6.2-33 (Continued)

NOTES:

(1) A Technical Specification commitment of 10.08 percent of total design containment leakage is made for the maximum test leakage bypassing the containment annulus exhaust gas treatment system (for leakage sources in lines penetrating primary containment and personnel airlocks).

(2) Expected bypass water leakage sources from components that circulate core cooling water following LOCA:

a. Pumps - expected total leakage of 5 gal./day from residual heat removal, high pressure core spray, and low pressure core spray pumps.
b. Valves - expected total valve stem leakage of 300 cc/hr from systems handling reactor fluid outside containment.
c. FW-LCS, ECCS and RCIC Branch Lines - expected total leakage of 1.663 gal./hr.

(3) Bypass leakage barrier arrangement is shown on the designated detail of <Figure 6.2-60>.

(4) Closed Systems Outside Containment Piping systems which penetrate containment and are closed outside containment are tested for potential water leakage under the guidance of <NUREG-0737> Item III.D.1.1. The expected bypass water leakage from these systems is identified in Note 2 above. The limit on bypass water leakage is identified in

<Section 15.6.5.5.1.2.b>. Valves in closed systems outside containment, which are potential air leakage sources, are identified in the text of
. The redundant containment isolation provisions for each penetration consist of an isolation valve and a closed system outside containment which are in compliance with <10 CFR 50, Appendix A>, Criteria 54, and with GDCs 55 and 56, utilizing the other defined basis provision. The closed system is missile protected, Seismic Category I, Safety Class 2, and has a temperature and pressure rating in excess of that for containment. Revision 21 6.2-216 October, 2019 TABLE 6.2-33 (Continued) NOTES: (Continued) The following penetrations lead to closed systems outside containment: P101, P102, P103, P104, P105, P107, P112, P113, P118, P121(a), P123, P132, P401, P402, P403, P407, P408, P409, P410, P411, P412, P414(a), P421, P429, P431. NOTE: (a) These feedwater penetrations have a branch line leading to the RHRShutdown Cooling Return Line and the RWCU Return Line: - The RHRShutdown Cooling Return Line leads to RHR, which is considered a closed system outside containment. The branch line leading to RHR is examined for external leakage from mechanical joints (e.g., valve stem or bonnet, seals or gaskets). - The RWCU Return Line leads back into the containment, and is tested like a closed system outside containment, with the specific acceptance criteria that leakage exterior to the piping will be eliminated. - See
for testing details on containment penetrations. (5) Instrument Lines Instrument lines penetrating containment are assumed to allow zero bypass leakage. Valves in instrument lines penetrating containment are open post-LOCA in order to fulfill the instruments functions. The instruments are designed to allow zero bypass leakage. Penetrations containing instrument lines appear below: P102, P318, P320, P401, P402, P425, P433, P434 Revision 19 6.2-217 October, 2015 TABLE 6.2-33 (Continued) NOTES: (Continued) (6) Spectacle or Blind Flanges Penetrations which contain lines isolated by spectacle or blind flanges are assumed to allow zero bypass leakage. Spectacle and blind flanges are local leak rate tested. Penetrations whose lines are isolated by spectacle or blind flanges appear below: Unit 1: P109, P119, P120, P205, P317, P319 Unit 2: P428, P429, P427, P304 (7) Leakage Control System The feedwater system has a dedicated leakage control system <Section 6.9> which provides seal water to the bonnet, stem, and seat of the outboard gate valves (B21-F065A/B). Water leakage from the Feedwater Leakage Control System (FWLCS) piping, and from the bonnet, stem, and seat of the outboard gate valves, are controlled under the Primary Coolant Sources Outside Containment Program, Technical Specification 5.5.2. Outboard gate valve bonnet and stem leakage identified during the system walkdown at pressures >1000 psig will be eliminated. The gate valves will be closed during this check. Gate valve seat water leakage measured at 1.1 Pa will be limited by the Program, which restricts allowable leakages to half of that assumed in the dose calculations <Section 15.6.5.5.1.2.b>. This water leakage is not added into the secondary containment bypass air leakage totals. The FWLCS seals the feedwater lines going through the following penetrations: Unit 1: P121, P414 Unit 2: P112, P410 The leakage control systems meet single failure criteria, are missile protected, Seismic Category I, Safety Class 2, and have temperature and pressure ratings in excess of that for the containment. Revision 22 6.2-218 October, 2021 TABLE 6.2-33 (Continued) NOTES: (Continued) (8) The personnel airlock door seals are not considered a bypass leakage path when the outer door is operable because all leakage through the outer door seals is routed back into the annulus area between the annulus shield wall and containment where it is treated by the Annulus Exhaust Gas Treatment System. All direct leakage paths associated with the barrel/doors which may bypass the outer door seals under the various modes of operation/availability are assigned as bypass. P305, P312 (9) The air supply lines to the ADSaccumulators and personnel air lock door seal accumulators are not considered bypass leakage paths since they are safety-related lines that remain pressurized post-LOCA (at a pressure exceeding containment vessel design pressure.): P116, P304, P305, P312 (10) The following penetrations contain lines from more than one system, and therefore, may appear more than once in this table and in its notes: P102, P305, P312, P317, P319, P320, P401, P402, P425, P434 (11) (Deleted) (12) If valves leak, they will leak water. Expected leakage: none. Revision 19 6.2-219 October, 2015 TABLE 6.2-33 (Continued) NOTES: (Continued) (13) It is necessary to break O-ring seals to test the isolation valves for this penetration. After the valve test, the O-rings will be reinstalled and Type B tests performed. If the O-rings leak, they will be fixed to eliminate leakage. (14) The Alternate Hydrogen Purge System line (P302) is not a bypass leakage path because it ties into the Annulus Exhaust Gas Treatment System. (15) Leakage from test spacers E12D015A & E12D015B are considered bypass leakage. (16) The IFTS penetration (P205) is not normally considered a bypass leakage path because all leakage through the bellows and bellows assembly flange joints, is routed to the annulus area between the shield wall and containment where it is treated by the annulus exhaust gas treatment system. Any leakage into the IFTS tube is still considered a potential secondary containment bypass leakage path. With the blind flange removed, the bypass leakage path is the IFTS tube and the drain line and drain valve, 1F42-F003. (17) Leakage limits established per the ASMEOM Code IST Program. (18) Location (see column title) of these valves inside (I) and outside (O) of containment varies depending on whether the inner or outer air lock door is open and/or inoperable. (19) P51-F0530 is a 2.0 valve installed in the 2.5 line via reducers. Revision 19 6.2-220 October, 2015 TABLE 6.2-34 REACTOR COOLANT PRESSURE BOUNDARY INFLUENT LINES THAT PENETRATE CONTAINMENT/DRYWELL Isolation Devices(s)(1) Between Inside Drywell and Outside Influent Line Drywell Containment Containment Reference Section Feedwater Lines CV GP CV, MOV <Section 6.2.4.2.2.1.a.1> High Pressure Core Spray Line TCV - MOV <Section 6.2.4.2.2.1.a.2> Low Pressure Core Spray and Low Pressure Coolant Injection C Lines TCV - MOV <Section 6.2.4.2.2.1.a.3> Low Pressure Coolant Injection A and B Lines TCVMOVMOV <Section 6.2.4.2.2.1.a.3> Control Rod Drive Supply Line - CV MOV <Section 6.2.4.2.2.1.a.4> Reactor Core Isolation Cooling Return and Residual Heat Removal Head Spray Lines TCVGPTCV, MOV <Section 6.2.4.2.2.1.a.5> Standby Liquid Control Lines(2) CV EV - <Section 6.2.4.2.2.1.a.6> Residual Heat RemovalShutdown Cooling Return Lines - - CV, MOV <Section 6.2.4.2.2.1.a.7> Reactor Water Cleanup Discharge to Heat Exchangers - MOVMOV <Section 6.2.4.2.2.1.a.8> NOTES: (1) Isolation devices: CV - Check valveGP - Guard pipe EV - Explosive valve MOV - Motor-operated valve TCV - Testable check valve (2) These lines do not penetrate containment. Revision 12 6.2-221 January, 2003 TABLE 6.2-35 REACTOR COOLANT PRESSURE BOUNDARY EFFLUENT LINES THAT PENETRATE CONTAINMENT/DRYWELL Isolation Devices(s)(1) Between Inside Drywell and Outside Effluent Line Drywell Containment Containment Reference Section Main Steam LinesAOVGPAOV <Section 6.2.4.2.2.1.b.1> Main Steam Drains MOVGPMOV <Section 6.2.4.2.2.1.b.1> Reactor Core Isolation Cooling Steam Supply MOVGPMOV <Section 6.2.4.2.2.1.b.1> Reactor Water Cleanup to Pumps MOVGPMOV <Section 6.2.4.2.2.1.b.2> Reactor Water Cleanup to Condenser and Radwaste - MOVMOV <Section 6.2.4.2.2.1.b.2> Reactor Water Cleanup from Regenerative Heat Exchangers to Feedwater - MOVMOV <Section 6.2.4.2.2.1.b.2> Residual Heat RemovalShutdown Cooling Line MOV,CV GPMOV <Section 6.2.4.2.2.1.b.3> Recirculation System Sample Line - AOV(2) - <Section 6.2.4.2.2.1.b.4> NOTE: (1) Isolation devices: AOV - Air operated valve MOV - Motor-operated valve GP - Guard pipe CV - Check valve Revision 12 6.2-222 January, 2003 TABLE 6.2-36 PRIMARY CONTAINMENT ISOLATION FOR LINES THAT PENETRATE CONTAINMENT AND CONNECT TO THE SUPPRESSION POOL Isolation Device(s)(1) Outside Line Containment Reference Section Influent Lines Low Pressure Core SprayMOV <Section 6.2.4.2.2.2.a.1> Minimum Flow Line Low Pressure Core SprayMOV <Section 6.2.4.2.2.2.a.1> Test Line High Pressure Core SprayMOV <Section 6.2.4.2.2.2.a.1> Minimum Flow Line High Pressure Core SprayMOV <Section 6.2.4.2.2.2.a.1> Test Line Residual Heat RemovalMOV <Section 6.2.4.2.2.2.a.1> Suppression Pool Cooling and Test Line Residual Heat Removal Heat MOV <Section 6.2.4.2.2.2.a.1> Exchanger Dump to Suppression Pool Residual Heat RemovalMOV <Section 6.2.4.2.2.2.a.1> Minimum Flow Lines Reactor Core Isolation MOV <Section 6.2.4.2.2.2.a.2> Cooling Minimum Flow Line Reactor Core Isolation MOV, CV, RV <Section 6.2.4.2.2.2.c.3> Cooling Turbine Exhaust Line Residual Heat Removal Heat MOV <Section 6.2.4.2.2.2.a.3> Exchanger Vent to Suppression Pool Relief Valve Discharge RV, MOV <Section 6.2.4.2.2.2.a.3> Lines Effluent Lines Low Pressure Core SprayMOV <Section 6.2.4.2.2.2.b> Suction Line Revision 20 6.2-223 October, 2017 TABLE 6.2-36 (Continued) Isolation Device(s)(1) Outside Line Containment Reference Section Influent Lines (Continued) High Pressure Core SprayMOV <Section 6.2.4.2.2.2.b> Alternate Suction Line Reactor Core Isolation MOV <Section 6.2.4.2.2.2.b> Cooling System Alternate Suction Line Residual Heat RemovalMOV <Section 6.2.4.2.2.2.b> Suction Line NOTE: (1) Isolation devices: CV - Check valveMOV - Motor-operated valve RV - Relief valve Revision 12 6.2-224 January, 2003 TABLE 6.2-37 COMBUSTIBLE GAS CONTROL SYSTEM EQUIPMENT DESIGN AND PERFORMANCE DATA
a. Combustible Gas Mixing Units
1. Compressor Centrifugal Max inlet pressure, psia 23.3 Max discharge pressure, psia 29.13 Max inlet temperature, F 185 Max discharge temperature, F 238 Relative humidity (inlet), % 100 Capacity, scfm (Minimum) 500 Power requirement, BHP (Maximum) 60
2. Heat Exchanger (After Cooler) - Isolated from cooling water flow rate via closure of 1M51-F591A(B) valve.
Cooling Water RHR System Cooling Water Pressure (tube side), psig 160 Air Temperature in/out, F 238/238 Cooling Water Temp. in/out, F 140/140
3. Material Compressor Casing cast steel Shroud aluminum Impeller 17-4 ph S.S.
Heat Exchanger Tube 304 S.S.
4. Manufacturer Turbonetics Revision 19 6.2-225 October, 2015
TABLE 6.2-37 (Continued)
b. Combustible Gas Purging Drywell Isolation Valves Type globe Body SA-216, GR, WCB Stem SA-564 Disc SA-351, GR CF8M Seating Surface Stellite No. 6
c. Hydrogen Recombiner
1. Material Outer Structure Type 300 series S.S.
Inner Structure Incoloy 800 Heater Element Sheath Incoloy 800 Base Skid Type 300 series S.S.
2. Power Maximum, kW 75 Nominal, kW 50
3. Capacity, scfm (min.) 100
4. Temperatures Gas in, F 60 to 185 Outlet of heater section, F 1,150 to 1,450 Exhaust, F ~50 above ambient Revision 12 6.2-226 January, 2003
TABLE 6.2-37 (Continued)
5. Heaters Number 5 banks Max. heat flux, watts/in2 5.8 Max. sheath temperature, F 1,550
6. Manufacturer Westinghouse
d. Piping Material Carbon Steel Revision 12 6.2-227 January, 2003
TABLE 6.2-38 COMBUSTIBLE GAS CONTROL SYSTEM FAILURE ANALYSIS Component Malfunction Comments Drywell purge Failure of compressor Should operating compressors resulting in inability subsystem compressor to purge the drywell fail, will be of combustible gases manually shutdown. Redundant subsystem will maintain system capabilities. Valve Failure of valve control Should valve control control power power resulting in power fail, valves inability to open valves will remain shut: redundant subsystem will maintain system capabilities. Hydrogen Failure of recombiner to Should recombiner recombiner operate resulting in loss fail, redundant of hydrogen removal recombiner will capability maintain system capabilities. Hydrogen analyzer Failure of analyzer or Should the analyzer or sample system sample system fail, redundant analysis or sample system will maintain system capabilities. Revision 12 6.2-228 January, 2003 TABLE 6.2-39 DESIGN AND OPERATING PARAMETERS FOR HYDROGEN CONTROL System Used System System Design For Analysis Drywell/ Containment Atmosphere Mixing Two-500 scfm One-500 scfm compressors compressor Hydrogen Recombiner Two-100 scfm One-100 scfm recombiner recombiner Revision 12 6.2-229 January, 2003 TABLE 6.2-40 PRIMARY REACTOR CONTAINMENT PENETRATION AND CONTAINMENT ISOLATION VALVE LEAKAGE RATE TEST LIST Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P202 Equipment hatch B Double O-ring See Note(1) - - - P305 Lower Personnel Airlock Barrel B Inner door See Note(2) Outer door See Note(2) Inflatable gaskets See Note(1) Inflatable gaskets See Note(1) C P53F536/F570 See Note(3)(32) C P53F015/F070 See Note(32)/- C P53F556 C P53F035 See Note(7) C P53F579B See Note(32) C P52F160 - C P53F580B C P53F010 - C P53F581 See Note(32) C P53F030 - C P53F582 C P53F579A - C P53F580A See Note(32) P312 Upper Personnel Inner door See Note(2) Outer door See Note(2) Airlock Barrel B Inflatable gaskets See Note(1) Inflatable gaskets See Note(1) C P53F541/F571 See Note(3)(32) C P53F025/F075 See Note(32)/- C P53F561 C P53F045 See Note(7) C P53F593B See Note(32) C P52F170 - C P53F594B C P53F020 - C P53F595 See Note(32) C P53F040 - C P53F596 C P53F593A - C P53F594A See Note(32) P205 Fuel transfer tube B Double gasket See Note(1)(12) - - - C F42F003 See Note(30) P124 Main steam line A B C B21F022A See Note(3)(4)(12)(13) C B21F028A See Note(4)(13) P416 Main steam line B B C B21F022B See Note(3)(4)(12)(13) C B21F028B See Note(4)(13) P122 Main steam line C B C B21F022C See Note(3)(4)(12)(13) C B21F028C See Note(4)(13) P415 Main steam line D B C B21F022D See Note(3)(4)(12)(13) C B21F028D See Note(4)(13) Revision 19 6.2-230 October, 2015 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P121 Feedwater A, RHR, B - N27F559A See Note(5)(13) - B21F032A See Note(5)(13) RWCU Return to C B21F065A See Note(5)(13) Reactor Pressure C E12F053A See Note(7)(13)(31) Vessel - RWCU Closed System See Note(13)(31) P414 Feedwater B, RHR, B - N27F559B See Note(5)(13) - B21F032B See Note(5)(13) RWCU Return to C B21F065B See Note(5)(13) Reactor Pressure C E12F053B See Note(7)(13)(31) Vessel - RWCU Closed System See Note(13)(31) P102 RHR pump A suction - - E12F004A See Note(9)(13)(17)(34) - Closed system See Note(7) P402 RHR pump B suction - - E12F004B See Note(9)(13)(17)(34) - Closed system See Note(7) P403 RHR pump C suction - - E12F105 See Note(9)(13)(17)(34) - Closed system See Note(7) P421 RHR shutdown B - E12F009 See Note(12)(18)(34) - E12F008 See Note(18)(34) cooling suction - E12F550 See Note(18)(34) P105 RHR A min. flow & - - E12F011A See Note(9)(13)(16)(34) - Closed system (RHR) See Note(7) test; LPCS pump min. - E12F064A See Note(9)(13)(16)(34) - Closed system (RHR) See Note(7) flow & test; RHR Heat - E12F024A See Note(9)(13)(16)(34) - Closed system (RHR) See Note(7) Exchanger Dump to - E12F609 See Note(9)(13)(34) - E12F610 See Note(34) Suppression Pool; B E12D003A - - - SPCU Return Line - - - E21F011 See Note(9)(13)(16)(34) - Closed system (LPCS) See Note(7) - E21F012 See Note(9)(13)(16)(34) - Closed system (LPCS) See Note(7) P407 RHR B test and min. - - E12F011B See Note(9)(13)(16)(34) - Closed system (RHR) See Note(7) flow; RHR Heat - E12F064B See Note(9)(13)(16)(34) - Closed system (RHR) See Note(7) Exchanger Dump to - E12F024B See Note(9)(13)(16)(34) - Closed system (RHR) See Note(7) Suppression Pool B E12D003B - - - Revision 20 6.2-231 October, 2017 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P408 RHR C pump test, - C E12F064C See Note (6)(13)(16)(35) - Closed system (RHR) See Note(7) and minimum flow C E12F021 See Note(13)(16) - Closed system (RHR) See Note(7) line - - P107 RHR A relief valve - C E12F025B See Note(8)(13) - Closed system See Note(7) discharge to C E12F025C See Note(8)(13) - Closed system See Note(7) suppression pool C E12F005 See Note(8)(13) - Closed system See Note(7) C E12F055B See Note(8)(13) - Closed system See Note(7) C E12F055A See Note(8)(13) - Closed system See Note(7) C E12F025A See Note(8)(13) - Closed system See Note(7) B E12D015A - - - B E12D015B - - - C E12F102 See Note(3)(13)(26) C E51F068 - C - - C E21F018 See Note(8)(13) - Closed system See Note(7) C N27F751 See Note(3)(13) B N27D006 See Note(13) C P87F264 See Note(3) C P87F083 See Note(3) P429 RHR B relief valve - - Same as penetration Same as penetration discharge to P107 P107 suppression pool P422 Steam supply to B C E51F063 See Note(3)(12) C E51F064 - RCIC turbine C E51F076 See Note(3) C P118 RHR heat exchanger - C E12F558A See Note(13) C E12F073A See Note(13) vents to suppres- C sion vessel P431 RHR heat exchanger - C E12F558B See Note(13) C E12F073B See Note(13) vents to suppres- C sion vessel Revision 20 6.2-232 October, 2017 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P123 RCIC and RHR to RPV B - E51F066 See Note (12)(13)(34) head spray - E51F013 See Note(13)(34) - E12F023 See Note(3)(13)(34) P113 LPCI A to reactor - - E12F042A See Note(13)(34) - E12F027A See Note(13)(34) and RHR to cont. - E12F037A See Note(3)(13)(34) spray and cont. pool - E12F028A See Note(13)(34) cooling P412 LPCI B to reactor - - E12F042B See Note(13)(34) - E12F027B See Note(13)(34) and RHR to cont. - E12F037B See Note(3)(13)(34) spray and cont. pool - E12F028B See Note(13)(34) cooling P411 LPCI C to Reactor - - E12F041C See Note(13)(34) - E12F042C See Note(13)(34) P104 RCIC pump minimum - - - - flow line to C E51F019 See Note(3)(13)(16) - Closed system See Note(7) suppression pool P101 RCIC pump suction - - E51F031 See Note(9)(13)(17)(34) - Closed system See Note(7) P106 RCIC turbine exhaust - C E51F068 See Note(13)(26) - C E12F102 See Note(3)(13)(26) C E12F025B See Note(8)(13)(26) C E12F025C See Note(8)(13)(26) C E12F005 See Note(8)(13)(26) C E12F055B See Note(8)(13)(26) C E12F055A See Note(8)(13)(26) C E12F025A See Note(8)(13)(26) B E12D015A See Note(26) B E12D015B See Note(26) C E21F018 See Note(8)(13)(26) C N27F751 See Note(8)(13)(26) C P87F264 See Note(3)(26) C E51F0040 See Note(26) Revision 20 6.2-233 October, 2017 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P115 RCIC pump turbine - C E51F068 See Note (13)(26) exhaust vacuum - C E12F102 See Note(3)(13)(26) C E12F025B See Note(8)(13)(26) relief C E12F025C See Note(8)(13)(26) C E12F005 See Note(8)(13)(26) C E12F055B See Note(8)(13)(26) C E12F055A See Note(8)(13)(26) C E12F025A See Note(8)(13)(26) B E12D015A See Note(26) B E12D015B See Note(26) C E21F018 See Note(8)(13)(26) C N27F751 See Note(3)(13)(26) C P87F264 See Note(3)(26) C E51F0040 See Note(26) P401 HPCS pump suction - - E22F015 See Note(9)(13)(17)(34) - Closed system See Note(7) P410 HPCS pump discharge - - E22F005 See Note(13)(34) - E22F004 See Note(13)(34) to RPV P409 HPCS min. flow and - C E22F012 See Note(13)(16) - Closed system See Note(7) test line to C E22F035 See Note(8)(13)(16) - Closed system See Note(7) suppression pool C E22F023 See Note(13)(16) - Closed system See Note(7) P103 LPCS pump suction - - E21F001 See Note(9)(13)(17)(34) C Closed system See Note(7) P112 LPCS pump discharge - - E21F006 See Note(13)(34) - E21F005 See Note(13)(34) to RPV P423 Main steam line B C B21F016 See Note(3)(12) C B21F019 - drain P131 RWCU pump suction B C G33F001 See Note(12)(13) C G33F004 See Note(13) P419 RWCU pump discharge - C G33F053 - C G33F054 - P132 RWCU return to - C G33F040 - C G33F039 - feedwater Revision 20 6.2-234 October, 2017 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P424 RWCU to main - C G33F028 - C G33F034 - condenser and C G33F0646 See Note(8) radwaste P203 Fuel pool cooling - C G41F522 - C G41F100 - and cleanup supply P301 Fuel pool cooling - C G41F140 - C G41F145 - and cleanup system C G41F801 - return V313 Containment purge - supply C M14F045 See Note(3) C M14F040 - C M14F190 See Note(3) C M14F195 See Note(3)(28) V314 Containment purge - C M14F200 See Note(3) C M14F090 - exhaust C M14F085 See Note(3) C M14F205 See Note(3)(28) P404 Chilled water - C P50F539 See Note(13) C P50F060 See Note(13) supply P405 Chilled water - C P50F140 See Note(13) C P50F150 See Note(13) return C P50F606 See Note(8) P417 Drywell and con- - C G61F075 See Note(3) C G61F080 See Note(3) tainment equipment C G61F0655 drain sump pump discharge P418 Drywell and con- - C G61F165 See Note(3) C G61F170 See Note(3) tainment floor C G61F657 - drain sump pump discharge P309 Demineralized water - C P22F577 - C P22F010 - supply to containment Revision 19 6.2-235 October, 2015 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P420 RWCU backwash - C G50F272 - C G50F277 - transfer pump C G50F823 See Note(8) discharge to radwaste P310 Nuclear closed - C P43F721 See Note(13) C P43F055 See Note(13) cooling water supply P311 Nuclear closed - C P43F215 See Note(13) C P43F140 See Note(13) cooling water C P43F851 See Note(8) return P108 Condensate supply - C P11F545 - C P11F060 - P111 Condensate return - C P11F090 - C P11F080 - C P11F629 - P116 Air supply to ADS - C P57F524B See Note(15) C P57F015B See Note(15) accumulators P304 Air supply to ADS - C P57F524A See Note(15) C P57F015A See Note(15) accumulators P308 Service air - C P51F530 See Note(33) C P51F150 - P306 Instrument Air - C P52F550 - C P52F200 - P114 Containment Vacuum - C M17F010 - C M17F015 - Relief P208 Containment Vacuum - C M17F020 - C M17F025 - Relief P428 Containment Vacuum - C M17F030 - C M17F035 - Relief P436 Containment Vacuum - C M17F040 - C M17F045 - Relief P434 Containment Vacuum - A M17F055 and 1/4 orifice See Note(14) - - - Relief Revision 22 6.2-236 October, 2021 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P320 Containment Vacuum - A M17F065 and 1/4 orifice See Note (14) Relief P406 Fire Protection - C P54F727 - C P54F726 - Water P210 CO2 to Fire - C P54F1098 - C P54F340 - Protection P302 Backup H2 Purge - C M51F090 - C M51F110 - P425 Post-LOCA H2 - C M51F210A See Note(3)(14)(21)(23) - - - Analyzer C M51F220A See Note(3)(14)(22)(23) C M51F230A See Note(3)(14)(22)(23) C M51F240A See Note(3)(14)(21)(23) C M51F250A See Note(3)(14)(21)(23) P315 SLC Tank Refill - C C41F520 - C C41F518 - P318 Post-LOCA H2 - C M51F210B See Note(3)(14)(21)(23) - - - Analyzer C M51F220B See Note(3)(14)(22)(23) C M51F230B See Note(3)(14)(22)(23) C M51F240B See Note(3)(14)(21)(23) C M51F250B See Note(3)(14)(21)(23) C P87F071 See Note(3)(14)(23) C P87F065 See Note(3)(14)(23) - C P87F077 See Note(3)(14)(23) C P87F074 See Note(3)(14)(23) P109 ILRT Vent - B E61D017 - B E61D003 - B Blind flange P120 ILRT Pressurization - B E61D016 - B E61D001 - Line B Blind flange P119 ILRT Instrumentation - B E61D014 - B E61D015 - Revision 19 6.2-237 October, 2015 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P317 ILRT Instrumentation - C E61F549 See Note (3)(13)(23) B E61D007 See Note(13)(23) B Pipe cap See Note(13)(23) B E61D006 See Note(13)(23) C E61F550 See Note(3)(13)(23) B Pipe cap See Note(13)(23) P319 ILRT Instrumentation - C E61F551 See Note(3)(13)(23) B E61D005 See Note(13)(23) B Pipe cap See Note(13)(23) C E61F552 See Note(3)(13)(23) B E61D004 See Note(13)(23) B Pipe cap See Note(13)(23) P117 N2 Supply to CRD - C P86F528 - C P86F002 - P204 CRD to Reactor - C C11F122 See Note (13) C C11F083 See Note(13) Pressure Vessel P201 Drywell Atmosphere - C D17F071B See Note(3)(23) C D17F071A See Note(3) Radiation Monitor C D17F079B See Note(23) C D17F079A - P413 PASS - C P87F049 See Note(3)(23) C P87F055 See Note(3)(23) C P87F046 See Note(3)(23) C P87F052 See Note(3)(23) C P87F277 See Note(8)(23) P317 Containment Atmos- - C D17F081B See Note(3)(23) C D17F081A See Note(3) phere Radiation - C D17F089B See Note(23) C D17F089A - Monitor P319 Containment Atmos- - A 1/4 orifice and See Note(14)(23) - - - phere Monitoring D23F030B A 1/4 orifice and See Note(14)(23) D23F040B P320 Containment Atmos- - A 1/4 orifice and See Note(14)(23) - - - phere Monitoring D23F020B A 1/4 orifice and See Note(14)(23) D23F010B P425 Containment Atmos- - A 1/4 orifice and See Note(14) - - - phere Monitoring D23F050 Revision 19 6.2-238 October, 2015 TABLE 6.2-40 (Continued) Inboard Outboard Containment Containment Pene- Inboard Isolation Barrier Outboard Isolation Barrier Penetration tration Barrier Barrier Description/ Barrier Barrier Description/ No. Description Test Test Valve No. References Test Valve No. References P433 Containment Atmos- - A 1/4 orifice and See Note (14)(23) phere Monitoring D23F030A A 1/4 orifice and See Note(14)(23) D23F040A P434 Containment Atmos- - A 1/4 orifice and See Note(14)(23) - - - sphere Monitoring D23F010A A 1/4 orifice and See Note(14)(23) D23F020A P102 Suppression Pool - A G43F050A See Note(14)(23) - - - Makeup C C P402 Suppression Pool - A G43F050B See Note(14)(23) - - - Makeup C C P401 Suppression Pool - A G43F060 See Note(14)(23) - - - Makeup C C C P87F037 See Note(3)(9)(14)(23)(35) C Various Spares - A Capped - - - - Various Electrical - B Double O-rings See Note(11) - - - NOTES: (1) Penetration is sealed by a blind flange or door with double O-ring or double gasket seals. The gaskets or O-rings are leak checked by pressurizing the space between them. (2) Personnel air lock volume is pressurized to pressure (Pa) as given in technical specifications. During the airlock test, tie downs are installed on the inner door since it is not designed to withstand the full differential pressure across the door in the reverse direction. Pressurizing the air lock barrel also tests the air lock mechanical and electrical penetrations. (3) Leak testing direction for valves having a functional differential pressure of 15 psi or less will be in accordance with the ASME Code for Operation and Maintenance of Nuclear Power Plants (ASMEOM Code). Revision 20 6.2-239 October, 2017 TABLE 6.2-40 (Continued) NOTES: (Continued) (4) MSIV seat leakage rate shall not exceed 100 scfh for any main steam line with maximum total leakage for all four main steam lines less than or equal to 250 scfh. MSIV leakage is not included in the 0.60 La Type B and C test totals (Reference 33). (5) The <10 CFR 50, Appendix J> Type C test for the feedwater lines is provided by the Type C hydrostatic tests performed on the long term, high integrity leakage protection valves, i.e., the motor-operated gate valves (B21-F065A/B). Water leakage from the Feedwater Leakage Control System (FWLCS) piping, and from the bonnet, stem and seat of the motor-operated gate valves, are controlled under the Primary Coolant Sources Outside Containment Program, Technical Specification 5.5.2. Outboard gate valve bonnet and stem leakage identified during the system walkdown at pressure >1000 psig will be eliminated. The gate valves will be closed during this check. Gate valve seat water leakage measured at 1.1 Pa will be limited by the program, which restricts allowable leakages to half of that assumed in the dose calculations <Section 15.6.5.5.1.2.b>. This water leakage is not redundantly added into the Type C 0.60 La totals, secondary containment bypass air leakage totals or the hydrostatic test program totals. The feedwatercheck valves (N27-F559A/B and B21-F032A/B) utilize an alternate non-Type C water leak testing methodology per the Inservice Testing Program, to verify proper closure (see <Section 15.6.6.5.2.4>). (6) System remains water filled post-LOCA. Isolation valve tested with water to a pressure not less than 1.10 Pa. Isolation valve leakage not included in 0.60 La Type B and C test totals. (7) The redundant containment isolation provisions for this penetration consist of an isolation valve and a closed system outside containment which is in compliance with <10 CFR 50, Appendix A>, GDC 54, and with GDCs 55 and 56, utilizing the other defined basis provision. A single active failure can be accommodated. The closed system is missile protected, Seismic Category I, Safety Class 2, and has a temperature and pressure rating in excess of that for the containment. Closed system integrity is maintained and verified during system leak tests <NUREG-0737>, Item III.D.1.1. However, the portions of the Personnel Airlock Leakage Control System designated as closed systems to secondary containment (see P305 and P312) are not given closed system leak tests for the following reason. The closed system piping is routed to the annulus. The Annulus Exhaust Gas Treatment System maintains the annulus at a vacuum. Any post-LOCA containment atmosphere in the airlock leakage control lines will flow into the annulus. As a result, no containment atmosphere will bypass the annulus. Therefore, closed system tests at Pa on the airlock leakage control lines are unnecessary. (8) Relief valve. (9) System is sealed from the primary containment atmosphere because its line terminates below the water level of the suppression pool. Leakage is not included in 0.60 La Type B and C test totals. (10) (Deleted) (11) Modular type electrical penetration with header plate bolted to penetration nozzle. Double 0-ring seals with test connection is provided at interface. (12) Penetration design utilizes a double bellows for containment isolation. The bellows is leak checked by pressurizing the space between the inner and outer bellows. The fuel transfer tube bellows is sealed on both ends with double gasketed flange joints. These joints are leak checked by pressurizing the space between the double gaskets. The fuel transfer tube has a bellows assembly installed in the annulus to permit confirmatory leak testing of the fuel transfer tube bellows. The fuel transfer tube bellows is leak checked by pressurizing the annular space between the IFTS tube and the bellows assembly via a test connection on the bellows assembly. (13) System is not vented and drained for Type A test. This allowance for main steam lines is provided by (Reference 33). Revision 20 6.2-240 October, 2017 TABLE 6.2-40 (Continued) NOTES: (Continued) (14) Isolation valving for instrument lines which penetrate the containment conform to the requirements of <Regulatory Guide 1.11>. The ISI program will provide assurance of the operability and integrity of the isolation provisions. Type C testing will not be performed on the instrument line isolation valves. The instrument lines will be within the boundaries of the Type A test, open to the media (containment atmosphere or suppression pool water) to which they will be exposed under postulated accident conditions. Three exceptions to the above are Penetrations P401, P318 and P425. Isolation valves for the three penetrations include H2 Analyzer and Postaccident Sampling System Valves. The valves are normally closed post-LOCA, open only intermittently, and will therefore receive Type C tests. (15) System remains pressurized with air post-LOCA. (16) These lines are always filled with water on the outboard side of the containment, thereby forming a water seal. They are maintained at a pressure that is always higher than primary containment pressure by jockey pumps or hydrostatic head, thus precluding any outleakage from primary containment. However, even if outleakage did occur, it would be into an ESF system which forms a closed loop outside primary containment. Thus, any leakage from primary containment would return to primary containment through this closed loop. A system leakage test <NUREG-0737>, Item III.D.1.1. will be performed as described below to ensure the leak-tightness of the ECCS and RCIC systems. The systems will be pressurized with water and a leakage rate for the entire system will then be determined and compared to an acceptance limit. (17) The ECCS and RCIC suction lines are normally filled with water on both the inboard and outboard side of containment, thereby forming a water seal to the containment environment. The valves are open during post-LOCA conditions to supply a water source for the ECCS pumps. Since a break in an ECCS line need not be considered in conjunction with a DBA, the only possible situation requiring one of these valves to be closed during a DBA is an unacceptable leakage in an emergency core cooling system. However, because these ECCS systems are constantly monitored for excessive leakage, this is not a credible event. (18) During Type A test, this penetration is operational to provide shutdown cooling via the RHR system. (19) (Deleted) (20) (Deleted) (21) Post LOCA H2 Analyzer - Containment (22) Post LOCA H2 Analyzer - Drywell (23) Penetration contains more than one line (24) (Deleted) (25) (Deleted) Revision 20 6.2-241 October, 2017 TABLE 6.2-40 (Continued) NOTES: (Continued) (26) Valve E12F102 serves as a first isolation barrier for P107 and P429. Valve E51F068 serves as a second isolation barrier for P107 and P429. The RCIC Turbine Exhaust Line (P106) and the associated vacuum break line (P115) share common containment isolation valves: The first containment isolation for the penetrations are: E51F068 (automatic) and E12F102 (locked closed). The second containment isolation valve downstream of E51F068 is nozzle check valve E51F040 (not a simple check). Downstream of E12F0102 is the RHR Relief Lines to the Suppression Pool (P107 and P429). The first isolation valves/barriers for the RHR Relief Lines (P107 and P429) are also the second isolation valves/barriers for the RCIC Turbine Exhaust Line and the Vacuum Break Line (P106 and P115). These valves/barriers are: E12F005, E12F025A, E12F025B, E12F025C, E12F055A, E12F055B, E21F018, N27F751, P87F264 and spectacle flanges 1E12D015A and 1E12D015B. (27) (Deleted) (28) The containment purge 18-inch supply and exhaust lines are provided with double inboard isolation valves. For each 18-inch line, both inboard valves are Type C tested and the highest leakage is designated as the inboard barrier leakage. Leakage through the test connection between the 18-inch isolation valves is summed with the innermost 18-inch valve leakage. (29) (Deleted) (30) The portion of the large transfer tube piping outboard of the blind flange and down to the drain line valve 1F42-F003 (the portion of the tube which becomes exposed to containment air during the draining portion of the IFTS operation) will also be part of the leakage rate test boundary and will be tested with air. (31) The RWCU and RHR lines return water to the Reactor Vessel via the feedwater lines. The piping outboard of the containment is ASME Code Class 2, Seismic Category I, protected from pipe whip, missiles and jet forces, and analyzed for break exclusion. The branch line leading to the RHR closed system outside containment is examined for external leakage from mechanical joints (e.g., valve stem or bonnet, seals, and gaskets). The RWCU branch line leads directly back to containment penetration P132, and contains only mechanical joints, including the packing on the outboard containment isolation valve (G33-F039) for penetration P132 (see the P132 entry). This outboard valve (G33-F039), including the stem and bonnet, is already part of the air leak rate test program. The remainder of the RWCU piping between the feedwater line and penetration P132 will be added to the Technical Specification 5.5.2 Primary Coolant Sources Outside Containment Program, with a specific leakage acceptance limit of zero (0) external water leakage when tested at > 1000 psig. (32) Barrier Description of these valves inside (I) or outside (O) of containment varies depending on whether the inner or outer airlock door is open and/or inoperable. (33) P51F0530 is a 2.0 valve installed in the 2.5 line via reducers. (34) This valve has been excluded from Type C testing since it does not constitute a potential primary containment atmospheric pathway during and following a Design Basis Accident (DBA). (35) This system will be pressurized with water to a minmum pressure of 1.10 Pa and a leakage rate for the entire system will be compared to an acceptance limit. Revision 20 6.2-242 October, 2017 TABLE 6.2-41 CONTAINMENT LEAK RATE TEST DATA Type A Test Definitions A. Peak Test Pressure Pa = 7.80 psig The calculated peak containment internal pressure related to the design basis loss-of-coolant accident (LOCA). B. Maximum Allowable Leakage Rate at Pa La = 0.2% by weight of the contained atmosphere in 24 hrs. C. Measured Leakage Rate at Pa Lam Estimate of the leakage rate, derived as a function of the least squares slope and intercept, for the Type A test at pressure Pa obtained from testing the primary containment by simulating some of the conditions that would exist under design-basis accident conditions (e.g., vented, drained, flooded, or pressurized). D. Imposed Leakage Rate Lo The known leakage rate superimposed on the containment during the verification test. E. Composite Leakage Rate Lc The composite leakage rate is the algebraic sum of the calculated leakage rate La and the superimposed leakage rate Lo. Revision 21 6.2-243 October, 2019 TABLE 6.2-41 (Continued) Type A Test Definitions (Continued) F. Test Duration
1. After the containment atmosphere has stabilized, the integrated leakage rate test period begins.
The duration of the test period is sufficient to enable adequate data to be accumulated and statistically analyzed so that leakage rate and upper confidence limit can be accurately determined.
2. A Type A test shall last a minimum of eight hours after stabilization and shall have a total of not less than 30 sets of data points at approximately equal time intervals.
3. A Type A test cannot be success-fully terminated until the acceptance criteria of <Chapter 16>
are met. G. Containment Atmosphere Temperature 40°-120°F Limits During Type A Test H. Containment Free Air Volume 1,441,900 ft3 (includes drywell free air volume) I. Drywell Free Air Volume 276,500 ft3 Revision 21 6.2-244 October, 2019 TABLE 6.2-42 DELETED Revision 20 6.2-245 October, 2017 TABLE 6.2-43 HYDROGEN CONTROL SYSTEM EQUIPMENT DESIGN AND PERFORMANCE DATA
1. Number of Igniters
- Drywell 17 - Wetwell 12 - Enclosed Areas 22 - Containment 51 Total 102
2. Igniter Location Criteria 1 ESF Division operable:
(except drywell below 60 foot spacing not to exceed weir wall and containment 70 feet above refueling floor) 2 ESF Divisions operable 30 foot spacing not to exceed 35 feet
3. Igniter Assembly Power Systems Division of Manufacturer Morris Knudson
4. Igniter Operating Temperature 1,700F @ 12 volt ac
5. Igniter Transformer 0.2 KVA Dongan Model 52-20-472
6. Igniter Qualification 345F for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> Temperature
7. Igniter Qualification Pressure 33 psig
8. System Operation Manually via 2 control room handswitches (1 switch per division)
9. Power Supply 120 Vac +/- 10% from ESF Power Panels powered off of motor control centers from ESF buses (onsite and offsite AC power supplies)
Revision 12 6.2-246 January, 2003 TABLE 6.2-44 CONTAINMENT EQUIPMENT SURVIVABILITY LIST Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1B21N044C Pressure Transmitter Rx Vessel Level 622-4 120 43-3 318 73 (Fuel Zone) 1B21N044D Pressure Transmitter Rx Vessel Level 634-8 305 47-6-1/2 318 73 (Fuel Zone) 1B21N091A Pressure Transmitter Rx Vessel Level 622-7 53 52-0 318 73 (Wide Range) 1B21N091B Pressure Transmitter Rx Vessel Level 622-1 225 43-6 318 73 (Wide Range) 1B21N062A Pressure Transmitter Rx Vessel Pressure 624-6 53 53-2 318 73 1B21N062B Pressure Transmitter Rx Vessel Pressure 622-1 230 43-6 318 73 1D23N130A Containment RTD Containment 720-6 280 60 340(1) 70 Temperature Monitoring 1D23N130B Containment RTD Containment 720-6 100 60 340(1) 70 Temperature Monitoring 1D23N140A Containment RTD Containment 689-4 45 58 340(1) 70 Temperature Monitoring 1D23N140B Containment RTD Containment 689-4 210 58 340(1) 70 Temperature Monitoring 1D23N150A Containment RTD Containment 647-0 54 56 340(1) 70 Temperature Monitoring 1D23N150B Containment RTD Containment 645-6 251 56 340(1) 70 Temperature Monitoring 1D23N160A Containment RTD Containment 613-0 69 56 340(1) 70 Temperature Monitoring Revision 20 6.2-247 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1D23N160B Containment RTD Containment 613-0 251 56 340(1) 70 Temperature Monitoring 1E12F028A Containment Spray Containment 643-6 37 55-6 340 105 Inboard Isolation Spray Valve (MO) 1E12F028B Containment Spray Containment 643-9 335 56-3 340 105 Inboard Isolation Spray Valve (MO) 1E12F042A LPCI Inboard Low Pressure 628-0 41 44-0 340 105 Isolation Valve (MO) Coolant Injection 1E12F042B LPCI Inboard Low Pressure 628-0 315 55-6 340 105 Isolation Valve (MO) Coolant Injection 1E12F537A Containment Spray Containment 692-0 40 58-0 340 105 Valve (MO) Spray 1E12F537B Containment Spray Containment 692-0 320 58-0 340 105 Valve (MO) Spray 1G41F140 FPCC Inboard Containment 629-5 228 59 340 105 Isolation Valve (MO) Venting 1M17F010 Containment Vacuum Containment 693-0 58 60 250 30 Relief System Vacuum Relief Check Valve 1M17F020 Containment Vacuum Containment 693-0 150 60 250 30 Relief System Vacuum Relief Check Valve 1M17F030 Containment Vacuum Containment 693-0 302 60 250 30 Relief System Vacuum Relief Check Valve 1M17F040 Containment Vacuum Containment 693-0 315 60 250 30 Relief System Vacuum Relief Check Valve Revision 20 6.2-248 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1M51C001A Hydrogen Mixing Hydrogen Mixing 664-7 300 24 192 80 Compressor and Motor 1M51C001B Hydrogen Mixing Hydrogen Mixing 664-7 245 25 192 80 Compressor and Motor 1M51D001A Hydrogen Recombiner Removal of 664-7 304 31 1,700 - 45.3 Hydrogen by 1,750 Hydrogen and (Heater Oxygen Element) Recombination 1M51D001B Hydrogen Recombiner Removal of 664-7 236 30 1,700 - 45.3 Hydrogen by 1,750 Hydrogen and (Heater Oxygen Element) Recombination 1M51F010A Hydrogen Mixing Drywell Isolation 667-7 309 25-6 340 105 Compressor Isolation Valve (MO) 1M51F010B Hydrogen Mixing Drywell Isolation 667-7 245 22 340 105 Compressor Isolation Valve (MO) 1M51F020A Combustible Gas Compressor 666-0 300 32 340 105 Control System Cooling Water Supply Valve (MO) 1M51F020B Combustible Gas Compressor 666-0 255 30 340 105 Control System Cooling Water Supply Valve (MO) 1M51F501A Hydrogen Mixing Check Valve 666-0 305 27 350 300 Compressor for Drywell Purge Check Valve Compressor 1M51F501B Hydrogen Mixing Check Valve 665-3 250 23 350 300 Compressor for Drywell Purge Check Valve Compressor Revision 20 6.2-249 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1M56S001 Hydrogen Ignition Hydrogen Ignition 611-6 352 48-6 345 33 System 1M56S002 Hydrogen Ignition Hydrogen Ignition 612-6 4 49-0 345 33 System 1M56S003 Hydrogen Ignition Hydrogen Ignition 619-6 69 54-6 345 33 System 1M56S004 Hydrogen Ignition Hydrogen Ignition 619-6 89 54-3 345 33 System 1M56S005 Hydrogen Ignition Hydrogen Ignition 662-6 34 57-0 345 33 System 1M56S006 Hydrogen Ignition Hydrogen Ignition 687-4 36 52-3 345 33 System 1M56S023 Hydrogen Ignition Hydrogen Ignition 619-6 54 54-0 345 33 System 1M56S024 Hydrogen Ignition Hydrogen Ignition 619-6 116 52-0 345 33 System 1M56S025 Hydrogen Ignition Hydrogen Ignition 619-6 150 51-7 345 33 System 1M56S026 Hydrogen Ignition Hydrogen Ignition 619-6 185 51-8 345 33 System 1M56S027 Hydrogen Ignition Hydrogen Ignition 619-6 221 51-9 345 33 System 1M56S028 Hydrogen Ignition Hydrogen Ignition 619-6 251 53-8 345 33 System 1M56S029 Hydrogen Ignition Hydrogen Ignition 619-6 289 53-4 345 33 System 1M56S030 Hydrogen Ignition Hydrogen Ignition 619-6 324 53-3 345 33 System Revision 20 6.2-250 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1M56S031 Hydrogen Ignition Hydrogen Ignition 638-0 359 41-6 345 33 System 1M56S032 Hydrogen Ignition Hydrogen Ignition 640-0 155 46-0 345 33 System 1M56S033 Hydrogen Ignition Hydrogen Ignition 640-0 187 46-0 345 33 System 1M56S034 Hydrogen Ignition Hydrogen Ignition 640-0 324 53-6 345 33 System 1M56S035 Hydrogen Ignition Hydrogen Ignition 640-4-3/4 61 51-6 345 33 System 1M56S036 Hydrogen Ignition Hydrogen Ignition 640-5-1/2 118 51-6 345 33 System 1M56S037 Hydrogen Ignition Hydrogen Ignition 640-5 227 46-0 345 33 System 1M56S038 Hydrogen Ignition Hydrogen Ignition 639-4 261 54-0 345 33 System 1M56S039 Hydrogen Ignition Hydrogen Ignition 651-1 286 41-6 345 33 System 1M56S040 Hydrogen Ignition Hydrogen Ignition 647-4 2 41-6 345 33 System 1M56S041 Hydrogen Ignition Hydrogen Ignition 650-6-3/4 41 50-6 345 33 System 1M56S042 Hydrogen Ignition Hydrogen Ignition 650-6 87 49-0 345 33 System 1M56S043 Hydrogen Ignition Hydrogen Ignition 651-0 101 49-0 345 33 System 1M56S044 Hydrogen Ignition Hydrogen Ignition 660-0 86 44-6 345 33 System Revision 20 6.2-251 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1M56S045 Hydrogen Ignition Hydrogen Ignition 660-6 95 48-6 345 33 System 1M56S046 Hydrogen Ignition Hydrogen Ignition 664-0 54 51-0 345 33 System 1M56S047 Hydrogen Ignition Hydrogen Ignition 665-0 114 52-0 345 33 System 1M56S048 Hydrogen Ignition Hydrogen Ignition 662-6 147 53-0 345 33 System 1M56S049 Hydrogen Ignition Hydrogen Ignition 662-7-3/4 218 51-0 345 33 System 1M56S050 Hydrogen Ignition Hydrogen Ignition 664-7 251 49-6 345 33 System 1M56S051 Hydrogen Ignition Hydrogen Ignition 661-6 289 50-0 345 33 System 1M56S052 Hydrogen Ignition Hydrogen Ignition 661-6 324 49-6 345 33 System 1M56S053 Hydrogen Ignition Hydrogen Ignition 669-6 0 54-6 345 33 System 1M56S054 Hydrogen Ignition Hydrogen Ignition 684-9 355 52-6 345 33 System 1M56S055 Hydrogen Ignition Hydrogen Ignition 686-0 75 48-0 345 33 System 1M56S056 Hydrogen Ignition Hydrogen Ignition 686-0 85 47-0 345 33 System 1M56S057 Hydrogen Ignition Hydrogen Ignition 686-0 95 47-0 345 33 System 1M56S058 Hydrogen Ignition Hydrogen Ignition 686-0 105 48-0 345 33 System Revision 20 6.2-252 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1M56S059 Hydrogen Ignition Hydrogen Ignition 686-0 75 35-0 345 33 System 1M56S060 Hydrogen Ignition Hydrogen Ignition 686-0 105 35-0 345 33 System 1M56S061 Hydrogen Ignition Hydrogen Ignition 689-6 45 48-0 345 33 System 1M56S062 Hydrogen Ignition Hydrogen Ignition 689-6 133 41-0 345 33 System 1M56S063 Hydrogen Ignition Hydrogen Ignition 689-6 229 48-0 345 33 System 1M56S064 Hydrogen Ignition Hydrogen Ignition 689-6 252 43-6 345 33 System 1M56S065 Hydrogen Ignition Hydrogen Ignition 689-6 289 43-0 345 33 System 1M56S066 Hydrogen Ignition Hydrogen Ignition 689-6 310 48-6 345 33 System 1M56S067 Hydrogen Ignition Hydrogen Ignition 715-6 359 58-9 345 33 System 1M56S068 Hydrogen Ignition Hydrogen Ignition 715-6 27 58-9 345 33 System 1M56S069 Hydrogen Ignition Hydrogen Ignition 715-6 62 58-9 345 33 System 1M56S070 Hydrogen Ignition Hydrogen Ignition 715-6 87 58-9 345 33 System 1M56S071 Hydrogen Ignition Hydrogen Ignition 715-6 119 58-9 345 33 System 1M56S072 Hydrogen Ignition Hydrogen Ignition 715-6 151 58-9 345 33 System Revision 20 6.2-253 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1M56S073 Hydrogen Ignition Hydrogen Ignition 715-6 178 58-9 345 33 System 1M56S074 Hydrogen Ignition Hydrogen Ignition 715-6 209 58-9 345 33 System 1M56S075 Hydrogen Ignition Hydrogen Ignition 715-6 241 58-9 345 33 System 1M56S076 Hydrogen Ignition Hydrogen Ignition 715-6 273 58-9 345 33 System 1M56S077 Hydrogen Ignition Hydrogen Ignition 715-6 300 58-9 345 33 System 1M56S078 Hydrogen Ignition Hydrogen Ignition 715-6 331 58-9 345 33 System 1M56S079 Hydrogen Ignition Hydrogen Ignition 745-6 359 48-0 345 33 System 1M56S080 Hydrogen Ignition Hydrogen Ignition 745-6 34 48-0 345 33 System 1M56S081 Hydrogen Ignition Hydrogen Ignition 745-6 72 48-0 345 33 System 1M56S082 Hydrogen Ignition Hydrogen Ignition 745-6 102 48-0 345 33 System 1M56S083 Hydrogen Ignition Hydrogen Ignition 745-6 143 48-0 345 33 System 1M56S084 Hydrogen Ignition Hydrogen Ignition 745-6 180 48-0 345 33 System 1M56S085 Hydrogen Ignition Hydrogen Ignition 745-6 216 48-0 345 33 System 1M56S086 Hydrogen Ignition Hydrogen Ignition 745-6 252 48-0 345 33 System Revision 20 6.2-254 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1M56S087 Hydrogen Ignition Hydrogen Ignition 745-6 287 48-0 345 33 System 1M56S088 Hydrogen Ignition Hydrogen Ignition 745-6 324 48-0 345 33 System 1M56S089 Hydrogen Ignition Hydrogen Ignition 757-0 0 1-0 345 33 System 1M56S090 Hydrogen Ignition Hydrogen Ignition 757-0 180 1-0 345 33 System 1M56S091 Hydrogen Ignition Hydrogen Ignition 645-7 168 60-0 345 33 System 1M56S092 Hydrogen Ignition Hydrogen Ignition 645-0 172 58-0 345 33 System 1M56S093 Hydrogen Ignition Hydrogen Ignition 613-4 7 44-0 345 33 System 1M56S094 Hydrogen Ignition Hydrogen Ignition 612-5 13 42-8 345 33 System 1M56S095 Hydrogen Ignition Hydrogen Ignition 612-6 344 42-6 345 33 System 1M56S096 Hydrogen Ignition Hydrogen Ignition 612-3 351 43-6 345 33 System 1M56S097 Hydrogen Ignition Hydrogen Ignition 638-8 289 49-6 345 33 System 1M56S098 Hydrogen Ignition Hydrogen Ignition 685-6 342 53-0 345 33 System 1M56S099 Hydrogen Ignition Hydrogen Ignition 685-6 17 50-6 345 33 System 1M56S100 Hydrogen Ignition Hydrogen Ignition 686-0 75 25-0 345 33 System Revision 20 6.2-255 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1M56S101 Hydrogen Ignition Hydrogen Ignition 686-0 105 25-0 345 33 System 1R72S001 Electrical Penetrations Containment 659-0 221 60 340 108 Boundary 1R72S002 Electrical Penetrations Containment 659-0 228 60 340 108 Boundary 1R72S003 Electrical Penetrations Containment 656-3 221 60 340 108 Boundary 1R72S004 Electrical Penetrations Containment 657-1-1/2 248 60 340 108 Boundary 1R72S005 Electrical Penetrations Containment 656-3 228 60 340 108 Boundary 1R72S006 Electrical Penetrations Containment 657-1-1/2 242 60 340 108 Boundary 1R72S007 Electrical Penetrations Containment 651-6 221 60 340 108 Boundary 1R72S008 Electrical Penetrations Containment 649-9 221 60 340 108 Boundary 1R72S009 Electrical Penetrations Containment 651-6 248 60 340 108 Boundary 1R72S010 Electrical Penetrations Containment 649-9 248 60 340 108 Boundary 1R72S011 Electrical Penetrations Containment 657-1-1/2 235 60 340 108 Boundary 1R72S012 Electrical Penetrations Containment 651-6 228 60 340 108 Boundary 1R72S013 Electrical Penetrations Containment 649-9 228 60 340 108 Boundary Revision 20 6.2-256 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1R72S014 Electrical Penetrations Containment 651-6 242 60 340 108 Boundary 1R72S015 Electrical Penetrations Containment 649-9 242 60 340 108 Boundary 1R72S016 Electrical Penetrations Containment 643-3 221 60 340 108 Boundary 1R72S017 Electrical Penetrations Containment 641-6 221 60 340 108 Boundary 1R72S018 Electrical Penetrations Containment 643-3 228 60 340 108 Boundary 1R72S019 Electrical Penetrations Containment 641-6 228 60 340 108 Boundary 1R72S020 Electrical Penetrations Containment 643-3 248 60 340 108 Boundary 1R72S021 Electrical Penetrations Containment 641-6 241 60 340 108 Boundary 1R72S022 Electrical Penetrations Containment 643-3 242 60 340 108 Boundary 1R72S023 Electrical Penetrations Containment 641-6 248 60 340 108 Boundary 1R72S024 Electrical Penetrations Containment 643-3 235 60 340 108 Boundary 1R72S025 Electrical Penetrations Containment 651-6 235 60 340 108 Boundary 1R72S026 Electrical Penetrations Containment 638-4 221 60 340 108 Boundary 1R72S027 Electrical Penetrations Containment 638-4 228 60 340 108 Boundary Revision 20 6.2-257 October, 2017 TABLE 6.2-44 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) 1R72S028 Electrical Penetrations Containment 641-6 223 60 340 108 Boundary 1R72S029 Electrical Penetrations Containment 656-3 223 60 340 108 Boundary 1R72S030 Electrical Penetrations Containment 643-3 223 60 340 108 Boundary 1R72S031 Electrical Penetrations Containment 649-9 223 60 340 108 Boundary 1R72S032 Electrical Penetrations Containment 657-1-1/2 241 60 340 108 Boundary 1R72S033 Electrical Penetrations Containment 649-9 235 60 340 108 Boundary 1R72S035 Electrical Penetrations Containment 641-6 242 60 340 108 Boundary 1R72S036 Electrical Penetrations Containment 649-9 241 60 340 108 Boundary 1R72S038 Electrical Penetrations Containment 651-6 241 60 340 108 Boundary Upper Personnel 692-10 225 60 330 60 Airlock Seal Lower Personnel 599-9 241 60 330 60 Airlock Seal Equipment Hatch Seal 620-6 133 60 330 60 Control Cable and Various Locations 346 113 Small Power Cable Instrument Cable Various Locations 346(2) 113 NOTES: (1) RTD qualified to 485F for 30 seconds and then 340F for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. (2) Instrument cable qualified to 385F for 12 minutes and then 346F for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Revision 20 6.2-258 October, 2017 TABLE 6.2-45 DRYWELL EQUIPMENT SURVIVABILITY LIST Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) Manufacturer Model 1B21F041A Automatic Depressuri- RPV Pressure 636-5 51 20 355 60 Dikkers G471-zation System Valve Relief/ADS 6/125.04 1B21F041B Automatic Depressuri- RPV Pressure 636-5 277 26 355 60 Dikkers G471-zation System Valve Relief/ADS 6/125.04 1B21F041E Automatic Depressuri- RPV Pressure 636-5 31 21 355 60 Dikkers G471-zation System Valve Relief/ADS 6/125.04 1B21F041F Automatic Depressuri- RPV Pressure 636-5 289 26 355 60 Dikkers G471-zation System Valve Relief/ADS 6/125.04 1B21F047D Automatic Depressuri- RPV Pressure 636-5 308 20 355 60 Dikkers G471-zation System Valve Relief/ADS 6/125.04 1B21F047H Automatic Depressuri- RPV Pressure 636-5 322 21 355 60 Dikkers G471-zation System Valve Relief/ADS 6/125.04 1B21F051C Automatic Depressuri- RPV Pressure 636-5 88 25 355 60 Dikkers G471-zation System Valve Relief/ADS 6/125.04 1B21F051G Automatic Depressuri- RPV Pressure 636-5 71 26 355 60 Dikkers G471-zation System Valve Relief/ADS 6/125.04 1B21F410A Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F410B Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F411A Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F411B Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid Revision 12 6.2-259 January, 2003 TABLE 6.2-45 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) Manufacturer Model 1B21F414A Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F414B Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F415A Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F415B Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F422A Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F422B Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F425A Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F425B Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F442A Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F442B Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1B21F444A Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid Revision 22 6.2-260 October, 2021 TABLE 6.2-45 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) Manufacturer Model 1B21F444B Automatic Depressuri- RPV Pressure Location Same as 355 50 Seitz 6A39 zation System Valve Relief/ADS ADS Valve Solenoid 1D23N100A Drywell RTD Drywell Temperature 653-8 315 17 340(1) 70 Weed 611 Monitoring 1D23N100B Drywell RTD Drywell Temperature 653-8 135 16 340(1) 70 Weed 611 Monitoring 1D23N110A Drywell RTD Drywell Temperature 634-0 308 36-6 340(1) 70 Weed 611 Monitoring 1D23N110B Drywell RTD Drywell Temperature 634-0 145 36-6 340(1) 70 Weed 611 Monitoring 1D23N120A Drywell RTD Drywell Temperature 605-0 308 36-6 340(1) 70 Weed 611 Monitoring 1D23N120B Drywell RTD Drywell Temperature 604-6 150 36-6 340(1) 70 Weed 611 Monitoring 1M56S008 Hydrogen Ignition Hydrogen Ignition 629-1-1/2 12 36-6 345 33 Power Systems 6043 System 1M56S009 Hydrogen Ignition Hydrogen Ignition 637-0 41 36-6 345 33 Power Systems 6043 System 1M56S010 Hydrogen Ignition Hydrogen Ignition 636-3-1/2 90 36-6 345 33 Power Systems 6043 System 1M56S011 Hydrogen Ignition Hydrogen Ignition 636-7 137 36-6 345 33 Power Systems 6043 System 1M56S012 Hydrogen Ignition Hydrogen Ignition 632-3 180 36-6 345 33 Power Systems 6043 System 1M56S013 Hydrogen Ignition Hydrogen Ignition 631-5 221 36-6 345 33 Power Systems 6043 System 1M56S014 Hydrogen Ignition Hydrogen Ignition 636-10 273 36-6 345 33 Power Systems 6043 System Revision 12 6.2-261 January, 2003 TABLE 6.2-45 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) Manufacturer Model 1M56S015 Hydrogen Ignition Hydrogen Ignition 630-9-1/2 322 36-6 345 33 Power Systems 6043 System 1M56S016 Hydrogen Ignition Hydrogen Ignition 660-0 0 31-6 345 33 Power Systems 6043 System 1M56S017 Hydrogen Ignition Hydrogen Ignition 659-8 57 29-6 345 33 Power Systems 6043 System 1M56S018 Hydrogen Ignition Hydrogen Ignition 659-8 114 30-0 345 33 Power Systems 6043 System 1M56S019 Hydrogen Ignition Hydrogen Ignition 659-8 172 30-0 345 33 Power Systems 6043 System 1M56S020 Hydrogen Ignition Hydrogen Ignition 659-8 225 28-0 345 33 Power Systems 6043 System 1M56S021 Hydrogen Ignition Hydrogen Ignition 660-0 280 30-0 345 33 Power Systems 6043 System 1M56S022 Hydrogen Ignition Hydrogen Ignition 660-0 317 31-0 345 33 Power Systems 6043 System 1M56S102 Hydrogen Ignition Hydrogen Ignition 670-0 350 13-0 345 33 Power Systems 6043 System 1M56S103 Hydrogen Ignition Hydrogen Ignition 670-0 4 13-0 345 33 Power Systems 6043 System Control Cable and Drywell 346 113 Rockbestos EKB-2 Small Power Cable (Various Locations) Instrument Cable (Various Locations) 346(2) 113 Brand-Rex EKC-1 Drywell Personnel Containment 599-9 105 36-6 330 60 W.J. Wooley Airlock Seal Boundary Revision 12 6.2-262 January, 2003 TABLE 6.2-45 (Continued) Equipment Rx Qualification Identification Equipment Centerline Pressure Number Description Function Elevation Azimuth Distance Temp (F) (psig) Manufacturer Model Drywell Equipment Containment 599-9 227 36-6 330 Newport News Hatch Seal Boundary Industrial Corp. NOTES: (1) RTD qualified to 485F for 30 seconds and then 340F for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. (2) Instrument cable qualified to 385F for 12 minutes and then 346F for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Revision 12 6.2-263 January, 2003 TABLE 6.2-46 PERRY CLASIX-3 RESULTS SORV(2) DWB(3) Number of burns DW(1) 0 0 [1] WW 32 30 [8] CT 2 0 [1] Total H2 Burned (lbm) DW 0 0 [117] WW 1,220 1,361 [472] CT 791 0 [340] H2 Remaining (lbm) DW 15 692 [203] WW 293 151 [41] CT 294 409 [81] Peak Temp. (F) DW 191 (154) 251 [643] WW 1,762 (1,364) 1,201 [1,763] CT 760 (236) 192 [587] Peak Pressure (psig) DW 15.9 (10.7) 13.8 [17.3] WW 21.1 (12.6) 12.2 [19.4] CT 21.2 (9.9) 10.9 [19.4] NOTES: (1) Drywell, wetwell and containment are abbreviated as DW, WW and CT. (2) ( ) Maxima due to wetwell burns. (3) [ ] Values due to extension past end of hydrogen release. Revision 12 6.2-264 January, 2003 6.3 EMERGENCY CORE COOLING SYSTEMS 6.3.1 DESIGN BASES AND

SUMMARY

DESCRIPTION

<Section 6.3.1> provides the design bases for the emergency core cooling systems (ECCS), a summary description of the several systems as an introduction to the more detailed design descriptions provided in

<Section 6.3.2>, and the performance analysis provided in

<Section 6.3.3>. <Appendix 15B>, Reload Safety Analysis provides the results of a performance analysis for the new (reload) fuel designs.

6.3.1.1 Design Bases 6.3.1.1.1 Performance and Functional Requirements The ECCS is designed to provide protection against postulated loss-of-coolant accidents (LOCA) caused by ruptures in primary system piping. The functional requirements (for example, coolant delivery rates) specified in detail in
are such that the system performance under all LOCA conditions postulated in the design satisfies the requirements of <10 CFR 50.46>, Acceptance Criteria for Emergency Core Cooling System for Light Water Cooled Nuclear Power Reactors. These requirements, the most important of which is that the post-LOCA peak cladding temperature be limited to 2,200F, are summarized in <Section 6.3.3.2>. In addition, the ECCS is designed to following requirements:
a. Protection is provided for any primary system line break up to and including the double-ended break of the largest line.
b. Two independent phenomenological cooling methods (flooding and spraying) are provided to cool the core.
Revision 12 6.3-1 January, 2003
c. One high pressure cooling system is provided which is capable of maintaining water level above the top of the core and eliminating the need for automatic depressurization system actuation for line breaks of less than 1 inch nominal diameter.
d. No operator action is required until 10 minutes after an accident to allow for operator assessment and decision.
e. The ECCS is designed to satisfy all criteria specified in this section for any normal mode of reactor operation.
f. A sufficient water source and the necessary piping, pumps and other hardware are provided so that the containment and reactor core can be flooded for possible core heat removal following a LOCA.
6.3.1.1.2 Reliability Requirements The following reliability requirements apply:
a. The ECCS conforms to licensing requirements, and good design practices of isolation, separation and common mode failure considerations.
b. To meet the above requirements, the ECCS network shall have built-in redundancy so that adequate cooling can be provided, even in the event of specified failures. As a minimum, the following equipment shall make up the ECCS:
1. 1 High Pressure Core Spray (HPCS)
2. 1 Low Pressure Core Spray (LPCS)
3. 3 Low Pressure Coolant Injection (LPCI) Loops
4. 1 Automatic Depressurization System (ADS)
Revision 12 6.3-2 January, 2003
c. The system is designed so that a single active or passive component failure, including power buses, electrical and mechanical parts, cabinets and wiring will not disable the ADS.
d. In the event of a break in a pipe that is not a part of the ECCS, no single active component failure in the ECCS shall prevent automatic initiation and successful operation of less than the following combination of ECCS equipment:
1. 3 LPCI loops, the LPCS and the ADS (i.e., HPCS failure); or
2. 2 LPCI loops, the HPCS and the ADS (i.e., failure of diesel generator supplying LPCS/LPCI); or
3. 1 LPCI loop, the LPCS, the HPCS, and ADS (i.e., diesel generator failure).
e. In the event of a break in a pipe that is a part of the ECCS, no single active component failure in the ECCS shall prevent automatic initiation and successful operation of less than the following combination of ECCS equipment:
1. 2 LPCI loops and the ADS; or
2. 1 LPCI loop, the LPCS and the ADS; or
3. 1 LPCI loop, the HPCS and the ADS; or
4. The LPCS, the HPCS and ADS.
These are the minimum ECCS combinations which result after assuming any failure (from Item 4, above) and assuming that the ECCS line break disables the affected system. Revision 12 6.3-3 January, 2003
f. Long term (10 minutes after the initiation signal) cooling requirements call for the removal of decay heat via the emergency service water system. In addition to the break which initiated the loss-of-coolant event, the system is able to sustain one failure, either active or passive and still have at least one low pressure ECCS pump operating with a heat exchanger and 100 percent emergency service water flow.
g. Offsite power is the preferred source of power for the ECCS network and every reasonable precaution must be made to assure its high availability. However, onsite emergency power shall be provided with sufficient diversity and capacity so that all the above requirements can be met even if offsite power is not available.
h. The onsite diesel fuel reserve shall be in accordance with IEEE Standard 308-1974 criteria.
i. Diesel-load configuration shall be as follows:
1. 1 LPCI loop (with heat exchanger) and the LPCS connected to a single diesel generator.
2. 2 additional LPCI loops (1 loop with heat exchanger) connected to a single diesel generator.
3. The HPCS connected to a single diesel generator.
j. Systems which interface with, but are not part of, the ECCS are designed and operated such that failure(s) in the interfacing systems shall not propagate to and/or affect the performance of the ECCS.
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k. Non-ECCS systems interfacing with the ECCS buses shall automatically be shed from and/or be inhibited from the ECCS buses when a LOCA signal exists and offsite ac power is not available.
l. No more than one storage battery shall be connectable to a dc power bus.
m. Each system of the ECCS including flow rate and sensing networks is capable of being tested during shutdown. All active components are capable of being tested during plant operation, including logic required to automatically initiate component action.
n. Provisions for testing the ECCS network components (electronic, mechanical, hydraulic, and pneumatic, as applicable) are installed in such a manner that they are an integral and nonseparable part of the design.
o. The ECCS is designed to withstand the passive failure of valve stem packings and pump seals following a LOCA.
6.3.1.1.3 ECCS Requirements for Protection from Physical Damage The emergency core cooling system piping and components are protected against damage from movement, from thermal stresses, from the effects of the LOCA, and the safe shutdown earthquake (SSE). The ECCS is protected against the effects of pipe whip which might result from piping failures up to and including the design basis event LOCA. This protection is provided by separation, pipe whip restraints or energy absorbing materials if required. One of these three methods is applied to provide protection against damage to piping and components of the ECCS which otherwise could result in a reduction of ECCS effectiveness to an unacceptable level. Revision 12 6.3-5 January, 2003 The ECCS piping and components located outside the reactor building are protected from internally and externally generated missiles by the reinforced concrete structure of the auxiliary building ECCS pump rooms. In addition, the watertight construction of the ECCS pump rooms when required protects against mass flooding of redundant ECCS pumps. Mechanical separation outside the drywell is achieved as follows:
a. The ECCS is separated into three functional groups:
1. HPCS
2. LPCS + 1 LPCI + 100% emergency service water and heat exchanger
3. 2 LPCI pumps + 100% emergency service water and heat exchanger
b. The equipment in each group is separated from that in the other two groups. In addition, the HPCS and RCIC (which is not part of the ECCS) are separated.
c. Separation barriers are constructed between the functional groups as required to assure that environmental disturbances such as fire, pipe rupture, falling objects, etc., affecting one functional group will not affect the remaining groups. In addition, separation barriers are provided as required to assure that such disturbances do not affect both the RCIC and the HPCS.
6.3.1.1.4 ECCS Environmental Design Basis Each emergency core cooling system, and the RCIC system, has a safety-related injection/isolation testable check valve located in piping within the drywell. In addition, the RCIC system has an Revision 12 6.3-6 January, 2003 isolation valve in the drywell portion of its steam supply piping. All valves are located above the highest water level expected in the drywell during any accident. The valves are qualified for the following environmental conditions:
a. Normal and upset plant operating ambient temperatures, relative humidities and pressures for each area of the drywell.
b. Envelope-of-accident conditions for temperature, relative humidity and pressure within the drywell for various time periods following the accident.
c. Normal and envelope-of-accident radiation environment (gamma and neutron).
The portions of ECCS and RCIC piping and equipment located between the drywell and the secondary containment are qualified for the following environmental conditions:
a. Normal and upset plant operating ambient temperatures, relative humidities and pressures.
b. Envelope-of-accident conditions for temperature, relative humidity and pressure for various time periods following the accident.
c. Normal and envelope-of-accident radiation environment (gamma and neutron).
6.3.1.2 Summary Descriptions of ECCS The ECCS injection network comprises a high pressure core spray (HPCS) system, a low pressure core spray (LPCS) system and the low pressure coolant injection (LPCI) mode of the residual heat removal (RHR) System. Revision 20 6.3-7 October, 2017 These systems are briefly described here as an introduction to the more detailed system design descriptions provided in <Section 6.3.2>. The automatic depressurization system (ADS) which assists the injection network under certain conditions is also briefly described. Boiling water reactors which employ the same ECCS design are listed in
. 6.3.1.2.1 High Pressure Core Spray The HPCS pumps water through a peripheral spray ring sparger mounted above the reactor core. Coolant is supplied over the entire range of system operation pressures. The primary purpose of HPCS is to maintain reactor vessel inventory after small breaks which do not depressurize the reactor vessel. HPCS also provides spray cooling heat transfer during breaks in which core uncovery is calculated. 6.3.1.2.2 Low Pressure Core Spray The LPCS is an independent loop similar to the HPCS, the primary difference being the LPCS delivers water over the core at relatively low reactor pressures. The primary purpose of the LPCS is to provide inventory makeup and spray cooling during large breaks in which the core is calculated to uncover. Following ADS initiation, LPCS provides inventory makeup following a small break. 6.3.1.2.3 Low Pressure Coolant InjectionLPCI is an operating mode of the residual heat removal system. Three pumps deliver water from the suppression pool to the bypass region inside the shroud through three separate reactor vessel penetrations to provide inventory makeup following large pipe breaks. Following ADS initiation, LPCI provides inventory makeup following a small break. Revision 12 6.3-8 January, 2003 6.3.1.2.4 Automatic Depressurization System The ADS uses a number of the reactor safety/relief valves to reduce reactor pressure during small breaks in the event of a postulated HPCS failure. When the vessel pressure is reduced to within the capacity of the low pressure systems (LPCS and LPCI), these systems provide inventory makeup so that acceptable postaccident temperatures are maintained. 6.3.2 SYSTEM DESIGN A more detailed description of the individual systems including individual design characteristics of the systems are covered in detail in <Section 6.3.2.1>, <Section 6.3.2.2>, <Section 6.3.2.3>, and <Section 6.3.2.4>.
provides a list of significant ECCS design parameters along with their design bases. The following discussion provides details of the combined systems; in particular, those design features and characteristics which are common to all systems are discussed. 6.3.2.1 Schematic Piping and Instrumentation Diagrams The piping and instrumentation diagrams (P&IDs) for the ECCS are identified in <Section 6.3.2.2>. The process diagrams which identify the various operating modes of each system are also identified in <Section 6.3.2.2>. 6.3.2.2 Equipment and Component Descriptions The starting signal for the ECCS comes from at least two independent and redundant sensors of drywell pressure and low reactor water level. The ECCS is actuated automatically and requires no operator action during the first 10 minutes following the accident. A time sequence for starting of the systems is provided in
. Revision 12 6.3-9 January, 2003 Electric power for operation of the ECCS is from the regular ac power sources. Upon loss of the regular power, operation is from onsite standby ac power sources. Standby sources have sufficient diversity and capacity so that all ECCS requirements are satisfied. The HPCS is powered from one ac supply bus. The LPCS and one LPCI loop are powered from a second ac supply bus and the two remaining LPCI loops are powered from a third and separate ac supply bus. The HPCS has its own diesel generator as its alternate power supply. The LPCS and one LPCI loop switch to one site backup power supply and the other two LPCI loops switch to a second site backup power supply. <Section 8.3> contains a more detailed description of the power supplies for the ECCS.
a. <Regulatory Guide 1.1>, Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal System Pumps.
General Compliance or Alternate Approach Assessment This guide prohibits design reliance on pressure and/or temperature transients expected during a LOCA for assuring adequate NPSH. The guidelines of this Regulatory Guide are applicable to the HPCS, LPCS, and LPCI pumps. The BWR design conservatively assumes 0 psig containment pressure and maximum expected temperatures of the pumped fluids. Thus, no reliance is placed on pressure and/or temperature transients to assure adequate NPSH. Requirements for NPSH are available at the centerline of the pump suction nozzles for each pump and are given in <Figure 6.3-1> (HPCS), <Figure 6.3-2> (LPCS), <Figure 6.3-3> (LPCI). Pump characteristic curves are given in <Figure 6.3-4> (HPCS), <Figure 6.3-5> (LPCS) and <Figure 6.3-6> (LPCI). Revision 12 6.3-10 January, 2003
b. <Regulatory Guide 1.82>, Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident General Compliance or Alternate Approach Assessment The design of the large toroidal passive ECCS suction strainer was evaluated against the regulatory positions contained in <Regulatory Guide 1.82>, Revision 2.
The suction strainer is designed to preclude the potential for loss of NPSH caused by debris blockage during the period that the ECCS is required to maintain long-term cooling. The large toroidal passive strainer results in a very low approach velocity for water entering the strainer. Debris collected on the strainer surface is not expected to compact significantly (due to the very low approach velocity), resulting in minimal head loss. A 1/4-scale model of the strainer design was tested to confirm the performance of the strainer and the behavior of the postulated debris bed as a function of time after the postulated LOCA. Because the debris bed will not be significantly compacted, flow will continue to pass through the debris (and the strainer) and thus the overall differential pressure will remain low. Maintaining a low differential pressure will ensure adequate NPSH for the ECCS pumps. The size of the openings in the suppression pool suction strainer material has been chosen based on the minimum restrictions found in systems served by the suppression pool. The ECCS pump suctions are designed to prevent degradation of pump performance through air ingestion and other adverse hydraulic effects. All of the suction piping remains below the surface of the suppression pool, and due to the very low approach velocity design of the strainer and the depth of the strainer in the pool, Revision 12 6.3-11 January, 2003 vortexing will not be present. The strainer is located at the bottom of the suppression pool, below the elevation of the SRV quencher arms. Because of the physical size of the strainer, some encroachment into the recommended exclusion zone around the quenchers occurs. However, the strainer design is such that any air that may enter the strainer will be released through the strainer mesh before traveling to the pump suction plenums; that is, air entrainment in the strainer will be minimized. The strainer does not involve any modification in the arrangement of drains from upper floors in the containment. In addition, there are no floor or equipment drains from the containment or reactor building that drain directly into the suppression pool with the exception of one normally closed 3 diameter refueling bellows drain line, two normally closed small boreControl Rod Drive system scram discharge volume drain lines, and one normally closed 6 diameter Condensate and Refueling Water system drain line. Because of the water quality and cleanliness level of the systems these lines are considered to contribute very little or no debris to the suppression pool. The Suppression Pool Makeup dump lines discharge upper containment pool water into the suppression pool following a LOCA. The upper containment pools are maintained in a clean condition by operation of the Fuel Pool Cleanup system and through the foreign material exclusion program. Therefore, debris from these lines will be limited to any corrosion products present in the dump lines carried along by the dump flow. In addition, the strainer is located at the bottom of the suppression pool such that it is highly unlikely that any debris from drains from the upper regions of the containment could impinge directly on the suction strainer. The suction strainer is designed such that its support structure will protect it from the effects of large debris. The strainer is Revision 12 6.3-12 January, 2003 designed so that it is capable of withstanding LOCA-induced hydrodynamic loads. PNPP utilizes GESSAR II methods combined with acoustic methodology which demonstrates that the strainer can withstand the LOCA-induced hydrodynamic loads. Missile protection was evaluated and determined to be of no concern based on the location of the strainer and the postulated missile sources for Perry. The maximum force that the perforated plate material could withstand without breach has been defined, such that appropriate controls are in place on handling and use of potentially damaging large objects taken in containment. The suction strainer was evaluated and shown to be able to withstand loads associated with design basis seismic events without loss of structural integrity. In addition, the design incorporates provisions so that bolts do not lose torque during any vibratory motion, and incorporates restraints to preclude radial and axial movement of the strainer. Low carbon 304 stainless steel is used as the primary material for ECCS suction strainer to prevent corrosive degradation during periods of inactivity and normal operation. Perry has established a containment cleanliness program for the control of foreign materials, and other programs to minimize the potential for strainer fouling from operations generated debris. Perry takes no credit for LOCA generated debris hold up in the drywell, and the design does not include debris interceptors of any kind. The strainer design requires no operator actions in response to debris accumulations or to otherwise assure availability of adequate NPSH for the ECCS pumps. Perry has control room Revision 12 6.3-13 January, 2003 indication for the RHR A, RHR B, and HPCS pumps suction pressure, and control room annunciation for low suction pressure for RHR A, RHR B and HPCS. ECCS pump suction pressure is addressed in the Emergency Operating Procedures (EOPs). Accordingly, no additional safety-related instrumentation is required. The design of the ECCS suction strainer is passive. Perry conducts comprehensive inspections during refueling outages to evaluate the cleanliness of the suppression pool. The strainer is periodically monitored by visual inspection for evidence of structural degradation or debris fouling. The frequency of suppression pool inspection and cleaning activities is determined based on plant specific debris collection data. The large toroidal passive strainer does not require operator actions to prevent the accumulation of debris on the strainer or to mitigate the consequences of debris accumulation. The design of the strainer provides sufficient area to accommodate the maximum quantity of debris that is expected to be produced following a design basis LOCA combined with postulated in situ debris quantities. The Emergency Operating Procedures (EOPs) contain guidance to the operator on the use of alternate water sources to provide a diverse means of providing long-term cooling to the core. See USAR <Section 6.2.2.2> for a discussion of the ECCS suction strainer compliance with <Regulatory Guide 1.82> as it pertains to debris generation and transport. NPSH available to the ECCS pumps has been determined in accordance with <Regulatory Guide 1.1>. Pressure drop across the suction strainer is based on results from testing and conservative analysis. The vapor pressure for suppression pool water used in Revision 15 6.3-14 October, 2007 NPSH calculations for events where significant debris generation is expected is based on a suppression pool bulk water temperature of 185F, which is the maximum design temperature of the containment. Analyses show maximum suppression pool temperatures to be less than the containment design temperature of 185F. Containment pressure is assumed to be atmospheric in accordance with <Regulatory Guide 1.1> requirements. Tests have quantified head loss caused by debris blockage on the strainer. Head loss measured during the testing accounts for the possible filtration of particulates by the debris bed. Tests were conducted to determine the performance characteristics of the passive strainer for the quantities and types of debris predicted following postulated accidents. 6.3.2.2.1 High Pressure Core Spray (HPCS) System The high pressure core spray (HPCS) system consists of a single motor-driven centrifugal pump located outside the primary containment, a spray sparger in the reactor vessel located above the core (separate from the LPCS sparger) and associated system piping, valves, controls, and instrumentation. The system is designed to operate from normal offsite auxiliary power or from a standby diesel generator supply if offsite power is not available. The piping and instrumentation diagram, <Figure 6.3-7> for the HPCS, shows the system components and their arrangement. The HPCS system process diagram, <Figure 6.3-1>, shows the design operating modes of the system. A simplified system flow diagram showing system injection into the reactor vessel is in <Figure 6.3-1>. The HPCS pump curves are included in <Figure 6.3-75>. The principal active HPCS equipment is located outside the primary containment. Suction piping is provided from the condensate storage tank and the suppression pool. In the event that the condensate storage Revision 12 6.3-15 January, 2003 water supply becomes exhausted or is not available, automatic switchover to the suppression pool water source will ensure a closed cooling water supply for continuous operation of the HPCS system. HPCS pump suction is also automatically transferred to the suppression pool if the suppression pool water level exceeds a prescribed value. The condensate storage tank reserves water just for use by the HPCS and RCIC. When the Control Room is notified of the issuance of a tornado warning for the vicinity of the plant, or if a tornado is sighted in the immediate vicinity of the plant, administrative controls require the HPCS suction to be aligned to the tornado missile protected suppression pool. After the HPCS injection piping enters the vessel, it divides and enters the shroud at two points near the top of the shroud. A semicircular sparger is attached to each outlet. Nozzles are spaced around the spargers to spray the water radially over the core and into the fuel assemblies. The HPCS discharge line to the reactor is provided with two isolation valves. One of these valves is a hydraulically testable check valve located inside the drywell as close as practical to the reactor vessel. HPCS injection flow causes this valve to open during LOCA conditions (i.e., no power is required for valve actuation during LOCA). If the HPCS line should break outside the containment, the check valve in the line inside the drywell will prevent loss of reactor water outside the containment. The other isolation valve (which is also referred to as the HPCS injection valve) is a motor-operated gate valve located outside the primary containment as close as practical to HPCS discharge line penetration into the containment. This valve is capable of opening with the maximum differential pressure across the valve expected for any system operating mode including HPCS pump shutoff head. The valve will reach the position required to deliver rated flow within 29 seconds following the initiation of a LOCA signal per the design basis analysis. This valve is normally Revision 17 6.3-16 October, 2011 closed to back up the inside testable check valve for containment integrity purposes. A test line is provided between the two valves. The test connection line is normally closed with two valves to assure containment integrity. Remote controls for operating the motor-operated components and diesel generator are provided in the main control room. The controls and instrumentation of the HPCS system are described, illustrated and evaluated in detail in <Chapter 7>. The location and type of the manual valves in the HPCS system are detailed in
<Figure 6.3-7>. Design considerations are given to protect the systems safety functions from an undetected, incorrect positioning of any of these manual valves. Administrative controls likewise serve to minimize the possibility of such errors. These design/operations features are outlined in
<Section 6.3.2.8>. The system is designed to pump water into the reactor vessel over a wide range of pressures. For small breaks that do not result in rapid reactor depressurization, the system maintains reactor water level and depressurizes the vessel. For large breaks the HPCS system cools the core by a spray. If a LOCA should occur, a low water level signal or a high drywell pressure signal initiates the HPCS and its support equipment. The system can also be placed in operation manually. The HPCS system is capable of delivering rated flow into the reactor vessel within 29 seconds following receipt of an automatic initiation signal. When a high water level in the reactor vessel is signaled, the HPCS is automatically stopped by a signal to the injection valve to close. Revision 17 6.3-17 October, 2011 The HPCS system also serves as a backup to the RCIC system in the event the reactor becomes isolated from the main condenser during operation and feedwater flow is lost. If normal auxiliary power is not available, the HPCS pump motor is driven by its own onsite power source. The HPCS standby power source is discussed in <Section 8.3>. The HPCS pump head flow characteristic used in LOCA analyses is shown in <Figure 6.3-4>. When the system is started, initial flow rate is established by primary system pressure. As vessel pressure decreases, flow will increase. When vessel pressure reaches 200 psid (differential pressure between the reactor vessel and the suction source) the system reaches rated core spray flow. The HPCS motor size is based on peak horsepower requirements. The elevation of the HPCS pump (suction nozzle centerline at Elevation 571-7) is sufficiently below the water level of both the condensate storage tank and the suppression pool to provide a flooded pump suction. The minimum net positive suction head (NPSH) requirement specified by the manufacturer at the maximum allowed runout flow of 7,655 gpm is 4.5 feet at a location three feet above the pump mounting flange for pump suction from both the suppression pool and condensate storage tank. NPSH requirements are met by providing adequate suction head and suction line size. The available NPSH, calculated in accordance with <Regulatory Guide 1.1>, is based on the following design conditions:
a. Pump maximum runout flow from the suppression pool and the condensate storage tank.
b. Containment at atmospheric pressure. Condensate storage tank (CST) at atmospheric pressure.
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c. Maximum suppression pool temperature of 185F. Maximum CST temperature of 125F.
d. CST at automatic transfer water level of Elevation 626-8.
Suppression pool at minimum drawdown water level of Elevation 589-0.
e. HPCS pump suction piping arrangement as shown on <Figure 6.3-7>.
f. Suction strainer fully loaded (i.e., maximum postulated loading resulting from LOCA-generated and pre-LOCA debris materials at bounding conditions) with an approximate 6.25 ft pressure drop.
The available NPSH at the time immediately preceding automatic transfer from the condensate storage tank to the suppression pool is approximately 67 feet, based on the above design conditions. The available NPSH with suction taken from the suppression pool is approximately 19 feet, at 3 feet above the pump mounting flange, based on the above design conditions. If the SPCU system is in operation during HPCS initiation, there is a brief period of time that flow could be to both the HPCS pump and to the SPCU system (occurs due to the overlap in SPCU system isolation valve closure time and the HPCS initiation time). The NPSH requirements of the HPCS pump during this brief period of concurrent operation are satisfied when calculated in accordance with <Regulatory Guide 1.1>. The final design calculations, based on the <Regulatory Guide 1.1> position, indicate an available NPSH for the HPCS system sufficient to ensure pump performance capable of accomplishing the required safety functions in both modes. Revision 15 6.3-19 October, 2007 For preoperational testing the HPCS pump is provided with a test line back to the condensate storage tank. During preoperational testing the HPCS pump was tested for flow capacity and suction pressure, since the condensate storage tank is pumped down to the low level transfer point. From this test the flow capacity and NPSH were compared to the vendor data, and visual observations were made for vortexing. A motor-operated valve is provided in the suction line from the suppression pool. The valve is located as close to the suppression pool penetration as practical. This valve is used to isolate the suppression pool water source when the HPCS system suction is from the condensate storage system and to isolate the system from the suppression pool in the event a leak develops in the HPCS system. The HPCS pump characteristics, head, flow, horsepower, and required NPSH are shown in <Figure 6.3-75>. The design pressure and temperature of the system components are established based on the ASME Section III Boiler and Pressure Vessel Code. The design pressures and temperatures, at various points in the system can be obtained from the miscellaneous information blocks on the HPCS process diagram, <Figure 6.3-1>. A check valve, flow element and restricting orifice are provided in the HPCS discharge line from the pump to the injection valve. The check valve is located below the minimum suppression pool water level and is provided so the piping downstream of the valve can be maintained full of water by the discharge line fill system <Section 6.3.2.2.5>. The flow element is provided to measure system flow rate during LOCA and test conditions and for automatic control of the minimum low flow bypass gate valve. The measured flow is indicated in the main control room. Revision 12 6.3-20 January, 2003 The restricting orifice is sized during preoperational testing of the system to limit system flow to acceptable values as described on the HPCS system process diagram, <Figure 6.3-1>. A low flow bypass line with a motor-operated gate valve connects to the HPCS discharge line upstream of the check valve on the pump discharge line. The line bypasses water to the suppression pool via the 12-inch full-flow test return line to prevent pump damage due to overheating when other discharge line valves are closed. The valve automatically closes when flow in the main discharge line is sufficient to provide the required pump cooling. Water hammer effects due to opening of this line into the 12-inch full-flow test return line are prevented by a vacuum breaker inside containment, which ensures the test return line is filled with air. The HPCS system incorporates relief valves to protect the components and piping from inadvertent overpressure conditions. One relief valve, set to relieve at 1,560 psig, is located on the discharge side of the pump downstream of the check valve to relieve thermally expanded fluid. A second relief valve is located on the suction side of the pump and is set at 100 psig with a capacity of >10 gpm - 10% accumulation. To relieve thermally expanded fluid between the two isolation valves of the test line to the condensate storage tank, a bypass line and check valve are installed around the inboard isolation valve (F010). Relief valve F035 of the HPCS system discharges to the 12-inch full-flow test return line, which terminates below the surface of the suppression pool. For this valve, the dynamic loads such as thrust and momentum caused by relief valve opening are calculated for the discharge piping and include such effects as backpressure caused by submergence of the discharge piping in the suppression pool. The dynamic loads have been included in the piping stress analysis. Revision 12 6.3-21 January, 2003 The discharge line is supported as Seismic Category I piping, which includes waterhammer effects in the dynamic analysis of the piping. The discharge line is supported as deemed necessary by the piping analysis to preclude any adverse effects from waterhammer. The HPCS components and piping are positioned to avoid damage from the physical effects of design basis accidents, such as pipe whip, missiles, high temperature, pressure, and humidity. The HPCS equipment and support structures are designed in accordance with Seismic Category I criteria <Section 3.2>. The system is assumed to be filled with water for seismic analysis. Provisions are included in the HPCS system which permits the HPCS system to be tested. These provisions are:
a. All active HPCS components are testable during normal plant operation.
b. A full flow test line is provided to route water from and to the condensate storage tank without entering the reactor pressure vessel. The suction line from the condensate tank also provides reactor grade water to fully test the HPCS including injection into the RPV during shutdown.
c. A full flow test line is provided to route water from and to the suppression pool without entering the reactor pressure vessel.
d. Instrumentation is provided to indicate system performance during normal test operations.
e. All motor-operated valves are capable of either local or remote-manual operation for test purposes.
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f. System relief valves are removable for bench-testing during plant shutdown.
6.3.2.2.2 Automatic Depressurization System (ADS) If the RCIC and HPCS cannot maintain the reactor water level, the automatic depressurization system, which is independent of any other ECCS, reduces the reactor pressure so that flow from LPCI and LPCS systems enters the reactor vessel in time to cool the core and limit fuel cladding temperature. The automatic depressurization system employs the nuclear system pressure relief valves to relieve high pressure steam to the suppression pool. The design, number, location, description, operational characteristics, and evaluation of the pressure relief valves are discussed in detail in <Section 5.2.2>. The operation of the ADS is discussed in <Section 7.3.1>. 6.3.2.2.3 Low Pressure Core Spray (LPCS) System The low pressure core spray system consists of: a centrifugal pump that can be powered by normal auxiliary power or the standby ac power system; a spray sparger in the reactor vessel above the core (separate from the HPCS sparger); piping and valves to convey water from the suppression pool to the sparger; and associated controls and instrumentation. <Figure 6.3-8>, the LPCS system P&ID, presents the system components and their arrangement. The LPCS system process diagram, <Figure 6.3-2>, shows the design operating modes of the system. <Figure 6.3-2> includes a simplified system flow diagram showing injection into the reactor vessel by the LPCS system. The LPCS pump curves are included in <Figure 6.3-76>. When low water level in the reactor vessel or high pressure in the drywell is sensed, the low pressure core spray system automatically Revision 12 6.3-23 January, 2003 starts. When reactor pressure is below LPCS system design pressure, the injection valve opens and the system sprays water into the top of the fuel assemblies to cool the core. The LPCS injection piping enters the vessel, divides and enters the core shroud at two points near the top of the shroud. A semicircular sparger is attached to each outlet. Nozzles are spaced around the sparger to spray the water radially over the core and into the fuel assemblies. The LPCS is designed to provide cooling to the reactor core only when the reactor vessel pressure is low, as is the case for large LOCA break sizes. However, when the LPCS operates in conjunction with the ADS the effective core cooling capability of the LPCS is extended to all break sizes because the ADS will rapidly reduce the reactor vessel pressure to within the LPCS operating range. The system head flow characteristic assumed for LOCA analyses is shown in <Figure 6.3-5>. The low pressure core spray pump and all motor-operated valves can be operated individually by manual switches located in the control room. Operating indication is provided in the control room by a flowmeter and valve indicator lights. The location and type of the manual valves in the LPCS system are detailed in
<Figure 6.3-8>. Design considerations are given to protect the systems safety functions from an undetected, incorrect positioning of any of these manual valves. Administrative controls likewise serve to minimize the possibility of such errors. These design/operations features are outlined in
<Section 6.3.2.8>. To assure continuity of core cooling, signals to isolate the containment do not operate any low pressure core spray system valves. The LPCS discharge line to the reactor is provided with two isolation valves. One of these valves is a hydraulically testable check valve Revision 12 6.3-24 January, 2003 located inside the drywell as close as practical to the reactor vessel. LPCS injection flow causes this valve to open during LOCA conditions (i.e., no power is required for valve actuation during LOCA). If the LPCS line should break outside the containment the check valve in the line inside the drywell will prevent loss of reactor water outside the containment. The other isolation valve (which is also referred to as the LPCS injection valve) is a motor-operated gate valve located outside the primary containment as close as practical to LPCS discharge line penetration into the containment. This valve is capable of opening with the maximum differential across the valve expected for any system operating mode. The valve is capable of opening against a differential pressure equal to normal reactor pressure minus the minimum LPCS system shutoff pressure. The valve will reach a position required to deliver rated flow within 32 seconds following receipt of the pressure permissive following a maximum recirculation line break accident. This valve is normally closed to back up the inside testable check valve for containment integrity purposes. A test line is provided between the two valves. The test connection line is normally closed with two valves to assure containment integrity. The LPCS system components and piping are arranged to avoid unacceptable damage from the physical effect of design-basis accidents, such as pipe whip, missiles, high temperature, pressure, and humidity. All principal active LPCS equipment is located outside the primary containment. A check valve, flow element and restricting orifice are provided in the LPCS discharge line from the pump to the injection valve. The check valve is located below the minimum suppression pool water level and is provided so the piping downstream of the valve can be maintained full of Revision 17 6.3-25 October, 2011 water by the discharge line fill system <Section 6.3.2.2.5>. The flow element is provided to measure system flow rate during LOCA and test conditions and for automatic control of the minimum low flow bypass gate valve. The measured flow is indicated in the main control room. The restricting orifice is sized during preoperation test of the system to limit system flow to acceptable values as shown on <Figure 6.3-2>. The LPCS pump (pump performance test results) characteristics, head, flow, horsepower, and required NPSH are shown in <Figure 6.3-5> and <Figure 6.3-76>. A low flow bypass line with a motor-operated gate valve connects to the LPCS discharge line upstream of the check valve on the pump discharge line. The line bypasses water to the suppression pool to prevent pump damage due to overheating when other discharge line valves are closed or reactor pressure is greater than the LPCS system discharge pressure following system initiation. The valve automatically closes when flow in the main discharge line is sufficient to provide required pump cooling. LPCS flow passes through a motor-operated pump suction valve that is normally open. This valve can be closed by a remote-manual switch (located in the control room) to isolate the LPCS system from the suppression pool should a leak develop in the system. This valve is located in the core spray pump suction line as close to the suppression pool as practical. A closed loop is established for the spray water escaping from the break. The design pressure and temperature of the system components are established based on the ASME Section III boiler and pressure vessel code. The design pressures and temperatures at various points in the system can be obtained from the miscellaneous information blocks on the LPCS process diagram <Figure 6.3-2>. Revision 12 6.3-26 January, 2003 The LPCS pump is located in the auxiliary building sufficiently below the water level in the suppression pool to assure a flooded pump suction and to meet pump NPSH requirements are met with the containment at atmospheric pressure and the suction strainer fully loaded (i.e., maximum postulated loading resulting from LOCA-generated and pre-LOCA debris materials). A pressure gauge is provided to indicate the suction head. The available NPSH, calculated in accordance with <Regulatory Guide 1.1>, is based on the following design conditions:
a. Pump design maximum runout flow of 7,800 gpm
b. Atmospheric containment pressure
c. Maximum suppression pool water temperature of 185F
d. Suppression pool minimum design water level at Elevation 589-0
e. LPCS pump suction nozzle centerline at Elevation 571-7
f. Suction strainer fully loaded (3.2 feet).
The minimum NPSH requirement is, as specified by the manufacturer, 5 feet at a point 2 feet above the top of the pump mounting flange. This reference point is two feet, 1-1/4 inches above the pump suction nozzle. The calculated minimum available NPSH for the LPCS pump is 28.4 feet. The LPCS pump characteristics are shown on <Figure 6.3-76>. The LPCS system incorporates relief valves to prevent the components and piping from inadvertent overpressure conditions. One relief valve, located on the pump discharge, is set at approximately 600 psig with a capacity of 100 gpm at 10 percent accumulation. The second relief valve is located on the suction side of the pump and is set for 100 psig at a capacity of 10 gpm at 10 percent accumulation. Relief Valve F018 of the LPCS system has a discharge line terminating below the surface of the suppression pool. For this valve, the dynamic loads such as thrust and Revision 22 6.3-27 October, 2021 momentum caused by relief valve opening are calculated for the discharge piping and include such effects as backpressure caused by submergency of the discharge piping in the suppression pool. The dynamic loads have been included in the piping stress analysis. The discharge line is supported as Seismic Category I piping, which includes waterhammer effects in the dynamic analysis of the piping. The discharge line is supported as deemed necessary by the piping analysis to preclude any adverse effects from waterhammer. The LPCS system piping and support structures are designed in accordance with Seismic Category I criteria <Section 3.2>. The system is assumed to be filled with water for seismic analysis. Provisions are included in the LPCS system which permits the LPCS system to be tested. These provisions are:
a. All active LPCS components are testable during normal plant operation.
b. A full flow test line is provided to route water from and to the suppression pool without entering the reactor pressure vessel.
c. A suction test line supplying reactor grade water is provided to test pump discharge into the reactor pressure vessel during normal plant shutdown.
d. Instrumentation is provided to indicate system performance during normal and test operations.
e. All motor-operated valves and check valves are capable of operation for test purposes.
Revision 12 6.3-28 January, 2003
f. Relief valves are removable for bench testing during plant shutdown.
6.3.2.2.4 Low Pressure Coolant Injection (LPCI) System The low pressure coolant injection subsystem is an operating mode of the RHR system. The LPCI system is automatically actuated by low water level in the reactor or high pressure in the drywell and uses the three RHR motor-driven pumps to draw suction from the suppression pool and inject cooling water flow into the reactor core and accomplish cooling of the core by flooding. Each loop has its own suction and discharge piping and separate vessel nozzle which connects with the core shroud to deliver flooding water on top of the core. The system is a high volume core flooding system. The LPCI system, like the LPCS system, is designed to provide cooling to the reactor core only when the reactor vessel pressure is low, as is the case for large LOCA break sizes. However, when the LPCI operates in conjunction with the ADS then the effective core cooling capability of the LPCI is extended to all break sizes because the ADS will rapidly reduce the reactor vessel pressure to the LPCI operating range. The head flow characteristics assumed in the LOCA analyses for the LPCI pumps are shown in <Figure 6.3-6>. The LPCI pump curves are included in <Figure 6.3-77>. <Figure 6.3-3> shows a process diagram and process data for the RHR system, including LPCI. The RHR pumps receive power from ac power buses having standby power source backup supply. Two RHR pump motors and the associated automatic motor-operated valves receive ac power from one bus, while the LPCS pump and the other RHR pump motor and valves receive power from another bus <Section 8.3>. Revision 12 6.3-29 January, 2003 The pump, piping, controls, and instrumentation of the LPCI loops are separated and protected so that any single physical event, or missiles generated by rupture of any pipe in any system within the drywell, cannot make all loops inoperable. To assure continuity of core cooling, signals to isolate the primary containment do not operate any RHR system valves which interfere with the LPCI mode of operation. Each LPCI discharge line to the reactor is provided with two isolation valves. The valve inside the drywell is a testable check valve and the valve outside the drywell is a motor-operated gate valve. No power is required to operate the check valve inside of the drywell; rather, it opens as a result of LPCI injection flow. If a break were to occur outboard of the check valve it would close to isolate the reactor from the line break. The motor-operated valve outside of the drywell is called the LPCI injection valve and is located as close as practical to the drywell wall. It is capable of opening against the maximum differential expected for the LPCI modes (i.e., normal reactor pressure minus the upstream pressure with the RHR pump running at minimum flow). The valve will reach a position required to deliver rated flow within 32 seconds following a maximum recirculation line break accident and receipt of the pressure permissive. The process diagram <Figure 6.3-3> and P&ID <Figure 5.4-13> indicate a great many flow paths are available other than the LPCI injection line. However, the low water level or high drywell pressure signals which automatically initiate the LPCI mode are also used to isolate all other modes of operation and revert other system valves to the LPCI lineup. Revision 17 6.3-30 October, 2011 The heat exchanger bypass valves will receive a signal to automatically open 110 seconds after a LOCA in order to provide rated LPCI flow to the reactor pressure vessel. During standby LPCI lineup, these valves are positioned full open and hence are not affected by the 110 second delay to auto open. During operation in the suppression pool cooling or test return mode, the 110 second time delay will allow the suppression pool test return valve to close under nominal flow rate conditions prior to auto opening the heat exchanger bypass valves. The heat exchanger outlet valves also receive a signal to automatically open 110 seconds after a LOCA and are controlled in a manner similar to the heat exchanger bypass valves. The heat exchanger inlet valves receive no automatic signals to open, however, these valves are administratively maintained in a full open position to provide flow to the heat exchangers and ensure LPCI mode operability. Design considerations have been given to protect the LPCI mode safety functions from an undetected, incorrect positioning of the manual valves in the system. Administrative controls likewise serve to minimize the possibility of such errors. The location and type of these valves as well as the design/operations features are outlined in
and <Section 6.3.2.8>. A check valve in the pump discharge line is used together with a discharge line fill system <Section 6.3.2.2.5> to prevent water hammer resulting from pump start against a potential shutoff condition. A flow element in the pump discharge line is used to provide a measure of system flow and to originate automatic signals for control of the pump minimum flow valve. The minimum flow valve permits a small flow to the suppression pool in the event no discharge valve is open, or in the case of a LOCA, the vessel pressure is higher than pump shutoff head. Revision 12 6.3-31 January, 2003 Using the suppression pool as the source of water for the LPCI establishes a closed loop for recirculation of LPCI water escaping from the break. The design pressures and temperatures at various points in the system, during each of the several modes of operation of the RHR subsystems, can be obtained from the miscellaneous information blocks on the LPCI process diagram, <Figure 6.3-3>. LPCI pumps and equipment are described in detail in <Section 5.4.7>, which also describes the other functions served by the same pumps if not needed for the LPCI function. The heat exchangers are discussed in <Section 6.2.2>. The portions of the RHR required for accident protection including support structures are designed in accordance with Seismic Category I criteria <Section 3.2>. The LPCI pump characteristics are shown in <Figure 6.3-6>. The LPCI system incorporates a relief valve on each of the pump discharge lines which protects the components and piping from inadvertent overpressure conditions. These valves, E12-F025A, B and C, are set to relieve pressure at 485 psig, which is below the system design pressure of 500 psig. The following relief valves in the RHR system have discharge lines terminating below the surface of the suppression pool:
a. F055A & B
b. F025A, B & C
c. F005 For these valves, the dynamic loads such as thrust and momentum caused by relief valve opening are calculated for the discharge piping and Revision 15 6.3-32 October, 2007
include such effects as backpressure caused by submergence of the discharge piping in the suppression pool. The dynamic loads have been included in the piping stress analysis. The discharge lines are supported as Seismic Category I piping, which includes waterhammer effects in the dynamic analysis of the piping. The discharge lines are supported as deemed necessary by the piping analysis to preclude any adverse effects from waterhammer. Provisions are included in the LPCI system to permit testing of the system. These provisions are:
a. All active LPCI components are designed to be testable during normal plant operation.
b. A discharge test line is provided for the three pump loops to route suppression pool water back to the suppression pool without entering the reactor pressure vessel.
c. A suction test line, supplying reactor grade water, is provided to test loop C discharge into the reactor pressure vessel during normal plant shutdown.
d. Instrumentation is provided to indicate system performance during normal and test operations.
e. All motor-operated valves and check valves are capable of manual operation for test purposes.
f. Shutdown lines taking suction from the recirculation system are provided for loops A and B to test pump discharge into the reactor pressure vessel after normal plant shutdown and to provide for shutdown cooling.
Revision 12 6.3-33 January, 2003
g. All relief valves are removable for bench-testing during plant shutdown.
6.3.2.2.5 ECCS Discharge Line Fill System A requirement of the core cooling systems is that cooling water flow to the reactor vessel be initiated rapidly when the system is called on to perform its function. This quick-start system characteristic is provided by quick-opening valves, quick-start pumps and standby ac power source. The lag between the signal to start the pump and the initiation of flow into the RPV can be minimized by keeping the core cooling pump discharge lines full. Additionally, if these lines were empty when the systems were called for, the large momentum forces associated with accelerating fluid into a dry pipe could cause physical damage to the piping. Therefore, the ECCS discharge line fill system is designed to maintain the pump discharge lines in a filled condition. The systems are filled and vented to remove any potentially damaging air or non-condensables. Since the ECCS discharge lines are elevated above the suppression pool, check or stop-check valves are provided near the pumps to prevent back flow from emptying the lines into the suppression pool. Past experience has shown that these valves will leak slightly, producing a small back flow that will eventually empty the discharge piping. To ensure that this leakage from the discharge lines is replaced and the lines are always kept filled, a water leg pump is provided for each of the three ECCS divisions. The power supply to these pumps is classified as essential when the main ECCS pumps are deactivated. The fill system, typical for each of the three ECCS divisions, consists of a jockey pump that takes suction from the corresponding ECCS divisions pump suction line(s) from the suppression pool and discharges downstream of the check valves on the ECCS pump discharge line. The P&IDs for the fill systems are shown on <Figure 5.4-13>, <Figure 6.3-7>, and <Figure 6.3-8>. Revision 15 6.3-34 October, 2007 Each jockey pump will ensure that the discharge lines are full up to the isolation valves considering conservative estimates of expected leakage through the boundary valves. A typical performance curve for the jockey pumps, defined by parameters of 32.5 psi and 40 gpm, is given in <Figure 6.3-74>. For each ECCS division, the minimum keep-fill pressure and flow requirements have been determined, assuming conservative estimates of leakage from the systems. A significant difference exists between these minimum keep-fill flow and pressure requirements and the flows and pressures to which the pumps are permitted to degrade under the ASME Code required pump testing program. This difference is adequate to meet an unexpected increase in leakage due to equipment deterioration, etc. To prevent overheating of the jockey pumps if the discharge lines valves do not leak, a low-flow bypass line is provided to continuously circulate water back to the ECCS pump suction lines. Initial filling of the piping systems is accomplished using the combination of jockey pumps, condensate water supply lines (located a minimum distance from filled system boundary valves), maintenance drains, vents, and test connections that are available, as shown on the P&IDs. All potentially damaging air is eliminated from the ECCS pump discharge lines when the fill system is placed into service by opening vents at all piping high points until water begins to flow from the vents. A high point venting procedure is repeated, after initial fill of the system, any time the jockey pump is stopped and restarted, and following any indication of low discharge line pressure. Pressure instrumentation provided on the jockey pumps discharge line initiates an alarm in the control room when pressure in the discharge line is less than the hydrostatic head required to maintain the line full. Indication is also provided in the control room as to when the jockey pumps are operating. If maintenance on a particular ECCS loop requires draining, the other loops in the system are protected by the isolation of the loop being drained by that lines isolation valves. Revision 15 6.3-35 October, 2007 The fill system, in accordance with surveillance procedures, is tested to ensure that the discharge lines are full as required. Calibration and functional testing of the pressure switches and associated alarms are performed to ensure their continued ability to perform their desired function. A small amount of dissolved gas may come out of solution during the interval between surveillance tests and accumulate at the high point vent(s) even though the jockey pump system is functioning properly. This is considered to be a normal phenomenon that will not compromise the system integrity. 6.3.2.2.6 Gas Management Both the suction and discharge piping in plant systems addressed in responses to Nuclear Regulatory Commission (NRC) Generic Letter (GL) 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems, have the potential to develop pockets of entrained gases. Gas as used herein includes air, nitrogen, hydrogen, water vapor, or any other void that results in a non-water-solid condition. Maintaining pump suction and discharge piping sufficiently filled with water is necessary to ensure the systems will perform properly and will inject the flow assumed in the safety analyses into the Reactor Coolant System (RCS) or containment upon demand. This will also prevent damage from pump cavitation or water hammer, and pumping of unacceptable quantities of noncondensible gas into the reactor vessel following an injection signal or during operation of Residual Heat Removal (RHR) shutdown cooling. Consistent with the responses to <GL 2008-01> for the Perry Nuclear Power Plant (Reference 21), (Reference 22), (Reference 23), (Reference 24), and NRC closure of the Generic Letter (Reference 25), gas management calculations and procedures address the following elements:
a. Identification of the systems/subsystems for which gas accumulation is managed; Revision 19 6.3-36 October, 2015
b. Identification of locations susceptible to gas accumulation that should be monitored in suction and discharge piping, and the type of monitoring performed;
c. Identification of gas void performance-based monitoring frequencies and modifications to the frequencies;
d. Determination of appropriate corrective actions for identified gas accumulations;
e. Identification of void acceptance criteria; and
f. Identification of methodology used to determine the void acceptance criteria.
6.3.2.3 Applicable Codes and Classifications The applicable codes and classification of the ECCS are specified in <Section 3.2>. All piping systems and components (pumps, valves, etc.) for the ECCS comply with applicable codes, addenda, code cases, and errata in effect at the time the equipment is procured. The piping and components of each ECCS within the containment and out to and including the pressure retaining injection valve are Safety Class 1. The remaining piping and components are Safety Class 2, 3 or non-code as indicated in <Section 3.2>, and as indicated on the individual system P&ID. The equipment and piping of the ECCS are designed to the requirements of Seismic Category I. This seismic designation applies to all structures and equipments essential to the core cooling function. IEEE codes applicable to the controls and power supplies are specified in <Section 7.1>. 6.3.2.4 Material Specifications and Compatibility Materials specifications and compatibility for the ECCS are presented in <Section 6.1> and <Section 3.2>. Nonmetallic materials such as lubricants, seals, packings, paints, and primers, insulation, as well as Revision 19 6.3-36a October, 2015 metallic materials, etc., are selected as a result of an engineering review and evaluation for compatibility with other materials in the system and the surroundings with concern for chemical, radiolytic, mechanical, and nuclear effects. Materials used are reviewed and evaluated with regard to radiolytic and pyrolytic decomposition and attendant effects on safe operation of the ECCS. 6.3.2.5 System Reliability A single failure analysis shows that no single failure prevents the starting of the ECCS when required, or the delivery of coolant to the reactor vessel. No individual system of the ECCS is single failure proof with the exception of the ADS; hence, it is expected that single failures will disable individual systems of the ECCS. The most severe effects of single failures with respect to loss of equipment occur if the LOCA occurs in combination with an ECCS pipe break coincident with a loss of offsite power. The consequences of the most severe single failures are shown in
. 6.3.2.6 Protection Provisions Protection provisions are included in the design of the ECCS. Protection is afforded against missiles, pipe whip and flooding. Also accounted for in the design are thermal stresses, loadings from a LOCA and seismic effects. The ECCS piping and components located outside the drywell are protected from internally and externally generated missiles by the reinforced concrete structure of the ECCS pump rooms. The ECCS is capable of withstanding the passive failure of valve stem packings and pump seals following a LOCA. The water tight construction of these ECCS pump rooms would contain any system leakage within the Revision 12 6.3-37 January, 2003 affected ECCS room, thereby preventing common mode flooding of the ECCS rooms, as described in <Section 9.3.3>. The maximum leakage due to a failure of this nature would be 23 gpm or less from an HPCS, LPCS or RHR pump seal failure. Valve stem leakage would be significantly less than this leakage. Each ECCS pump room is provided with leak detection capabilities <Section 9.3.3> and <Section 6.2.4.2.2.2> which would identify the faulted ECCS with an alarm system in the control room. The operator would then remotely isolate the influent and effluent containment isolation valves for the affected system. Based on operator action 30 minutes after the alarm, a total of 690 gallons would be spilled in the affected ECCS room. This reduction in suppression pool water inventory is insignificant and would not reduce the suppression pool water level below the minimum drawdown level. The design of the ECCS suction valves, which are flexible wedge gate valves, is such that the valve seal (packing) is isolated from the system when the valve is closed. See <Section 3.6.2.3.5.2> for discussion of unisolable/isolable leaks during non-accident (normal operation) and accident conditions. The ECCS is protected against the effects of pipe whip, which might result from piping failures up to and including the design basis event LOCA. This protection is provided by separation, pipe whip restraints and energy absorbing materials. These three methods are applied to provide protection against damage to piping and components of the ECCS which otherwise could result in a reduction of ECCS effectiveness to an unacceptable level. See <Section 3.6> for criteria on pipe whip. The component supports which protect against damage from movement and from seismic events are discussed in <Section 5.4.14>. The methods used to provide assurance that thermal stresses do not cause damage to the ECCS are described in <Section 3.9>. Revision 12 6.3-38 January, 2003 6.3.2.7 Provisions for Performance Testing Periodic system and component testing provisions for the ECCS are described in <Section 6.3.2.2> as part of the individual system descriptions. 6.3.2.8 Manual Actions The ECCS is actuated automatically and requires no operator action during the first 10 minutes following the accident. During the long term cooling period (after 10 minutes), the operator will take action as specified in <Section 6.2.2> to place the containment cooling system into operation. The operator has multiple instrumentation available in the control room to assist him in assessing the post-LOCA conditions. This instrumentation provides reactor vessel pressures, water levels, containment pressure, temperature, and radiation levels as well as indicating the operation of the ECCS. ECC system flow indication is the primary parameter available to assess proper operation of the system. Other indications such as position of valves, status of circuit breakers and essential power bus voltage are also available to assist him in determining system operating status. The electrical and instrumentation complement to the ECCS is discussed in detail in <Section 7.3>. Other available instrumentation is listed in the P&IDs for the individual systems. Much of the monitoring instrumentation available to the operator is discussed in more detail in <Chapter 5> and <Section 7.3>. 6.3.3 PERFORMANCE EVALUATION This section provides the results of the ECCS Loss-of-Coolant Accident (LOCA) evaluation. Note, the initial core through Cycle 7 used the SAFE/REFLOOD/CHASTE methodology (Reference 1). Cycle 8 and Revision 12 6.3-39 January, 2003 subsequent operating cycles are based on the SAFER/GESTR-LOCA methodology (Reference 4). (Reference 5) documents the analysis based on the SAFER/GESTR-LOCA methodology in support of cycle 8 at a core power level of 3,579 MWt for a new licensing basis. The licensing results have been revised and included in (Reference 18). The limiting case is reanalyzed for cycle 8 at a core power level of 3,758 MWt and results are documented in (Reference 18). The SAFER/GESTR-LOCA methodology evaluates the short-term and long-term reactor vessel blowdown response to a pipe rupture, the subsequent fuel heatup, and core reflooding by the ECCS. The reactor vessel pressure and water levels, ECCS performance, and other primary thermal-hydraulic phenomena are predicted as a function of time. These predictions are then used to determine the fuel cladding temperature under various accident conditions. The SAFER/GESTR-LOCA application methodology consists of three main parts. First, potentially limiting LOCA cases are determined by applying realistic (nominal) analytical models across the entire break spectrum of postulated breaks. Second, limiting LOCA cases are analyzed with an Appendix K model (inputs and assumptions) which incorporates the required features of <10 CFR 50, Appendix K>. For the most limiting cases, a Licensing Basis Peak Cladding Temperature (PCT) is calculated based on the nominal PCT with an adder to account statistically for the differences between the nominal and <10 CFR 50, Appendix K> assumptions. Finally, a statistically derived Upper Bound PCT is calculated to demonstrate the conservatism of the Licensing Basis PCT. The Licensing Basis PCT conforms to all the requirements of <10 CFR 50.46> and <10 CFR 50, Appendix K>. The performance of the ECCS with the new (reload) fuel types is presented in <Appendix 15B>, Reload Safety Analysis. Revision 12 6.3-40 January, 2003 The ECCS performance is evaluated for the entire spectrum of break sizes for postulated LOCAs. The accidents, as listed in <Chapter 15>, for which ECCS operation is required are:
a. Feedwater line break
b. Steam system piping break outside of containment
c. Loss-of-coolant accidents
<Chapter 15> provides the radiological consequences of the above listed events. 6.3.3.1 ECCS Bases for Technical Specifications The maximum average planar linear heat generation rates (MAPLHGRs) calculated in this performance analysis provide the basis for technical specifications designed to ensure conformance with the acceptance criteria of <10 CFR 50.46>. Minimum ECCS functional requirements are specified in <Section 6.3.3.4> and <Section 6.3.3.5> and testing requirements are discussed in <Section 6.3.4>. Limits on minimum suppression pool water level are discussed in <Section 6.2>. 6.3.3.2 Acceptance Criteria for ECCS Performance The applicable acceptance criteria, extracted from <10 CFR 50.46>, Acceptance Criteria for Emergency Core Cooling Systems for Light-Water-Cooled Nuclear Power Reactors, are listed below. Criterion 1 - Peak Cladding Temperature: The calculated maximum fuel element cladding temperature shall not exceed 2200F. Revision 12 6.3-41 January, 2003 Criterion 2 - Maximum Cladding Oxidation: The calculated total local oxidation shall not exceed 0.17 times the total cladding thickness before oxidation. Criterion 3 - Maximum Hydrogen Generation: The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all the metal in the cladding cylinder surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react. Criterion 4 - Coolable Geometry: Calculated changes in core geometry shall be such that the core remains amenable to cooling. Criterion 5 - Long-Term Cooling: After any calculated successful initial operation of the ECCS, the calculated core temperature shall be maintained at an acceptably low value and decay heat shall be removed for the extended period of time required by the long-lived radioactivity remaining in the core. The conformance with Criteria 1 through 3 is presented in (Reference 5) and summarized in <Section 6.3.3.7.3>. As discussed in (Reference 1), Section III.A, and presented in (Reference 5), conformance to Criterion 4 is demonstrated by conformance to Criteria 1 and 2. Conformance to Criterion 5 is demonstrated generically for General Electric BWRs in (Reference 1),Section III.A. (Reference 5). This remains unchanged by application of SAFER/GESTR-LOCA methodology. 6.3.3.3 Single Failure Considerations The functional consequences of potential operator errors and single failures (including those which might cause any manually controlled electrically operated valve in the ECCS to move to a position which Revision 12 6.3-42 January, 2003 could adversely affect the ECCS), and the potential for submergence of valve motors in the ECCS are discussed in <Section 6.3.2>. There it was shown that all potential single failures are no more severe than one of the single failures identified in
. Therefore, it is only necessary to consider each of these single failures in the performance analyses. For large breaks, failure of one of the diesel standby generators is in general the most severe failure. For small breaks, the HPCS is the most severe failure. 6.3.3.4 System Performance During the Accident In general, the system response to an accident can be described as:
a. receiving an initiation signal,
b. a small lag time (to open all valves and have the pumps up to rated speed) and
c. the ECCS flow entering the vessel.
Key ECCS initiating signals and time delays for all the ECC systems are provided in
. The minimization of the delay from the receipt of signal until the ECCS pumps have reached rated speed is limited by the physical constraints on accelerating the diesel generators and pumps. The delay time due to valve motion in the case of high pressure system provides a suitably conservative allowance for valves available for this application. In the case of the low pressure system, the time delay for valve motion is such that the pumps are at rated speed prior to the time the vessel pressure reaches the pump shutoff pressure. The flow delivery rates analyzed in <Section 6.3.3> can be determined from the head-flow curves in <Figure 6.3-4>, <Figure 6.3-5>, and Revision 12 6.3-43 January, 2003 <Figure 6.3-6> of <Section 6.3.2>. The ECCS leakage flow is accounted for in the analysis. The ECCS piping inside the vessel (between the vessel wall and shroud) has various leakage paths through slip joints and vent holes. Some of the ECCS water injected into the vessel is lost through these leakage paths into the downcomer region before reaching the region inside the shroud. The standard system leakage rates assumed are 80 gpm per LPCI pump and 100 gpm for HPCS and for LPCS. For the low pressure ECCS, there are two logic paths in SAFER that determine the time of flow injection. The first path is the system startup time and is governed by the diesel start time, electrical load sequencing, pump start time, and injection valve stroke time. The second path is governed by valve pressure permissive and injection valve stroke time. The limiting (longest) delays for the system startup and pressure permissive paths are determined and used for the analysis. In specific, for low pressure ECCS, no injection flow is assumed until 32 seconds following receipt of the low pressure injection valve pressure permissive. For high pressure ECCS, a 29 second system delay time from the accident initiation signal is assumed, encompassing the diesel start time plus time for the injection valve to open. Simplified piping and instrumentation and functional control diagrams for the ECCS are provided in <Section 6.3.2>. The operational sequence of ECCS for the DBA is presented in
. Operator action is not required, except as a monitoring function, during the short term cooling period following the LOCA. During the long term cooling period, the operator will take action as specified in <Section 6.2.2> to place the containment cooling system into operation. 6.3.3.5 Use of Dual Function Components for ECCS With the exception of the LPCI system, the systems of the ECCS are designed to accomplish only one function: to cool the reactor core Revision 17 6.3-44 October, 2011 following a loss of reactor coolant. To this extent, components or portions of these systems (except for pressure relief) are not required for operation of other systems which have emergency core cooling functions, or vice versa. Because either the ADS initiating signal or the overpressure signal opens the safety/relief valve, no conflict exists. The LPCI subsystem, however, uses the RHR pumps and some of the RHR valves and piping. When the reactor water level is low, the LPCI subsystem has priority through the valve control logic over the other RHR subsystems for containment cooling or shutdown cooling. Immediately following a LOCA, the RHR system is directed to the LPCI mode. 6.3.3.6 Limits on ECCS System Parameters The limits on the ECC system parameters are discussed in <Section 6.3.3.1> and <Section 6.3.3.7.1>. Any number of components in any given system may be out-of-service, up to and including the entire system. The maximum allowable out-of-service time is a function of the level of redundance and the specified test intervals as generally discussed in <Appendix 15A.5>. 6.3.3.7 ECCS Analyses for LOCA 6.3.3.7.1 LOCA Analysis Procedures and Input Variables The methodology used for the SAFER/GESTR-LOCA analysis is documented in (Reference 4). A summary of the set of codes used in this analysis is given below. The significant input parameters are contained in
and on <Figure 6.3-10>. Revision 12 6.3-45 January, 2003 The Shroud Head Stud Assembly Mechanism (SHSAM) leakage flow, ECCS leakage flow and the flow path of vessel Bottom Head Drain (BHD) connection to the broken recirculation line are accounted for in the analysis. Short-Term Thermal-Hydraulic Model (LAMB) The LAMB model (Reference 1) analyzes the short-term blowdown phenomena for postulated large pipe breaks in which nucleate boiling is lost before the water level drops sufficiently to uncover the active fuel. The LAMB output (most importantly, core flow as a function of time) is used in the SCAT/TASC model for calculating blowdown heat transfer and fuel dryout time. Transient Critical Power Model (SCAT/TASC) The SCAT model (Reference 1) completes the transient short-term thermal-hydraulic calculation for large recirculation line breaks. The time and location of boiling transition are predicted during the period of recirculation pump coastdown. When the core inlet flow is low, SCAT also predicts the resulting bundle dryout time and location. The calculated fuel dryout time is an input to the long-term thermal-hydraulic transient model, SAFER. For GE11 and later fuel, an improved SCAT model (designated TASC) is used to predict the time and location of boiling transition and dryout time. This model explicitly models the axially varying flow areas and heat transfer surface resulting from the GE11 part length fuel rods, and incorporates the critical power correlation for GE11 and GE12 (Reference 6) and (Reference 7). Thermal-Mechanical Model (GESTR-LOCA) The GESTR-LOCA (Reference 8) model provides the parameters to initialize the fuel stored energy and fuel rod fission gas inventory at the onset Revision 12 6.3-46 January, 2003 of a postulated LOCA for input to SAFER. GESTR-LOCA also establishes the initial transient pellet-cladding gap conductance for input to both SAFER and SCAT/TASC. Long Term Thermal-Hydraulic Model (SAFER) The SAFER model (Reference 9), (Reference 10), (Reference 11), (Reference 12), and (Reference 13) calculates the long-term system response of the reactor over a complete spectrum of hypothetical break sizes and locations. SAFER is compatible with the GESTR-LOCA fuel rod model for gap conductance and fission gas release. SAFER calculates the core and vessel water levels, system pressure response, ECCS performance, and other primary thermal-hydraulic phenomena occurring in the reactor as a function of time. SAFER realistically models all regimes of heat transfer that occur inside the core, and provides the PCT and the heat transfer coefficients (which determine the severity of the temperature change) as a function of time. Part length fuel rods, found in GE11 and later fuel types, are modeled as full-length rods, which conservatively overestimates the hot bundle power. 6.3.3.7.2 Accident Description A detailed description of the LOCA methodology is provided in (Reference 4). The analysis is documented in (Reference 18). For convenience, a short description of the major events during the design basis accident (DBA) is included here. Immediately after the postulated double-ended recirculation line break, vessel pressure and core flow begin to decrease. The initial pressure response is governed by the closure of the main steam isolation valves and the relative values of energy added to the system by decay heat and energy removed from the system by the initial blowdown of fluid from the downcomer. The initial core flow decrease is rapid because the recirculation pump in the broken loop ceases to pump almost immediately Revision 12 6.3-47 January, 2003 because it has lost suction. The pump in the intact loop coasts down relatively slowly. This pump coastdown governs the core flow response for the next several seconds. When the jet pump suctions uncover, calculated core flow decreases to near zero. When the recirculation pump suction nozzle uncovers, the energy release rate from the break increases significantly and the pressure begins to decay more rapidly. As a result of the increased rate of vessel pressure loss, the initially subcooled water in the lower plenum saturates and flashes up through the core, increasing the core flow. This lower plenum flashing continues at a reduced rate for the next several seconds. The core water level is restored during the rapid depressurization following uncovery of the break, and then begins dropping again due to the mass loss out of the break. Once the pressure drops below the shutoff head of the low pressure systems they begin injecting water into the vessel and rapidly restore the water level in the core. In the analysis, no credit is taken for flow until the injection valve is fully open and the reactor pressure is below the system shutoff head. The uncovery duration is shorter because the injection of LPCI water into the bypass region makes it possible to reflood the core before the lower plenum subcools. The calculated fuel cladding temperature results show that the first peak heatup occurs during the early boiling transition (early dryout) period, which is due to the initial stored energy or gap conductance. The second peak heatup is caused by core uncovery which is slower, being governed by decay heat and heat transfer rate. Finally the heatup is terminated when the core is recovered by the accumulation of ECCS water. 6.3.3.7.3 Break Spectrum Calculations - Recirculation Line Breaks Several break sizes are analyzed to determine the limiting single failure <Section 6.3.3.3> using nominal assumptions documented in (Reference 5) and (Reference 18) and the inputs discussed in Revision 12 6.3-48 January, 2003 <Section 6.3.3.7.1>. The drain line flow path between the vessel bottom head and the broken recirculation line is considered in the analysis. The analysis reported in (Reference 18) established the shape of the PCT versus break area curve (break spectrum) to determine the limiting break. This ensures the limiting combination of break size, location, and single failure had been identified, and is similar to that determined in the generic evaluation (Reference 4). The trend of PCT with break size is consistent with the trend observed in the generic break spectrum. Once the Design Basis Accident (DBA) which includes the limiting single failure has been determined using nominal assumptions, the event is then analyzed using the <10 CFR 50, Appendix K> methodology. The <10 CFR 50, Appendix K> calculations validate the limiting conditions and provides inputs into the calculation of the licensing and upper bound PCTs. The Perry analysis demonstrates that the DBA is the recirculation suction line break with a coincident HPCS Diesel Generator (DG) failure. This event results in the same first peak PCT as for LPCIDG and LPCSDG failures using the nominal assumptions. However, the DBA suction break with HPCSDG failure results in a more severe second peak PCT than for the other two single failures for the plant using the nominal assumptions. The nominal calculations <Figure 6.3-9> show that for large breaks (i.e., 1.0 ft2) the calculated PCTs remain flat and decrease with decreasing break size from the DBA to the 1.0 ft2 range due to the first peak PCT limiting resulted from early boiling transition (dryout). In the small break range (i.e., < 1.0 ft2), where the depressurization of the reactor depends on the Automatic Depressurization System (ADS), the calculated PCT increases first with decreasing break size and then decreases again. For small breaks, which do not experience early dryout, the calculated PCT occurs during the core uncovery. A 0.1 ft2 suction line break is limiting as shown in the representative small break spectrum. Revision 12 6.3-49 January, 2003 The <10 CFR 50, Appendix K> calculations demonstrated that the DBA recirculation suction line break with HPCSDG failure remains the limiting case. A summary of the results of the break spectrum calculations is shown in tabular form in
and graphically in <Figure 6.3-9>. 6.3.3.7.4 Calculations for Non-Recirculation Line Breaks Non-recirculation line breaks are analyzed for the limiting fuel type, using nominal assumptions (Reference 4). The analysis considers the HPCS line break, steam line break inside and outside the containment, feedwater line break and LPCI line break. For all of these events the calculated PCTs do not exceed the steady state value during normal operation, and thus are bounded by the recirculation line breaks results. 6.3.3.7.5 Compliance Evaluations Conformance to the acceptance criteria of <10 CFR 50.46> and <10 CFR 50, Appendix K> is demonstrated by the Licensing Basis PCT. The Licensing Basis PCTs for the plant specific fuel types are calculated for the DBA suction line break with the limiting HPCSDG failure using the results presented in (Reference 18) and the methodology documented in (Reference 4), (Reference 5), and (Reference 18). An adder is added to the nominal PCT to generate the Licensing Basis PCT. The adder incorporates features required by <10 CFR 50, Appendix K> which are not already included in the nominal calculations. Plant variable uncertainties included backflow leakage, ECCS water temperature, ECCS initiation signal, stored energy, gap pressure, and ADS time delay are considered in the plant specific adder. The Licensing Basis PCT is required not to exceed 2200F. Revision 12 6.3-50 January, 2003 Finally, the conservatism of the Licensing Basis PCT is demonstrated by comparison to a statistically derived Upper Bound PCT. The statistical based Upper Bound PCT is a function of the limiting case nominal PCT, modeling bias and plant specific variable uncertainties. The evaluation method in (Reference 4) is used to determine the uncertainty term which involves stored energy, decay heat, PLHGR, break flow and the initial MCPR. The Upper Bound PCT is then conservatively determined by adjusting the plant specific difference between the nominal and the derived PCT. The Upper Bound PCT is required to be less than the Licensing Basis PCT.
provides the Licensing Basis PCT results for the limiting DBA recirculation line suction break. 6.3.3.7.6 Alternate Operating Mode Considerations The SAFER/GESTR-LOCA analysis was applied to three alternate operating modes: Maximum Extended Operating Domain (MEOD), feedwater temperature reduction, and single loop operation. Details of these operating modes are contained in USAR <Appendix 15D>, <Appendix 15E>, and <Appendix 15F>, respectively. SAFER/GESTR-LOCA results are fuel type specific and, as such, are contained in USAR <Appendix 15B>, Reload Analysis. 6.3.3.8 Conclusions The Perry SAFER/GESTR-LOCA analysis results provided in <Section 6.3.3.7.3> (Reference 18) demonstrate that a sufficient number of plant-specific PCT points have been evaluated to establish the shape of both the nominal and Appendix K PCT versus break size curves. The analysis also demonstrates that the limiting Licensing Basis PCT occurs for the recirculation suction line DBA. Revision 12 6.3-51 January, 2003 Compliance with the applicable acceptance criteria provided in <Section 6.3.3.2> is provided in
. With the verification that the Licensing Basis PCT is greater than the Upper Bound PCT, the level of safety and conservatism of this analysis meets the NRC approved acceptance criteria of <10 CFR 50.46> and <10 CFR 50, Appendix K>. 6.3.4 TESTS AND INSPECTIONS 6.3.4.1 ECCS Performance Tests All systems of the ECCS are tested for their operational ECCS function during the preoperational and/or startup test program. Each component is tested for power source, range, direction of rotation, set point, limit switch setting, torque switch setting, etc. Each pump is tested for flow capacity for comparison with vendor data (this test is also used to verify flow measuring capability). The flow tests involve the same suction and discharge source, i.e., suppression pool or condensate storage tank. All logic elements are tested individually and then as a system to verify complete system response to emergency signals including the ability of valves to revert to the ECCS alignment from other positions. Finally, the entire system is tested for response time and flow capacity taking suction from its normal source and delivering flow into the reactor vessel. This last series of tests is performed with power supplied from both offsite power and onsite emergency power. See <Chapter 14> for a detailed discussion of preoperational testing for these systems. Revision 12 6.3-52 January, 2003 6.3.4.2 Reliability Tests and Inspections The average reliability of a standby (non-operating) safety system is a function of the duration of the interval between periodic functional tests. The factors considered in determining the periodic test interval of the ECCS are: the desired system availability (average reliability), the number of redundant functional system success paths, the failure rates of the individual components in the system, and the schedule of periodic tests (simultaneous versus uniformly staggered versus randomly staggered). For the ECCS the above factors were used to determine safe test intervals utilizing the methods described in (Reference 2). All of the active components of the HPCS system, LPCS system and LPCI systems are designed so that they may be tested during normal plant operation. Full flow test capability is provided by a test line back to the suction source. The full flow test is used to verify the capacity of each ECCS pump loop while the plant remains undisturbed in the power generation mode. In addition, each individual valve may be tested during normal plant operation. Input jacks are provided so that each ECCS loop can be tested for response time during racking out of the injection valve breaker. All of the active components of the ADS system except the safety/relief valves and their associated solenoid valves are designed so they may be tested during normal plant operation. The safety/relief valves and associated solenoid valves are all tested on a Technical Specification specified frequency during plant startup following a refueling outage. Safety/relief valves and their associated solenoid valves which have been overhauled during a plant outage are tested during the startup following that outage. Revision 12 6.3-53 January, 2003 Testing of the initiating instrumentation and controls portion of the ECCS is discussed in <Section 7.3.1>. The emergency power system, which supplies electrical power to the ECCS in the event that offsite power is unavailable, is tested as described in <Section 8.3.1>. The frequency of testing is specified in technical specifications. Visual inspections of all the ECCS components located outside the drywell can be made at any time during power operation. Components inside the drywell can be visually inspected only during periods of access to the drywell. When the reactor vessel is open, the spargers and other internals can be inspected. 6.3.4.2.1 HPCS Testing The HPCS can be tested at full flow with condensate storage tank water at any time during plant operation except when the reactor vessel water level is low, when the condensate level in the condensate storage tank is below the reserve level or when the valves from the suppression pool to the pump are open. If an initiation signal occurs while the HPCS is being tested, the system returns automatically to the operating mode. The two motor-operated valves in the test line to the condensate storage system are interlocked closed when the suction valve from the suppression pool is open. The functional test of the HPCS pump is performed at a single pressure and flow calculated to satisfy all design bases flows and pressures. The test is performed by pumping water from either the condensate storage tank, through the full flow test return line, and back to the condensate storage tank or from the suppression pool to the suppression pool. The suction valve from the unused source and the discharge valve to the reactor remain closed. These valves are tested separately to ensure their operability. Revision 14 6.3-54 October, 2005 The HPCS test conditions are tabulated on the HPCS process flow diagram, Figure 6.3-1. The HPCS pre-operational testing was conducted in all modes of operation and included automatic transfer of pump suction from the condensate storage tank to the suppression pool for both modes of initiation (high suppression pool level and low condensate storage tank level). The pump head flow characteristics and NPSH were checked for consistency and design specifications for the various modes of operation. See Section 14.2.12.1.15 for details. Revision 14 6.3-54a October, 2005 6.3.4.2.2 ADS Testing The ADS valves are fully tested during the time when the reactor is at reduced pressure prior to or following a refueling outage. This testing includes simulated automatic actuation of the system throughout its emergency operating sequence. Each individual ADS valve is manually actuated. During plant operation the ADS system can be checked as discussed in <Section 7.3.1>. 6.3.4.2.3 LPCS Testing The LPCS pump and valves are tested periodically during reactor operation. With the injection valve closed and the return line open to the suppression pool, full flowing pump capability is demonstrated. The injection valve and the check valve are tested in a manner similar to that used for the LPCI valves. The system test conditions during reactor shutdown are shown on the LPCS system process diagram, <Figure 6.3-2>. 6.3.4.2.4 LPCI Testing Each LPCI loop can be tested during reactor operation. The test conditions are tabulated in <Figure 6.3-3>. During plant operation, this test does not inject cold water into the reactor because the injection valve is not opened. The injection line portion is tested during the shutdown cooling mode of operation. This prevents unnecessary thermal stresses. Revision 12 6.3-55 January, 2003 To test an LPCI pump at rated flow, the test line valve to the suppression pool is opened, the pump suction valve from the suppression pool is opened (this valve is normally open) and the pumps are started using the remote-manual switches in the control room. Correct operation is determined by observing the instruments in the control room. If an initiation signal occurs during the test, the LPCI system returns to the operating mode. The valves in the test bypass lines are closed automatically to assure that the LPCI pump discharge is correctly routed to the vessel. 6.3.4.2.5 ECCSCheck ValvesECCScheck valves in the discharge side of the RHR/LPCI, HPCS and LPCS systems perform an isolation function that they protect low pressure systems from full reactor pressure. These ECCScheck valves, as identified below, will be classified Category AC per the ASMEOM Code with leak testing for this class of valve being performed to code specifications. System Valve Identification USAR Figure RHR/LPCI F041A, B, C <Figure 5.4-13> HPCS F005 <Figure 6.3-7> LPCS F006 <Figure 6.3-8> The necessary test provisions (test connections, block valves, etc.) to leak test each valve have been incorporated in the design, as shown on <Figure 5.4-13>, <Figure 6.3-7>, and <Figure 6.3-8>. Leak testing will be performed at each refueling after the valves have been exercised. Revision 16 6.3-56 October, 2009 The required leak test schedule and leak detection criteria are provided in technical specifications. 6.3.5 INSTRUMENTATION REQUIREMENTS Design details including redundancy and logic of the ECCS instrumentation are discussed in <Section 7.3>. All instrumentation required for automatic and manual initiation of the HPCS, LPCS, LPCI, and ADS is discussed in <Chapter 7> and is designed to meet the requirements of IEEE Standard 279 and other applicable regulatory requirements. The HPCS, LPCS, LPCI, and ADS can be manually initiated from the control room. The HPCS, LPCS and LPCI are automatically initiated on low reactor water level or high drywell pressure (see
for specific initiation levels for each system). The ADS is automatically actuated by sensed variables for reactor vessel low water level plus indication that at least one LPCI or LPCS pump is operating. The HPCS, LPCS and LPCI automatically return from system flow test modes to the emergency core cooling mode of operation following receipt of an automatic initiation signal. The LPCS and LPCI system injection into the RPV begin when reactor pressure decreases to system discharge shutoff pressure. HPCS injection begins as soon as the HPCS pump is up to speed and the injection valve is open since the HPCS is capable of injecting water into the RPV over a pressure range from 1,200 psid (differential pressure between RPV and pump suction source) to 0 psid. Revision 13 6.3-57 December, 2003 6.

3.6 REFERENCES

FOR SECTION 6.3

1. General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with <10 CFR 50, Appendix K>, NEDO-20566, January 1976.
2. H. M. Hirsch, Methods for Calculating Safe Test Intervals and Allowable Repair Times for Engineered Safeguard Systems, January 1973 (NEDO-10739).
3. General Electric Company General Electric Standard Application for Reactor Fuel, including the United States Supplement, NEDE-24011-P-A and NEDE-24011-P-A-US (latest approved revision).
4. The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident, Volume III, SAFER/GESTR Application Methodology NEDE-23785-PA, General Electric Company, Revision 1, October 1984.
5. Perry Nuclear Power Plant SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis, NEDC-32872P, December 1998.
6. GE11 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR-II),

NEDE-31917P, April 1991.

7. GE12 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR-II),

NEDE-32417P, December 1994.

8. The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident, Volume I, GESTR-LOCA - A Model for the Prediction of Fuel Rod Thermal Performance, NEDE-23785-PA, General Electric Company, Revision 1, June 1984.

Revision 12 6.3-58 January, 2003

9. SAFER Model for Evaluation of Loss-of-Coolant Accidents for Jet Pump and Non-Jet Pump Plants, NEDE-30996P-A, October 1987.
10. MFN-040-88, H. C. Pfefferlen (GE) to J. A. Norberg (NRC), ECCS Evaluation Model Improvements, July 14, 1988.
11. MFN-23-90, R. C. Mitchell (GE) to USNRC, Reporting of Changes and Errors in ECCS Evaluation, June 13, 1990.
12. MFN-25-91, P. W. Marriott (GE) to USNRC, Reporting of Changes and Errors in ECCS Evaluation, March 12, 1991.
13. MFN-90-93, R. C. Mitchell (GE) to USNRC, Reporting of Changes and Errors in ECCS Evaluation, June 30, 1993.
14. Letter GE-PAIP-180, P. T. Tran (GE) to E. M. Root (CEI), GE Response to Perry SAFER/GESTR PERFORM Open Item 79, February 25, 1999 (provides the licensing basis PCT value for MEOD condition for Cycle 8).
15. Letter GE-PAIP-203 R/1, I. Nir (GE) to E. M. Root (CEI), Perry Power Uprate SAFER/GESTR Analysis Bounding Licensing Basis PCT, March 19, 1999 (provides percent oxidation and hydrogen generation values for MEOD for Cycle 8).
16. Letter GE-PAIP-231, I. Nir (GE) to E. M. Root (CEI), Resolution of concerns with ECCS LOCA Analysis Input Parameters, March 24, 1999 (provides confirmation that input parameters used for the SAFER/GESTR-LOCA analysis were the same or more conservative than those used in the existing SAFE/REFLOOD LOCA Analysis).

Revision 12 6.3-59 January, 2003

17. Letter GE-PAIP-239, I. Nir (GE) to E. M. Root (CEI), GE Response to Perry SAFER/GESTR Open Item 97, March 30, 1999 (provides an explanation for the change in limiting failure for the LOCA Analysis when analyzed using SAFER/GESTR methodology as compared to SAFE/REFLOOD).
18. GE-NE-A2200084-27-01, Perry Nuclear Power Plant Asset Improvement Project Task G1-27: SAFER/GESTR-LOCA Analysis (No ECCS Parameter Relaxations), Revision 1, November 1999.
19. Letter GE-PAIP-278, I. Nir (GE) to E. M. Root (CEI), Response to Perry SAFER/GESTR Open Items 96 and 98 (Resolution for SLO MAPLHGR Multiplier Values), April 29, 1999.
20. GE Nuclear Energy, Safety Review for Perry Nuclear Power Plant Safety/Relief Valve Setpoint Tolerance Relaxation/Out-of-Service Analysis, NEDC-32307P, dated May 1994.
21. Letter L-08-315, FirstEnergy Nuclear Operating Company (FENOC) to U.S. Nuclear Regulatory Commission (NRC), Nine Month Response to NRC Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (TAC No. MD7862), October 14, 2008.
22. Letter L-08-383, FENOC to NRC, Supplemental Information Regarding NRC Generic Letter 2008-01 (TAC No. MD7862), December 19, 2008.
23. Letter L-09-158, FENOC to NRC, Ninety Day Post-Outage Supplemental Response to Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (TAC No. MD7862), August 10, 2009.

Revision 19 6.3-60 October, 2015

24. Letter L-10-011, FENOC to NRC, Response to NRC Request for Additional Information Regarding Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (TAC No. MD7862), January 27, 2010.
25. Letter, NRC to FENOC, Perry Nuclear Power Plant, Unit 1 - Closeout of Generic Letter 2008-01 Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (TAC No. MD7862), June 27, 2011.

Revision 19 6.3-60a October, 2015

TABLE 6.3-1 PARAMETERS USED IN PERRY SAFER/GESTR-LOCA ANALYSIS A. PLANT PARAMETERS

<10 CFR 50, Plant Parameters Nominal Appendix K>

Core Thermal Power (MWt)(1) 3758 3833 Corresponding Power (% of 3758 MWt) 100 102 Vessel Steam Output (Mlb/hr) 16.30 16.63 Vessel Steam Output (% rated) 100 102 Core Flow (Mlb/hr) 104.0 104.0 Core Flow (% rated) 100 100 Vessel Steam Dome Pressure (psia) 1040 1060 Maximum Recirculation Suction Line 2.73 2.73 Break Area (ft2)

Bottom Head Drain Line Break Area (ft2) 0.0155 0.0155 B. ECCS PARAMETERS

1. Low Pressure Coolant Injection (LPCI) System Variable Units Analysis Value
a. Maximum vessel pressure at which psid (vessel 225 pumps can inject flow to drywell)
b. Minimum rated flow (into shroud)

Vessel pressure at which below psid (vessel 20 listed flow rates are quoted to drywell)

One (1) LPCI pump injecting gpm 6500 into shroud Two (2) LPCI pumps injecting gpm 13000 into shroud Three (3) LPCI pumps injecting gpm 19500 into shroud Revision 12 6.3-61 January, 2003

TABLE 6.3-1 (Continued)

B. ECCS PARAMETERS (Continued)

Variable Units Analysis Value

c. Run-out flow at 0 psid (vessel to drywell)

One (1) LPCI pump injecting gpm 7000 into shroud Two (2) LPCI pumps injecting gpm 14000 into shroud Three (3) LPCI pumps injecting gpm 21000 into shroud

d. Initiating signals Low-low water level, or inches above 373.4 vessel zero High drywell pressure psig 2.0
e. Vessel pressure at which injection valve may open psia 450
f. Time from initiating signal sec 27 (Item 1.d) to pump at rated speed and capable of rated flow with emergency (diesel) power including sequencing delays
g. Time from initiating signal sec 10 (Item 1.d) to power at injection valves
h. Injection valve stroke time-opening sec 32
2. Low Pressure Core Spray (LPCS) System Variable Units Analysis Value
a. Maximum vessel pressure at which psid (vessel 289 pumps can inject flow to drywell)

Revision 12 6.3-62 January, 2003

TABLE 6.3-1 (Continued)

2. Low Pressure Core Spray (LPCS) System (Continued)

Variable Units Analysis Value

b. Minimum rated flow at vessel-to gpm 6000

-drywell pressure (into shroud) psid 122

c. Run-out flow at 0 psid (vessel to gpm 6600 drywell)
d. Initiating signals inches above 373.4 vessel zero Low-low water level, or High drywell pressure psig 2.0
e. Run-out flow at 0 psid (vessel to gpm 6600 drywell)
f. Vessel pressure at which injection psig 450 valve may open
g. Injection valve stroke time-opening sec 32
h. Time from initiating signal sec 10 (Item 2.d) to power at injection valves
i. Time from initiating signal sec 27 (Item 2.d) to pump at rated speed with emergency (diesel) power including sequencing delays
3. High Pressure Core Spray (HPCS) System Variable Units Analysis Value
a. Vessel pressure at which flow psid 1200 may commence
b. Minimum rated flow and vessel gpm/psid 517/1200 pressure 1550/1147 (vessel to source of 6000/200 suction)

Revision 12 6.3-63 January, 2003

TABLE 6.3-1 (Continued)

3. High Pressure Core Spray (HPCS) System (Continued)

Variable Units Analysis Value

c. Run-out flow at 0 psid (vessel gpm 6000 to source of suction)
d. Initiating signals inches above 485.4 vessel zero Low-low water level, or High drywell pressure psig 2.0
e. Maximum allowable time delay seconds 29 from initiating signal until rated flow is available through the injection valve
4. Automatic Depressurization System (ADS)

Variable Units Analysis Value

a. Total number of valves with 8 ADS function available
b. Number of ADS valves assumed in 8 the analysis
c. Pressure at which below listed psig 1080 capacity is quoted
d. Minimum flow capacity at pressure lb/hr 6.724x106 given in 4.c with all available ADS valves open
e. Initiating signals inches above 373.4 vessel zero Low-low water level, and ADS Timer Delay from initiating sec 120 signal completed to the time valves are open Revision 17 6.3-64 October, 2011

TABLE 6.3-1 (Continued)

C. FUEL PARAMETERS Analysis Value Fuel Parameter GE11 PLHGR (kW/ft) - <10 CFR 50, Appendix K> 14.4x1.02

- Nominal 13.8 MAPLHGR (kW/ft) - <10 CFR 50, Appendix K> 13.4x1.02

- Nominal 12.9 Initial Operating MCPR - <10 CFR 50, Appendix K> 1.16

- Nominal 1.20 Axial Peaking Factor 1.4 Number of Fuel Rods per Bundle 74 NOTE:

(1)

The nominal core thermal power (3758 MWt) corresponds to the current licensed rated power value. A conservative core thermal power of 3833 MWt which corresponds to 102% of the rated power was used for the <10 CFR 50, Appendix K> evaluation.

Revision 12 6.3-65 January, 2003

TABLE 6.3-2 OPERATIONAL SEQUENCE OF EMERGENCY CORE COOLING SYSTEMS FOR DESIGN BASIS ACCIDENT(1)(2)

Time (sec) Events 0 Design basis loss-of-coolant accident assumed to start; normal auxiliary power assumed to be lost.

~0 Drywell high pressure and reactor low water level reached. All diesel generators signaled to start; scram; HPCS, LPCS, and LPCI signaled to start on high drywell pressure.

~4 Reactor low-low water level reached. HPCS receives second signal to start.

~6 Reactor low-low-low water level reached. Second signal to start LPCI and LPCS; auto-depressurization sequence begins; main steam isolation valve signaled to close.

<10 Division 1 and 2 diesel generators ready to load; begin energizing LPCI and LPCS pump motors.

~28 Pressure permissive for LPCI and LPCS injection valve reached.

~29 HPCS pump at rated speed and injection valve open sufficient to pass required flow.

~60 LPCI and LPCS pumps at rated speed, and LPCI and LPCS injection valves open sufficient to pass required flow.

~150 Core reflooded assuming worst single failure; heatup terminated.

>10 min Operator shifts to containment cooling.

NOTES:

(1)

For the purpose of all but the next to last entry on this table, all ECCS equipment is assumed to function as designed. Performance analysis calculations consider the effects of single equipment failures <Section 6.3.2.5> and <Section 6.3.3.3>. The recirculation suction line break DBA with limiting HPCS DG failure case using

<10 CFR 50, Appendix K> assumptions is used.

(2)

Credit is taken in LOCA analyses for ECCS starts on high drywell pressure signal.

Revision 17 6.3-66 October, 2011

TABLE 6.3-3 PERRY SINGLE FAILURE EVALUATION The table below shows the various combinations of Automatic Depressurization System (ADS), High Pressure Core Spray (HPCS) System, Low Pressure Coolant Injection (LPCI) System and Low Pressure Core Spray (LPCS) System which might be operable in an assumed design basis accident situation. In performing the ECCS performance analysis with SAFER/GESTR-LOCA, it is assumed that no postulated single active component will result in less than certain minimum combinations of systems remaining operable.

The following single, active failures will be considered in the ECCS performance evaluation for recirculation suction line break:

Assumed Failure(1) Systems Remaining(2)

LPCI Emergency Diesel Generator (D/G) All ADS, HPCS, LPCS, 1 LPCI LPCS Emergency DG All ADS, HPCS, 2 LPCI HPCS Emergency DG All ADS, LPCS, 3 LPCI One ADS Valve All ADS minus one, HPCS, LPCS, 3 LPCI NOTES:

(1)

Other postulated failures are not specifically considered because they all result in at least as much ECCS capacity as one of the above assumed failures.

(2)

Systems remaining, as identified in this table, are applicable to all non-ECCS line breaks. For a LOCA from an ECCS line break, the systems remaining are those listed, less the ECCS system in which the break is assumed.

Revision 12 6.3-67 January, 2003

TABLE 6.3-4

SUMMARY

OF RECRICULATION LINE BREAK RESULTS FOR PERRY SAFER/GESTR ANALYIS FOR CYCLE 8(1)

Break Size & Single GE11(3)

Recirc Break Failure(2) 1st/2nd peak Location PCT (F)

Nominal:

DBA, Suction HPCS DG 907/809 1.0 ft2, Suction HPCS DG 891/590 0.1 ft2 HPCS DG 650

<10 CFR 50, Appendix K>:

DBA, Suction HPCS DG 1130/1328 1.0 ft2 HPCS DG 1144/1021 0.1 ft2 HPCS DG 835 NOTES:

(1)

Table does not include values associated with MEOD, feedwater temperature reductions, or single loop operations.

(2)

Only the results for the most limiting single failure are presented in this Table.

(3)

The calculated FCT results for the limiting fuel (GE11) would be bounding for GE10 and GE12 fuels.

Revision 12 6.3-68 January, 2003

TABLE 6.3-5 SAFER/GESTR-LOCA RESULTS FOR PERRY(4)

1. Limiting Fuel Type (Cycle 8) GE11 Fuel
2. Limiting Break DBA Acceptance Suction Criteria
3. Limiting Failure HPCS DG -
4. Peak Cladding Temperature < 1370(3) 2200(1)

(Licensing Basis)

5. Upper Bound PCT < 1250(3) 1600F(2)
6. Maximum Local Oxidation < 0.2% 17%(1)
7. Core-Wide Metal-Water < 0.1% 1,0%(1)

Reaction NOTES:

(1)

Acceptance criteria is from <10 CFR 50.46>.

(2)

Acceptance criteria is from NRC SER written for SAFER/GESTR-LOCA methodology.

(3)

SAFER/GESTR-LOCA Licensing Basis PCT for MEOD. The licensing result for the limiting fuel (GE11) would be bounding for GE10 and GE12 fuels.

(4)

<Appendix 15B>, Reload Safety Analysis provides the results of a performance analysis for the new (reload) fuel designs.

Revision 18 6.3-69 October, 2013

TABLE 6.3-6 KEY TO FIGURES

- Recirculation Break Limiting Large Break Intermediate Break Typical Small Break

- Break Size DBA 1.0 ft2 0.1 ft2

- Location Suction Suction Suction

- Failure HPCS DG HPCS DG HPCS DG

- Assumption Nominal Nominal Nominal Water Level in Hot & Average <Figure 6.3-11 (1)> <Figure 6.3-12 (1)> <Figure 6.3-13 (1)>

Channels Reactor Vessel Pressure <Figure 6.3-11 (2)> <Figure 6.3-12 (2)> <Figure 6.3-13 (2)>

Peak Cladding Temperature(1) <Figure 6.3-11 (6)> <Figure 6.3-12 (6)> <Figure 6.3-13 (6)>

Heat Transfer Coefficient(1) <Figure 6.3-11 (7)> <Figure 6.3-12 (7)> <Figure 6.3-13 (7)>

ECCS Flow <Figure 6.3-11 (5)> <Figure 6.3-12 (5)> <Figure 6.3-13 (5)>

Core Inlet Flow <Figure 6.3-11 (10)>

Minimum Critical Power Ratio <Figure 6.3-11 (11)>

Revision 12 6.3-70 January, 2003

TABLE 6.3-6 (Continued)

- Recirculation Break Limiting Large Break Intermediate Break Typical Small Break

- Break Size DBA 1.0 ft2 0.1 ft2

- Location Suction Suction Suction

- Failure HPCS DG HPCS DG HPCS DG

- Assumption <10 CFR 50, Appendix K> <10 CFR 50, Appendix K> <10 CFR 50, Appendix K>

Water Level in Hot & Average <Figure 6.3-14 (1)> <Figure 6.3-15 (1)> <Figure 6.3-16 (1)>

Channels Reactor Vessel Pressure <Figure 6.3-14 (2)> <Figure 6.3-15 (2)> <Figure 6.3-16 (2)>

Peak Cladding Temperature(1) <Figure 6.3-14 (6)> <Figure 6.3-15 (6)> <Figure 6.3-16 (6)>

Heat Transfer Coefficient(1) <Figure 6.3-14 (7)> <Figure 6.3-15 (7)> <Figure 6.3-16 (7)>

ECCS Flow <Figure 6.3-14 (5)> <Figure 6.3-15 (5)> <Figure 6.3-16 (5)>

Core Inlet Flow <Figure 6.3-14 (10)>

Minimum Critical Power Ratio <Figure 6.3-14 (11)>

NOTE:

(1)

Plots are for GE11 fuel only.

Revision 12 6.3-71 January, 2003

TABLE 6.3-7 ECCS DESIGN PARAMETERS Design System Parameter Value_ Basis LPCS Pool suction line 100 psig Nominal value, suction design pressure from RPV (shutdown test)

RHR Pool suction line 100 psig Nominal value, suction design pressure from RPV (shutdown test)

HPCS Design pressure 100 psig Nominal value, suction for suction from from condensate tank condensate storage RHR Shutdown suction 200 psig Max vessel cut in line pressure pressure + max. vessel water level above pump LPCS Pump discharge 600 psig(1) Shutoff head + max.

line pressure suction pressure RHR (LPCI) Pump discharge 500 psig(1) Shutoff head + max.

line pressure suction pressure HPCS Pump discharge 1,575 psig Shutoff head + max.

line pressure suction pressure LPCS Pump suction & 185F Maximum expected discharge temp. temperature of pumped fluid (i.e., maximum containment design temperature)

<Regulatory Guide 1.1>

HPCS Pump suction & 185F Maximum expected discharge temp. temperature of pumped fluid (i.e., maximum containment design temperature)

<Regulatory Guide 1.1>

Revision 12 6.3-72 January, 2003

TABLE 6.3-7 (Continued)

Design System Parameter Value_ Basis RHR (LPCI) Pool suction 185F Maximum expected temperature of pumped fluid (i.e., maximum containment design temperature)

<Regulatory Guide 1.1>

RHR Shutdown line 358F Max shutdown suction temperature temperature (satura-tion @ 135 psig)

LPCS Rated flow 6,000 gpm
@122 psid (over drywell) RHR (LPCI) Rated flow 6,500 gpm/
loop - 3 loops @20 psid (over drywell) HPCS Rated Flow 6,000 gpm
@200 psid (value selected to provide adequate core cooling, all design basis events) LPCSRPV pressure at 289 psid
beginning flow (over (value selected to drywell) provide adequate core cooling all design basis events) RHR (LPCI) RPV pressure at 225 psid
(value beginning flow (over selected to provide drywell) adequate core cooling for all design basis events) Revision 12 6.3-73 January, 2003 TABLE 6.3-7 (Continued) Design System Parameter Value_ Basis HPCSRPV pressure 1,200 psid
(value selected to provide adequate core cooling for all design basis events) LPCS Time to rated 27 sec
speed (value selected to provide adequate core cooling for all design basis events) RHR (LPCI) Time to rated 27 sec
(value pump speed selected to provide adequate core cooling for all design basis events) HPCS Time to rated 27 sec
(value Pump speed selected to provide adequate core cooling for all design basis events) LPCS Injection valve 32 sec(2)
(value open sufficient (after selected to provide to pass rated pressure adequate core cooling flow permissive) for all design basis events) RHR (LPCI) Injection valve 32 sec(2)
(value open sufficient (after selected to provide to pass rated pressure adequate core cooling flow permissive) for all design basis events) HPCS Injection valve 29 sec(3)
(value open sufficient selected to provide to pass rated adequate core cooling flow for all design basis events) Revision 17 6.3-74 October, 2011 TABLE 6.3-7 (Continued) NOTES: (1) Discharge piping design rating is based on ASME code Section III criteria; applicable pressure/temperature rating is 720 psig (@100F) to 625 psig (@500F). (2) Calculated valve stroke time is 32 seconds. Required flow will be established prior to the valve reaching full open, providing margin for considerations such as diesel generator operation at minimum allowable frequency and voltage. (3) Calculated injection valve stroke time is 29 seconds including the time to start the emergency diesel generator. Required flow will be established prior to reaching full open, providing margin for considerations such as diesel generator operation at minimum allowable frequency and voltage. Design basis analysis assumes HPCS injection begins at 29 seconds. Revision 17 6.3-75 October, 2011 TABLE 6.3-8 MANUAL VALVES IN HPCS SYSTEM(1) Methods for Minimizing Valve No. Type Location Service Function Positioning Error(2) F036 12 Gate Drywell Main Process Main Process Line NO; position indications Line Block Valve light (control room mounted) F026 6 Gate Aux. Bldg. Flushing Backflush Line By- NC; closed passing Check Valve (F024) F031 6 Gate Aux. Bldg. Flushing Flushing Water Supply NC; backed by check valve line to HPCS pump F003 Discharge F034 2 Globe Aux. Bldg. Jockey Pump Jockey Pump suction NO; during HPCS operation, Lines isolation valve position is not critical; closed F033 1 Globe Aux. Bldg. Jockey Pump Jockey Pump minimum NO; during HPCS operation, Lines flow line to HPCS pump position is not critical suction F006 1-1/2 Stop Aux. Bldg. Jockey Pump HPCS Jockey Pump Open - Throttled; HPCS Check Lines Discharge isolation operation would not be valve affected by this valves position (closed) F019 6 Gate Aux. Bldg. Flushing and HPCS Pump suction line NC Servicing Drain to Radwaste System Revision 21 6.3-76 October, 2019 TABLE 6.3-8 (Continued) NOTES: (1) Piping low point drains, high point vents and test connections are provided with dual isolation. (2) NO = Normally open NC = Normally closed Backed by . . ., = Double valve arrangement precluding impact on system operation without two position errors and/or a non-manual valve failure. Closed = Indicates valve is in line that forms closed loop with piping that, without a double positioning error, would have no effect on system functioning. Revision 12 6.3-77 January, 2003 TABLE 6.3-9 MANUAL VALVES IN LPCS SYSTEM(1) Methods for Minimizing Valve No. Type Location Service Function Positioning Error(2) F007 12 Gate Drywell Main Process Main Process line NO; position indicating Line block valve light (control room mounted) F025 6 Gate Aux. Bldg. Flushing Flushing water supply NC; backed by a blind flange to LPCS pump discharge piping to vessel F004 6 Gate Aux. Bldg. Flushing Back flush line NC; Closed bypassing check valve F003 F008 6 Gate Aux. Bldg. Flushing and LPCS pump suction line NC; Closed Servicing drain to radwaste system F032 2 Globe Aux. Bldg. Jockey Pump LPCS Jockey pump suction NO; LPCS operation would not Lines isolation valve be affected by this valves position (closed) F035 3/4 Globe Aux. Bldg. Jockey Pump Jockey Pump minimum NO; LPCS operation would not Lines flow to LPCS suction be affected by this valves lines position (closed) F034 1-1/2 Globe Aux. Bldg. Jockey Pump LPCS Jockey pump Open-Throttled; LPCS Stop Check Lines Discharge isolation operation would not be valve affected by this valves position (closed) Revision 21 6.3-78 October, 2019 TABLE 6.3-9 (Continued) NOTES: (1) Piping low point drains, high point vents and test connections are provided with dual isolation. (2) NO = Normally open NC = Normally closed Backed by . . ., = Double valve arrangement precluding impact on system operation without two position errors and/or a non-manual valve failure. Closed = Indicates valve is in line that forms closed loop with piping that, without a double positioning error, would have no effect on system functioning. Revision 12 6.3-79 January, 2003 TABLE 6.3-10 MANUAL VALVES IN LPCI (RHR) SYSTEM(1) Methods for Minimizing Valve No. Type Location Service Function Positioning Error(2) F029 A,B,C 18 Gate Aux. Bldg. Main Process Block Valves on RHR NO; See Note(3) Line Pumps discharge lines F039 A,B,C 12 Gate Drywell Main Process Process Line Block NO; position indicating Line Valve for leak testing light (control room mounted) check valves A,B,C F066 A,B 10 Gate Aux. Bldg. Fuel Pool From spent fuel pool NC; position monitoring Cooling to RHR pumps A, B switches suction F067 18 Gate Aux. Bldg. Main Process Shutdown suction to NC Line Pump C F099 A,B 10 Gate Aux. Bldg. Fuel Pool Return to spent fuel NC Cooling after heat exchanger pass F552 A 10 Stop Aux. Bldg. Flushing RHR Line flushing NO Check F552B 10 Stop Aux. Bldg. Flushing RHR Line flushing Locked Closed Check F018 A,B,C 6 Gate Aux. Bldg. Minimum flow Minimum flow line to Locked in throttled and standby suppression pool from position RHR pumps A,B,C discharges Revision 21 6.3-80 October, 2019 TABLE 6.3-10 (Continued) Methods for Minimizing Valve No. Type Location Service Function Positioning Error(2) F047A,B 18 Gate Aux. Bldg. Main Process RHR Heat exchanger NO; position indicating Line isol. valve light (control room mounted) See Note(4) F071 A,B 8 Gate Aux. Bldg. Flushing RHR A,B Pump suction NC line drains to radwaste system F072 A,B 8 Gate Aux. Bldg. Flushing RHR A,B Pump discharge NC Line drains to Radwaste system F511 A,B 8 Gate Aux. Bldg. Flushing RHR A,B,C pump drains LO; backed by NC valves to radwaste system F071 A,B,C and F072 A,B,C F010 20 Gate Drywell Main Process Decay Heat Removal NO; position indicating Line light (control room mounted) F071C 8 Gate Aux. Bldg. Flushing RHR C pump suction line NC; backed by NC valve F072C drains to radwaste system F072C 8 Gate Aux. Bldg. Flushing RHR C pump discharge NC; backed by NC valves line drains to Radwaste F071C and F511B system F082 2 Globe Aux. Bldg. Jockey Pump RHR loop B,C Jockey NO; during LPCI operation, Lines pump suction isolation position is not critical; closed F085 A,B,C 1-1/2 Aux. Bldg. Jockey Pump RHR loop A,B,C Jockey NO Globe Stop Lines pump discharge Check isolation Revision 21 6.3-81 October, 2019 TABLE 6.3-10 (Continued) Methods for Minimizing Valve No. Type Location Service Function Positioning Error(2) F502 A,B, 6 Gate Aux. Bldg. Flushing RHR Heat exchanger line NC; backed by F503 A,B,C,D. C,D Flushing F503 A,B, 6 Gate Aux. Bldg. Flushing RHR Heat exchanger line NC; backed by F502, A,B,C,D. C,D Flushing F504 8 Gate Aux. Bldg. Flushing RHR Loop B pump NC; backed by F104 discharge flushing line F102 1-1/2 Aux. Bldg. Main Process RCIC Turb. Exh. Vac. Locked Closed; backed by F078 Globe Line RLF to RHR F0621 12 Gate Aux. Bldg. Main Process Provide isolation of RHR NO; Lock open during Line Loop A from ADHR system Modes 1, 2, and 3 for maintenance F0625A 4 Ball Aux. Bldg. Flushing RHR A Chemical Decon. NC; backed by blind flange NOTES: (1) Piping low point drains, high point vents and test connections are provided with dual isolation. (2) NO = Normally open NC = Normally closed Backed by . . ., = Double valve arrangement precluding impact on system operation without two position errors and/or a non-manual valve failure. Closed = Indicates valve is in line that forms closed loop with piping that, without a double positioning error, would have no effect on system functioning. (3) The incorrect positioning of F029 A,B,C would also be detected during normal plant operations when LPCI flow capacity verification tests are periodically conducted. (4) Electrically operated valve with no automatic open function administratively controlled to ensure it is open. Revision 22 6.3-82 October, 2021 6.4 HABITABILITY SYSTEMS Control room systems are designed in accordance with the design bases described in <Section 6.4.1> so that habitability of the control room can be maintained under normal and accident conditions. The general guidance contained in General Design Criterion 19 of <10 CFR 50, Appendix A>, and the specific guidance contained in <Regulatory Guide 1.78> is reflected throughout this section. 6.4.1 DESIGN BASES The design bases for control room habitability systems are as follows:
a. Control Room Envelope The control room envelope includes most areas located on Elevation 654-6 of the control complex, with the exception of the elevator area, the stairwell, and the mechanical and electrical chase areas. Housed within this control room envelope are the monitoring equipment, instrumentation and control panels required for safe operation and shutdown of the plant. The control room envelope is provided with fire protection equipment, adequate lighting, communications equipment, kitchen, sanitary, administrative and storage facilities, and spaces necessary to perform the normal plant operations required to maintain the plant in a safe condition following an accident. The control room envelope ambient atmosphere is normally maintained at the conditions presented in <Figure 3.11-17>.
b. Period of Habitability The control room envelope is equipped to sustain seven people for a period of seven days following an accident.
Revision 14 6.4-1 October, 2005
c. Capacity The normal occupancy level of the control room is six people following an accident.
d. Food, Water, Medical Supplies, and Sanitary Facilities First aid equipment, food and water are provided to sustain seven people for seven days following an accident. Chemical toilet facilities are provided for use in the event that normal sanitary facilities become inoperative.
e. Radiation Protection Radiation protection, as required by <10 CFR 50.67>, is provided by shield walls on the four exposures, shield slabs at floor and ceiling, radiation monitoring equipment, and emergency filtering systems. The control room atmosphere is monitored for radiation.
When required, the control room atmosphere can be recirculated through the emergency filter system to remove contaminants. This filter system consists of roughing, high efficiency particulate air (HEPA) and charcoal filters. Assumptions and analyses regarding sources and amounts of radioactivity which may surround or leak into the control room and related shielding requirements are discussed in <Chapter 12> and <Chapter 15>. The radiation monitoring system is discussed in <Section 12.3.4>.
f. Noxious Gas Protection Smoke detectors located in the control room air supply duct and in the emergency filter system discharge duct actuate alarms to indicate the presence of smoke in these locations. Additionally, Revision 19 6.4-2 October, 2015
the control room can be purged with outside air if required. Conformance with the guidelines given in <Regulatory Guide 1.78> is discussed in <Section 2.2.3>.
g. Toxic Gas Protection Based on the data in <Section 2.2.2>, the control room HVAC system is provided with oxygen monitors which alarm upon detecting a loss of oxygen in the air due to carbon dioxide buildup. No other toxic gas detectors or interlocks are considered necessary for ensuring control room habitability <Section 2.2.3.1.2.1>.
h. Respiratory Protection Breathing protection apparatus are provided for control room occupants. Breathable air is provided by 10 compressed air cylinders located in the service building at Elevation 620-6.
This air system supplies six breathable air stations with five connections on each station located in the control room. Self-contained breathing apparatus (SCBA) are provided for control room occupants. These SCBA can be supplied with air from the six breathable air stations in the control room or their own one hour compressed air bottle. The capacity of the 10 compressed air cylinders is sufficient to supply seven men for approximately six hours, plus each man has a one hour supply in his SCBA bottle. The SCBA bottles and the large air cylinders can be filled by a breathable air compressor located onsite or via offsite services.
i. Habitability System Operation during Emergencies Operation of the habitability system during emergencies is discussed in <Section 6.4.3>.
Revision 19 6.4-3 October, 2015
j. Emergency Monitors and Control Equipment Emergency monitors and control equipment are discussed in the PNPP Emergency Plan.
6.4.2 SYSTEM DESIGN 6.4.2.1 Definition of Control Room Envelope The control room envelope comprises those areas to which the control room operator could require access during an emergency. It includes the following:
a. Control room main control board and monitoring panel area -
continuous occupancy required.
b. Chart and storage room - infrequent access required.
c. Conference Room - infrequent access required.
d. Kitchen facility - infrequent access required.
e. Toilet room - infrequent access required.
f. Corridors/Hallway - infrequent access required.
The envelope includes those components that provide a boundary between the environment inside the control room and surrounding atmosphere. The components include the control room ventilation system, structural penetrations (electrical and mechanical), access doors (plenum, duct, personnel), door seals, as well as the walls, ceiling, and floor of the 654 elevation of the control complex and duct chase. <Figure 6.4-1> and <Figure 6.4-2> Revision 14 6.4-4 October, 2005 The equipment to which the control room operator could require access during an emergency is listed in
. 6.4.2.2 Ventilation System Design The heating, ventilating and air conditioning (HVAC) and the emergency filtration systems for the control room are shown schematically in Revision 14 6.4-4a October, 2005 <Figure 6.4-1 (1)>. This figure illustrates components, ducts, dampers, instrumentation, and normal and emergency air flow rates, and consists of the following:
a. Control room HVAC system
b. Control room emergency recirculation system The components are not subject to the effects of catastrophic weather, internal or external missiles. Pipe whip, jet impingement and flooding effects are discussed in <Section 3.6> and are insufficient to cause a loss of system redundancy.
<Figure 6.4-2> presents a layout drawing of the control room, indicating doors, corridors, stairwells, and shielded walls. The location of potential radioactive gas releases and their effect upon control room operation, and the monitoring instrumentation and controls located therein are discussed in <Chapter 11>. 6.4.2.2.1 Control Room HVAC System The function of this system is to provide cooling, heating, ventilation, and, when required, smoke removal for the control room equipment areas and office during normal plant operation, plant shutdown, loss of offsite power, and during periods of emergency (loss-of-coolant accident or high radiation conditions). This system operates continuously to supply 45,000 cfm of conditioned air, including 6,000 cfm outside air for ventilation, to the control room to dissipate the internal heat load generated and maintain the control room ambient air at the conditions presented in <Figure 3.11-17>. Revision 14 6.4-5 October, 2005 During normal plant operation, the system supply (M25-C001A or B) and return fans (M25-C002A or B) run continuously, the outside air intake dampers (M25-F010A or B, M25-F020B or A), and the return damper (M25-F110A or B) are open, and the exhaust air damper (M25-F130A or B) is closed. Either the A set or the B set of supply and return components is in operation with the idle redundant equipment as backup. The emergency recirculation system is idle and closed off from the HVAC system by its closed discharge (M26-F040A or B) damper; see <Section 6.4.2.2.2> for further details on the operation of this system. Normally, 4,900 cfm is assumed to exfiltrate from the control room through normal openings, thereby ensuring a positive pressure inside the room. Electric heating coils (with SCR controllers) in the branch supply ducts to the various zones in the control room are provided to control the final ambient air temperature in each zone. An electronic thermostat in each zone is used to provide a signal to the SCR controller which will control the heating coil, depending upon final room temperature. Humidification is also provided by the control and computer rooms humidification system. An electronic humidity controller, with local indication, is located in the general area of the control room to modulate the electric motor-operated valve on the humidifier (M29-B002A, B). For further details in the operation of the humidification system see <Section 9.4.12>. In the event of a LOOP condition the radiation monitors go to the fail safe condition, thereby ensuring that the running train shifts to the emergency recirculation mode and the standby train starts in the emergency recirculation mode so that both sets A and B are running. Power is supplied by the standby diesel generators. The operator may shut down one of the trains after it has been established that both are operating satisfactorily. Revision 19 6.4-6 October, 2015 The instrument air system which supplies control air to the pneumatic dampers is not connected to the emergency bus. In the event of loss of offsite power (without LOCA) coupled with subsequent loss of control air, the pneumatic dampers assume their failed position as shown in <Figure 6.4-1 (1)>. This places the system in the recirculation mode with back flow prevented by check damper (M25-F551A, B). In the event of high smoke condition, except during a LOOP/LOCA condition, the smoke can be purged by manually setting the mode selector switch in the smoke clear mode. The main components of this system are located in the control complex at Elevation 679-6 and consist of two redundant supply plenums (M25-B001A and B001B), two redundant supply fans (M25-C001A, C001B) and two redundant return fans (M25-C002A, C002B), each rated at 100 percent of the total required capacity. Each supply plenum includes roughing filters and chilled water coils. Each outside air intake duct is provided with redundant dampers (M25-F010A or F010B and M25-F020A or F020B) in series to reduce the outside air inleakage when the system is in the emergency recirculation mode. A check damper (M25-F510A or F510B) is provided in the discharge duct of each supply fan. In addition, manually operated balancing dampers for balancing, and fire dampers for fire protection, are provided. Each return unit consists of a centrifugal fan (M25-C002A or C002B), an exhaust air isolation damper (M25-F130A or F130B), a return air isolation damper (M25-F110A or F110B), manually operated balancing dampers, and fire dampers. The exhaust isolation damper (M25-F130A or F130B) is normally closed and the return isolation damper (M25-F110A or F110B) is normally open. Revision 12 6.4-7 January, 2003 The fans, filter elements, coils, and dampers are of standard industrial design manufactured in accordance with the Quality Assurance (QA) requirements of Safety Class 3, Seismic Category I items. The filter racks and plenums are specially designed to satisfy system space requirements and also meet the above QA requirements. However, the electric duct heating coils and the humidifiers are nonsafety-related items. Design information for the major components in this system is listed in
. 6.4.2.2.2 Control Room Emergency Recirculation System The Perry Nuclear Power Plant utilizes the Alternate Source Term analyses approved by the Nuclear Regulatory Commission through License Amendments 122, 166, and 180. The control room emergency recirculation system is tested to ensure control room habitability following a design basis loss of coolant accident. The electric heaters described below are not required for the control room emergency recirculation system to perform its specified safety function based on the Alternate Source Term analyses. This system provides the necessary supplementary particulate and halogen filtration of the air supplied to the control room areas and offices during emergency periods and other abnormal conditions for personnel protection. This system is automatically activated by an emergency signal (such as LOCA), or high radiation, or by manually setting the mode selector switch to the emergency recirculation mode. While the system is automatically activated, no credit is taken during the first 30 minutes following a design basis LOCA. As a result of a LOOP condition the system will automatically activate in the emergency recirculation mode when power is restored to the emergency busses. The operator may shut down one of the trains after it has been established that both are operating satisfactorily. In addition, the receipt of the emergency signal causes dampers in the control room HVAC system to be automatically positioned to the emergency recirculation mode of operation (see Note 4 of <Figure 6.4-1 (2)>, for the damper Revision 21 6.4-8 October, 2019 positions).The vortex damper operator (M25-F260A, B) of the supply fan (M25-C001A, B) is then automatically de-energized allowing the operator spring to partially close the variable inlet vanes to reduce the supply air flow to 30,000 cfm. This flow reduction is required so that the supply fan and recirculation fan flow rates are compatible. Return fan (M25-C002A or B) is also deactivated and the electric heating coil in the charcoal filter train is automatically energized upon receipt of an emergency signal. The electric heaters are not credited in design basis accident analyses for humidity control. The emergency recirculation system causes the supply air to be filtered through the charcoal filter train (M26-D001A, B) before being distributed to the control room. This system is idle during normal plant operation. During periods of loss of offsite power, emergency power will be supplied by the standby diesel generators. The degree to which the recommendations of <Regulatory Guide 1.52> are followed is given in
. The main components of this system are located in the control complex at Elevation 679-6 and consist of two 100 percent capacity filter trains. Each filter train includes the following sequential components: demisters, roughing filters, electric heating coil, HEPA prefilters, charcoal filters, HEPA after filters, centrifugal fan, isolation damper, and check damper. The fans, filter elements and dampers are of standard industrial design, manufactured in accordance with Quality Assurance (QA) requirements of Safety Class 3, Seismic Category I items. The filter racks, frames and housing are specially designed to satisfy the system space requirements and also meet the above QA requirements. Design information for the major components in this system is listed in
. Revision 21 6.4-9 October, 2019 6.4.2.3 Leak Tightness The control room system is designed so that, when operating in a normal mode (admitting outside air), the system automatically maintains a positive differential pressure between the control room and the outside and thus, between the control room and adjacent spaces. During an emergency, when the system operates in the recirculation mode (no designed admittance of outside air), no attempt is made to pressurize the control room. In the recirculation mode, the potential paths of air infiltration to the control room include (1) outside air dampers and relief air dampers, (2) openings around supply and return ducts in the control room walls and in duct chase floors, (3) openings for electrical conduit and cables in the control room and chase walls and floors, (4) doors, and (5) piping. A review of these paths, summarized as follows, indicates that infiltration through these paths during the recirculation mode is minimal:
a. The outside air is sealed from the control room by two 40 inch wide by 48 inch high dampers in series, both gasketed and arranged to close in the recirculation mode and to fail closed upon loss of control air or power. While either damper can be used for isolation, the outermost isolation damper from the control room provides the boundary of the envelope. The maximum leakage is 29 cfm through a single 42-inch by 48-inch outside air damper in the recirculation mode, at an estimated pressure differential across the damper of 0.25 inches of water. Maximum leakage through two closed dampers in series is approximately 20 cfm. This estimate conservatively assumes no pressurization in the control room. If the control room were pressurized, the pressure differential across the dampers would decrease. The duct pressure loss calculations for the control room system indicate that, during operation in the recirculation mode and with control room ambient.
Revision 21 6.4-10 October, 2019 pressure assumed to be 0 psig, the pressure at the inside of the outside air inlet damper would be 0.25 inches of water.
b. Exhaust isolation is provided by a normally closed bubble tight damper and a normally open damper that closes on recirculation.
During recirculation, a check damper also provides isolation in the exhaust duct. Revision 21 6.4-10a October, 2019
c. Openings around supply and return ducts in the walls and floors of the control room and chases are sealed with expanded silicone foam with a fire resistance rating of three hours. These openings are air tight.
d. Openings for electrical conduit and cables in the walls and floors of the control room and chases are sealed in the same manner as the openings noted in Item c, above.
e. Doors from the control room to the chase area and stairwells are three hour fire rated doors with closures. The maximum anticipated 2
total air gap around each door is 0.27 ft .
f. Piping to plumbing fixtures, drains and potable water leaving the control room are sealed in the manner noted in Item c, above.
None of the control room doors lead directly to the outside. All doors lead to closed chase spaces, closed stairwells or closed corridor space. Thus, neither outside wind conditions nor other ventilation system cause infiltration or leakage into the control room. Various plant activities may require a temporary degradation of the control room boundary and consequently, increase the inleakage. This is discussed in more detail in <Section 6.4.4.1>. 6.4.2.4 Interaction With Other Zones and Pressure Containing Equipment The control room ventilation system does not communicate with other building areas where potential for radioactivity exists. Revision 15 6.4-11 October, 2007 There are no pressure containing pipes or equipment containing hazardous chemicals in the control room chases. The normal operating mode of the control room ventilation system maintains a positive pressure differential between the control room and adjacent spaces. The likelihood of infiltration is therefore further reduced. A radiation monitor sensing control room atmospheric radioactivity immediately causes the ventilation system to shift into the recirculation mode upon detection of high gaseous activity. Thus, the potential for entry of outside airborne material into the control room is reduced. The control room ventilation system can also be used to purge the control room with outside air at a constant flow rate of 30,000 cfm. 6.4.2.5 Shielding Design The control room shielding design is discussed in <Section 12.1>. 6.4.3 SYSTEM OPERATIONAL PROCEDURES The control room is served by redundant normal and redundant emergency HVAC systems. The emergency systems provide for operation in the recirculation mode, the smoke clearing mode during loss of offsite power and for activation of the carbon dioxide fire protection system and charcoal water spray system. The normal control room HVAC system operates continuously to provide heating, ventilating and cooling to various equipment and personnel areas in the control room. The control room emergency recirculation system is idle except when activated by an emergency signal or when the mode selector switch is manually set to EMER. RECIRC. During periods of emergency, such as a Revision 15 6.4-12 October, 2007 LOCA or high radiation, the dampers automatically are positioned for the recirculation mode. Also, following this type of emergency the return fan (M25-C002A or B) stops, both emergency recirculation fans (M26-C001A & B) and the control room HVAC supply fans (M25-C001A & B) start simultaneously, and subsequently, one fan train may be manually stopped. The control room has a smoke removal mode of operation used to purge the control room with outside air when smoke is detected. This is accomplished by remote-manually positioning the mode selector switch located on panel H13-P904 to SMOKE-CLEAR. Operation of this switch positions the related dampers to the purge mode and automatically positions the variable inlet vanes of the supply and return fans at 30,000 cfm flow. The position of system dampers during the normal, emergency recirculation and smoke clearing mode is indicated by Note 4 of <Figure 6.4-1 (2)>. If loss of offsite power occurs (without LOCA), emergency power is provided by the standby diesel generators and the system operates with dampers in the emergency recirculation mode. At this time, both supply fans (M25-C001A & B) and both emergency recirculation fans (M26-C001A & B) start automatically. If excess temperature occurs in emergency filter plenums (as indicated by a high-high temperature alarm), the fire protection water spray system in the filter plenum can be activated manually. This action also energizes the solenoid valve (M26-F081A or B) and opens the drain valve (M26-F080A or B). Deactivating the spray deluge valve de-energizes the solenoid valve (M26-F081A or B); however, the drain valve remains open until it is manually closed by a manual override lever. Revision 12 6.4-13 January, 2003 6.4.4 DESIGN EVALUATION Each of the operating systems which ensures control room habitability is discussed in detail in other sections. These systems, and the section in which they are discussed, are as follows:
a. Control room ventilation system, <Section 6.4.2>.
b. Fire protection system, <Section 9.5.1>.
c. Communications system, <Section 9.5.2>.
d. Lighting system, <Section 9.5.3>.
e. Offsite power system, <Section 8.2>.
f. Onsite power system, <Section 8.3>.
g. Radiation monitoring system, <Section 12.3.4>.
A summary evaluation of control room habitability based on selected considerations is presented in <Section 6.4.4.1>, <Section 6.4.4.2>, <Section 6.4.4.3>, <Section 6.4.4.4>,<Section 6.4.4.5>, and <Section 6.4.4.6>. 6.4.4.1 Radiological Protection The evaluation of radiological exposures to control room operators following a design basis loss-of-coolant accident is presented in <Section 15.6.5>. The analysis in <Section 15.6.5> assumes a constant unfiltered control room inleakage value of 1375 cfm after 30 minutes and for the duration of the LOCA accident. Revision 19 6.4-14 October, 2015 Normally, the control room boundary inleakage is maintained at a value consistent with pre-operational testing such that the actual inleakage is substantially less than 1375 cfm. Throughout the life of the plant, various plant activities may need to be performed which temporarily degrade the control room boundary such that the unfiltered inleakage significantly exceeds 1375 cfm. The design basis radiological calculations for a postulated LOCA assume an unfiltered inleakage of 6600 cfm for the first 30 minutes, which shows that it is acceptable to delay the restoration of the control room boundary, provided that once it is restored, the actual unfiltered inleakage would be reduced to at or below 1375 cfm for the remainder of the accident. This allows for temporary degradations of the boundary to occur without impacting overall accident dose to the control room operators. Administrative controls are utilized during planned degradations to ensure the boundary can be rapidly restored to within the bounding parameters of the analysis. 6.4.4.2 Toxic Gas Protection No toxic materials which could interfere with control room occupancy are stored in the plant. Sodium hypo-chlorite, rather than chlorine, is used as a biocide. No chlorine is stored on site. The potential effects of offsite and onsite hazardous materials are discussed in <Section 2.2.2> and <Section 2.2.3>. Protection against offsite toxic gases are detailed in <Section 6.4.1.g>. 6.4.4.3 Control Room Emergency Recirculation System The general arrangement and control of the control room emergency recirculation system is as described in <Section 6.4.2.2.2>. Detailed information concerning the emergency filter is presented in <Section 6.5.1>. The equipment is shielded, housed in a Seismic Category I structure, separated, redundant, and powered from the Revision 19 6.4-15 October, 2015 Class 1E electrical system. It is equipped with filters designed in accordance with the requirements of <Regulatory Guide 1.52> <Section 6.5.1>. No single failure results in loss of system function. In case of loss of offsite power, redundant emergency power will be provided by the standby diesel generators and the fans will be automatically started. The electric heating coils for the emergency recirculation system are connected to the standby diesel generators to allow operation of the coils during loss of offsite power. The power supply to each filter train heating coil is from a separate safety division bus. The electric heating coils are not credited in design basis accident analysis for humidity control. Single component failure analysis of the control room emergency filter system is discussed in
. Implementation of scheduled field testing, inspection and maintenance programs ensure that each filtering system performs in accordance with design requirements. 6.4.4.4 Control of the Control Room Thermal Environment The control room air handling system operates during normal and emergency periods to maintain an environment suitable for personnel and equipment. The conditions maintained and general system description are presented in <Section 6.4.2.2.1>. The system satisfies the single failure criteria by providing redundant, separated and shielded air handling and cooling water systems (see <Section 9.4.9> for details on the cooling water system). Thus, the integrity and operability of this system during normal and emergency periods is ensured. Revision 21 6.4-16 October, 2019 Each portion of the system is sized for its maximum anticipated internal cooling load, considering outdoor summer design conditions expected for no more than 2.5 percent of the year. Additional margin is provided in equipment selection to allow for degradation of coil surfaces, films and changes in system air flow during operation. Scheduled maintenance procedures assure that each system performs in accordance with design requirements. 6.4.4.5 Fire Protection Protection against fire hazards is provided by fire hose cabinets, CO2 extinguishers and dry chemicals in the control room and adjacent areas. These fire suppression devices are provided in accordance with requirements of the National Fire Codes of the National Fire Protection Association (NFPA), the requirements of American Nuclear Insurers (ANI), the applicable regulations of the State of Ohio, and the requirements of the Occupational Safety and Health Administration (OSHA). The state of readiness of the fire protection system is maintained by enforcing a program of listing, inspection and maintenance. Further evaluation of the fire protection system is presented in <Section 9.5.1>. 6.4.4.6 Food, Water and Sanitation A seven day supply of food is provided in the control room for emergency use. If the emergency requires confinement for periods longer than seven days, additional food will be brought onsite in protected containers. Site accessibility will be determined by the Radiation Protection Manager. Potable water is normally available from the potable water system described in <Section 9.2.4>. Should this system become unavailable during an emergency period, stored, bottled water is available in an area immediately adjacent to the control room. Additional bottled water could be brought into the control room, if required. Revision 12 6.4-17 January, 2003 Normal sanitation facilities are available as described in <Section 9.2.4>. Chemical toilets are also available in these areas for use in the event that the normal facilities become inoperative following an emergency. 6.4.5 TESTING AND INSPECTION The equipment which maintains control room habitability includes the emergency filter system, the control room air handling system and the chilled water system. Components of these systems are subjected to documented preoperational test procedures to verify proper wiring, system integrity and leak tightness, proper function of system components and control devices under normal and emergency conditions, and to establish system air and water balance in accordance with design requirements. Those not in accordance with design requirements are evaluated or repaired/replaced prior to final acceptance. The main components of the control room HVAC system, control room emergency recirculation system and the control complex chilled water system are readily accessible for inspection, testing and maintenance during normal plant operation or shutdown. Redundancy in the system enables inspection, maintenance and testing to be performed without interrupting the normal operation of the systems. Periodic tests will be performed on the control room emergency filter system. These tests will include measurement of differential pressure across the filter units and determination of filter efficiency to demonstrate that aging, weathering or poisoning of the filters has not significantly degraded the adsorption material in the charcoal and HEPA filters. Revision 12 6.4-18 January, 2003 After system startup, test and balance procedures have been completed, the system will be periodically and routinely tested, checked and/or inspected as follows:
a. Inspections are made for signs of corrosion, metal fatigue, excess vibration, and tightness of isolation dampers.
b. Filter pressure drops are checked and recorded.
c. Water and air flow rates in main pipes or main ducts are checked and verified against the design flow rates.
d. Functions of dampers, valves or control devices necessary for component isolation or changeover from normal to emergency mode are verified.
e. Charcoal filter canisters are laboratory tested in accordance with the recommendations of <Regulatory Guide 1.52>.
f. Bearings are lubricated.
g. The redundant components of the system are switched from the standby mode to the operating mode.
h. As part of the Control Room Envelope Habitability Program, the unfiltered air in-leakage into the control room envelope will be measured in accordance with the recommendations of <Regulatory Guide 1.197>.
i. An assessment of the Control Room Envelope Habitability Program will be performed in accordance with the frequencies specified in
<Regulatory Guide 1.197>. Revision 16 6.4-19 October, 2009 6.4.6 INSTRUMENTATION REQUIREMENTS Habitability systems instrumentation and control equipment provides for control and monitoring of performance and status during system operation and testing. The instrumentation and control provisions for each of the systems used to ensure control room habitability are discussed in other sections. A list of these systems and the sections in which they are discussed is presented in <Section 6.4.4>. A summary discussion is presented in <Section 6.4.6.1>, <Section 6.4.6.2>, <Section 6.4.6.3>, and <Section 6.4.6.4>. Revision 16 6.4-19a October, 2009 6.4.6.1 Control Room HVAC System Operation of this system is initiated manually from the Unit 1 control room, such that either the A or the B set of supply and return components is operating, with the redundant set of components idle as backup. The control room HVAC system (exclusive of the emergency recirculation fans, ducts and filters) is provided with controls for temperature, flow and humidity. This system is provided with alarms, status lights and indicators in the Unit 1 control room to provide the operator with sufficient information to determine the status and operation of the system from the control room. The system is also equipped with sensors and detectors to detect, alarm and monitor smoke and radiation. The details of the instrumentation and controls for this system are presented in <Section 7.3.1>. 6.4.6.2 Control Room Emergency Recirculation System Operation of this system is initiated automatically upon receipt of an emergency signal or manually via the mode selector switch. During emergency recirculation mode of operation, one of the two fans (the one related to the active control room HVAC system) operates continuously. The control room emergency recirculation system is provided with controls for automatic or manual initiation. This system has sensors, instruments and indicators to monitor flow, pressure drop across filters, humidity, and charcoal filter temperature. Alarms, status lights and indicators located in the Unit 1 control room provide the operator sufficient information to determine system status and operation. The system instrumentation is designed essentially to conform with <Regulatory Guide 1.52>. No recorders are provided since this system is intended for infrequent use (periodic testing and emergency periods only), and operability and reliability difficulties Revision 12 6.4-20 January, 2003 become a factor for recorders that are infrequently used. Complete details of the system instrumentation and controls are presented in <Section 7.3.1>. 6.4.6.3 Lighting System Actuation of the control room emergency dc lighting system occurs automatically if the ac lighting system power is lost. 6.4.6.4 Offsite and Onsite Power Systems Operator control and monitoring of the status of onsite power, as well as offsite power feeds, are performed from control panels in the control room. Automatic actuation of each onsite ac emergency diesel generator occurs when an undervoltage condition is sensed on the associated bus. Revision 12 6.4-21 January, 2003 TABLE 6.4-1 EQUIPMENT WHICH COULD REQUIRE CONTROL ROOM OPERATOR ACCESS DURING AN EMERGENCY Item or Equipment Location Within Control Room Envelope Control and Monitoring Panels Identified on <Figure 6.4-2> and <Figure 9A-19> Portable Radiation Measuring Hallway outside control room Instruments Emergency Procedures, Manuals Operators work station and Drawings Self-Contained Breathing Apparatus Store room Communications Equipment Operators work station Fire Extinguishing Equipment Identified on <Figure 9A-19> Food Supplies Kitchen Revision 20 6.4-22 October, 2017 TABLE 6.4-2 DESIGN DATA FOR CONTROL ROOM HVAC SYSTEM MAJOR COMPONENTS A. PLENUMS No. of plenums 2 (each 100%) Manufacturer AAF B. SUPPLY FAN No. of fans 2 (each 100%) Manufacturer Westinghouse Fan type Centrifugal, SWSI Fan size (wheel diameter), in. 49 Arrangement No. 3 Discharge position Upblast Air quantity required, cfm 45,000 per fan Static pressure required, in. w.g. 5 per fan Motor horsepower, hp 60 per fan Motor location Direct driven Motor speed, rpm 860 Motor electrical characteristics 460V, 3 phase, 60 Hertz C. RETURN FAN No. of fans 2 (each 100%) Manufacturer Westinghouse Fan type Centrifugal, SWSI Fan size (wheel diameter), in. 49 Arrangement No. 3 Discharge position Upblast Revision 19 6.4-23 October, 2015 TABLE 6.4-2 (Continued) Air quantity required, cfm 39,000 per fan Static pressure required, in. w.g. 3 per fan Motor horsepower, hp 60 per fan Motor location Direct Driven Motor speed, rpm 900 Motor electrical characteristics 460V, 3 phase, 60 Hertz D. COOLING COILS No. of coil bank 1 per plenum Type of coil Horizontal finned tubes air-water counter flow Cooling capacity, tons 155 per coil bank Entering water temperature, F 45 Leaving water temperature, F 54.30 Chilled water flow rate (max.), gpm 400 per coil bank Max. coil face velocity, fpm 600 per coil bank E. DUCT REHEAT COILS No. of coils 9 for Unit 1 & Unit 2 Type Electric Type of Controller SCR Quantity and kW rating 2 - 2.5 kW 1 - 3 kW 4 - 30 kW 2 - 35 kW Electrical characteristics 480V, 3 phase, 60 Hertz Revision 12 6.4-24 January, 2003 TABLE 6.4-2 (Continued) F. ROUGHING FILTERS No. of filter banks 1 per plenum Manufacturer and Model AAF, Varicel 9-2424-12 (or equal) Material Glass fiber with aluminum separators No. of cells per bank 25 Rated flow per cell, cfm 2,000 Efficiency, % 90 (per ASHRAE 52-68) Max resistance, in. w.g. 0.55 (clean) Revision 12 6.4-25 January, 2003 TABLE 6.4-3 DESIGN DATA FOR CONTROL ROOM EMERGENCY RECIRCULATION SYSTEM MAJOR COMPONENTS A. PLENUMS No. of plenums 2 (each 100%) Manufacturer CVI B. FAN No. of fans 1 - 100% capacity per plenum Manufacturer Westinghouse Fan type Centrifugal, SWSI Fan size (wheel diameter), in. 36-1/2 Arrangement No. 8 Discharge position Upblast Motor location Direct Driven Motor speed, rpm 1,800 (Nominal) Air quantity required, cfm 30,000 per fan Static pressure required, in. w.g. 8 per fan Motor horsepower, hp 100 per fan Motor electrical characteristics 460V, 3 phase, 60 Hertz C. FILTERS
1. Demisters Manufacturer and Model ACS 101-55 No. of demister bank 1 per plenum No. of cells/bank 21 Revision 19 6.4-26 October, 2015
TABLE 6.4-3 (Continued) Rated flow per cell, cfm 1,600 Max. resistance at rated 0.97 (clean) flow, in. w.g.
2. Roughing Filters No. of filter banks 1 per plenum Manufacturer and Model Flanders, 00A-0-02-03NL (or equal)
No. of cells/bank 21 Rated flow per cell, cfm 2,000 Material Glass fiber without separators Efficiency, % 90 (per ASHRAE 52-68) Max. resistance at rated 0.49 (clean) flow, in. w.g.
3. HEPA Prefilters and After-filters No. of filter banks 2 per plenum Manufacturer and Model Flanders, 007-0-02-03-NU (or equal)
No. of cells per bank 21 Rated flow per cell, cfm 1,500 Material Continuous pleated web of glass fiber without separators Efficiency, % 99.97 for particles 0.3 microns and larger Max. resistance at rated 1.2 (clean) flow, in. w.g. Revision 12 6.4-27 January, 2003 TABLE 6.4-3 (Continued)
4. Charcoal Filters Manufacturer and Model CVI, HECA Module No. of filter banks/plenum 1 No. of beds per banks 15 - 2 thick beds Rated flow per bed, cfm 2,000 Material Activated coconut charcoal impregnated with KI Efficiency, % 99.9 on elemental iodine 97 on methyl iodide at 86F and 95 percent RH Max. resistance at rated flow, in. w.g. 1.4 (clean)
Charcoal ignition temperature F 626
5. Electric Heating Coil No. of coil banks 2 per plenum Heating capacity, kW 50 each Electrical characteristics 480V, 3 phase, 60 Hertz Revision 12 6.4-28 January, 2003
TABLE 6.4-4 SINGLE FAILURE ANALYSIS A. CONTROL ROOM EMERGENCY FILTER SYSTEM Component Malfunction Comments Fan Failure of operating Two 100 percent capacity fans fan resulting in are provided. If the operating loss of air flow fan fails, resultant loss of air flow in the duct actuates the alarm in the control room and the standby fan will be started manually by the operator. HEPA filters Release of DOP After initial installation of resulting in con- the HEPA filters and periodi-tamination of cally thereafter, the filter charcoal filters bank leak integrity will be determined by using DOP. On the basis of testing each HEPA filter element individually, a maximum of approximately 2.82 micrograms of DOP will be retained in each HEPA filter element. The control room emergency filter system has one HEPA filter element upstream of the charcoal filter and one HEPA filter element downstream of the charcoal filter. It is possible that the DOP can be released Revision 12 6.4-29 January, 2003 TABLE 6.4-4 (Continued) Component Malfunction Comments from the HEPA filter as the filter temperature increases. However, the charcoal adsorber being a poor particulate filter would retain a negligible quantity of DOP released in this manner. Combining I-131 with the retained DOP in the HEPA filter results in an insignificant amount of methyl iodine formed. The system has enough charcoal capacity to adsorb the maximum loading of both radioactive and non-radioactive isotopes of iodine and bromine. Also, the temperature of this system is substantially below the 410F flash point of DOP. Charcoal High temperature in Two 100 percent capacity filter filters the charcoal beds trains are provided in this system. In addition, temperature indicators and switches are provided in each charcoal cell bed to alarm in the control room and give an indication (readout) on rising Revision 12 6.4-30 January, 2003 TABLE 6.4-4 (Continued) Component Malfunction Comments charcoal temperature. Also, since the air flowing through the charcoal is at a low temperature (75-80F), this air will keep the charcoal filter temperature from rising to the critical value (250-300F desorption temperature). However, should the temperature reach 250F, an alarm is set in the control room to signal the operator. Actions can then be initiated to activate the charcoal water spray system and prevent the charcoal beds from desorbing. Also at this time, the standby charcoal filter train will be activated so that operation of the emergency recirculation system is not interrputed. Filter train Failure resulting High differential pressure in high differential across filters results in low pressure across HEPA air flow which is alarmed in the or charcoal filters control room. Operator may switch to the redundant train. Revision 12 6.4-31 January, 2003 TABLE 6.4-4 (Continued) Component Malfunction Comments Failure resulting High temperature is annunciated in high temperatures in the control room. High-high in the charcoal bed temperature is alarmed in the control room to signal operator. Actions can then be taken to initiate the deluge system. Initiation of the deluge system is indicated in the control room and the operator may switch to the redundant train. Dampers Loss of control air The dampers are spring assisted to position them in the safety or emergency mode of operation on loss of control air. Ducting Duct failure resulting This system is designed with in restriction or loss separate and redundant ducting of air flow and dampers. B. CONTROL ROOM HVAC SYSTEM Fan Failure of operating Two 100 percent capacity fans fan resulting in loss are provided. If the operating of air flow. fan fails, resultant loss of air flow in the duct actuates the alarm in the control room and the standby fan will be started manually by the operator. Revision 12 6.4-32 January, 2003 TABLE 6.4-4 (Continued) Component Malfunction Comments Supply Failure resulting High differential pressure Plenum in high differential across filter or coil results in pressure across low air flow which is alarmed in roughing filter or the control room. Operator may cooling coil. switch to the redundant train. Failure resulting High control room temperature is in high control room monitored in control room. temperature due to Operator may manually start loss of chilled water standby control water flow flow through cooling complex chiller and pump and coil. redundant air handling train. Humidifier Failure resulting in Humidity is indicated in control low or high humidity room. Humidifier and associated in control room. air handling train may be started by the operator upon indication of high or low control room humidity. Dampers Loss of control air The dampers are spring assisted or electronic signal. to position them in the safety or emergency mode of operation on loss of control signal. Ducting Duct failure resulting This system is designed with in restriction or separate and redundant ducting loss of air flow. and dampers. Revision 12 6.4-33 January, 2003 6.5 FISSION PRODUCT REMOVAL AND CONTROL SYSTEMS 6.5.1 ENGINEERED SAFETY FEATURES (ESF) FILTER SYSTEMS The control room emergency recirculation system (CRERS), the exhaust subsystem of Fuel Handling Area Ventilation System (FHAVS) known as the Fuel Handling Area Exhaust Subsystem (FHAES), and the annulus exhaust gas treatment system (AEGTS) are the ESF filter systems that reduce the concentration of airborne radioactive contaminants following a design basis accident (DBA). 6.5.1.1 Design Bases Design bases for the charcoal adsorber plenums of the CRERS, FHAES and the AEGTS are as follows:
a. Design Criteria The CRERS, FHAES and AEGTS are safety-related. System design conforms with the requirements of General Design Criteria (GDC) 1, 2, 3, 4, 19, 60, and 61 of <10 CFR 50, Appendix A>. To satisfy the requirements of these GDCs, the guidance presented in <Regulatory Guide 1.3>, <Regulatory Guide 1.13>, <Regulatory Guide 1.26>,
<Regulatory Guide 1.29>, <Regulatory Guide 1.47>, and <Regulatory Guide 1.52> has been considered in the design of these systems.
b. Need for Filtration The remote possibility of airborne radioactive contaminants entering the control room following a LOCA and the requirements of
<10 CFR 50.67> establish the need for the CRERS for filtration of control room air. <10 CFR 50.67> requires, in part, that adequate radiation protection be provided to permit access to, and occupancy of, the control room under accident conditions for the duration of Revision 19 6.5-1 October, 2015 the accident without radiation exposure to personnel in excess of 5 remTEDE. The remote possibility of release of airborne radioactive contaminants due to a fuel handling accident, the requirements of GDC 61, and the recommendations of <Regulatory Guide 1.13> establish the need for the FHAES to accomplish fuel pool area air filtration. GDC 61 requires, in part, that fuel storage and handling, and radioactive waste and other systems that may contain radioactivity be designed to ensure adequate safety under normal and postulated accident conditions and that appropriate filtering systems be provided. However, no accident dose calculations credit the FHAES <Section 15.7.4> and <Section 15.7.6>. The AEGTS is provided to reduce the radiological consequences of fission product releases in the containment from a LOCA, or fuel handling accident involving recently irradiated fuel, although credit is no longer taken for AEGTS filtration in the FHA dose calculation <Section 15.7.6>. AEGTS collects and filters the leakage from containment. Also, the AEGTS is designed to maintain a negative pressure in the annulus relative to the outside which minimizes ground level release of airborne radioactivity due to containment exfiltration during normal and postaccident conditions.
c. Component System Sizing Two 100 percent capacity filter units are provided for the CRERS.
Air flow rate for the CRERS is 30,000 cfm per plenum. Based on this assumed air flow rate and the assumed charcoal adsorber efficiencies and factors discussed in <Section 15.6>, the overall dose to the operators following an accident has been shown to satisfy the requirements of <10 CFR 50.67>. Revision 19 6.5-2 October, 2015 Three 50 percent capacity filter units are provided for the FHAES. The FHAES provides exhaust flow from the fuel handling area, the fuel pool cooling equipment rooms, the control rod drive maintenance area, and the control rod drive pump areas. Flow is 30,000 cfm. Of this quantity, 15,300 cfm is exhausted directly from the fuel pool area. This air flow rate is based on flow patterns that should entrain contaminants escaping from the fuel pool area. Two 100 percent capacity AEGTS filter units are provided. Air flow rate for the AEGTS is 2,000 cfm per plenum. Based on this flow rate, the negative pressure in the annulus is maintained at -0.25 inches of water gauge minimum continuously. Components of these filter systems have been sized to handle system air flow based on the recommendations of <Regulatory Guide 1.52>, ERDA 76-21 and general engineering practice.
d. Fission Product Removal Capability The fission product removal capability of the activated charcoal adsorber material used in the CRERS, FHAES and AEGTS is based on the recommendations of <Regulatory Guide 1.52>.
The decontamination efficiency of the AEGTS charcoal adsorber is 99 percent for both elemental iodine and organic species of iodine. However, none of the radiological consequence analyses credit any removal of elemental and organic iodines by the charcoal filters in the AEGTS. The AEGTS charcoal adsorber bed is 4 inches deep with annulus exhaust air maintained at less than 95 percent relative humidity. The decontamination efficiencies of the CRERS and FHAES charcoal adsorbers are 99 percent for elemental iodine and 95 percent for Revision 21 6.5-3 October, 2019 organic species of iodine. For the CRERS, the design basis LOCA <Section 15.6.5.5.1.9> credits an 80 percent removal efficiency of elemental and organic iodines by the charcoal filters in the CRERS. The Steam System Piping Break Outside Containment <Section 15.6.4>, Control Rod Drop Accident <Section 15.4.9>, and the Fuel Handling Accident <Section 15.7.4> and <Section 15.7.6>, do not take credit for the charcoal filters in the CRERS. For the FHAES, the alternative source termFHA analysis took no credit for the charcoal adsorbers. The CRERS and FHAES charcoal adsorber beds are 2 inches deep. Exhaust air for both plenums is maintained at less than 95 percent relative humidity. The HEPA filter efficiency of all the plenums is 99.97 percent on particles 0.3 microns and larger. However, the LOCA analysis only credits the HEPA filters in the AEGTS and CRERS at an efficiency of 99 percent. The other design basis radiological calculations do not take credit for the HEPA filters in the AEGTS, CRERS, or FHAES. Additional bases for the design of the CRERS, FHAES and AEGTS are presented in <Section 6.4>, <Section 9.4.2>, and <Section 6.5.3> respectively. 6.5.1.2 System Design The design features of the CRERS, FHAES and AEGTS are compared to the recommendations of <Regulatory Guide 1.52> in
,
, and
respectively. Design of the activated charcoal adsorber plenums used in the CRERS, FHAES and AEGTS follows the guidelines of <Regulatory Guide 1.52> and ERDA 76-21. Revision 21 6.5-4 October, 2019 Each charcoal adsorber plenum contains the following:
a. Demisters to remove large particles and water droplets (about 1 micron diameter).
b. Roughing filters to remove large particles (about 1 micron).
c. HEPA filters to remove small particles (0.3 to 1 micron), including fission product aerosols (particulates).
d. Electric heater coils.
Revision 21 6.5-4a October, 2019
e. Gasketless activated charcoal adsorber beds to remove gaseous elemental and organic iodines.
f. HEPA filters downstream of the charcoal beds to remove charcoal particles that may be entrained in the air stream.
g. A fan external to the plenum.
h. Instrumentation.
i. Test ports.
j. Water deluge system for fire protection.
Plenum housings and filter support frames are shop fabricated. Potential leakage and bypass paths are closed by seal welding. No caulking or sealant is used. Housings are fabricated of carbon steel sheet. Filter support frames are of unpainted stainless steel. Roughing and HEPA filters are mounted in frames in accordance with the recommendations of ERDA 76-21. The activated charcoal adsorber is bulk loaded into the permanently installed, gasketless adsorber section which is seal welded to the housing and support frames of the plenum. Tray type activated charcoal adsorber units are not used. Spent charcoal adsorber material is vacuumed from the bottom or top of the plenum and is loaded into 55 gallon drums for shipment off site. New charcoal adsorber material is added at the top of the adsorber section. Personnel are not directly exposed to potentially contaminated adsorber material during the changing procedure. Revision 12 6.5-5 January, 2003 The AEGTS and CRERS Roughing and HEPA filters are replaced when pressure drop across a filter exceeds the technical specification value. Pressure drop is measured by permanently installed differential pressure indicators. Charcoal adsorber material is changed when laboratory test results from representative samples show that the adsorber fails to satisfy the requirements of the Ventilation Filter Test Program. Essential services, such as power and electrical control cables associated with ESF filter systems, are protected as described in <Section 8.3.1.4>. The charcoal adsorber portion of each filter train is provided with a high temperature detection and water spray system to allow flooding of the charcoal bed in the unlikely event of high temperature in the charcoal (to preclude the possibility of iodine desorption). 6.5.1.3 Design Evaluation Design and safety evaluations of the CRERS, FHAES and AEGTS are presented in <Section 6.4>, <Section 9.4.2>, and <Section 6.5.3> respectively. The charcoal adsorber plenums are not exposed to conditions that can impair plenum efficiency. The FHAES and AEGTS are normally operated continuously during plant operation. The CRERS is operated for at least 15 minutes each month as recommended by <Regulatory Guide 1.52>; during this operation of CRERS, the exhaust air is free of radioactive contaminants. Air exhausted or circulated through the charcoal adsorber plenums is not expected to contain enough Revision 21 6.5-6 October, 2019 radioactive contaminants following a DBA to develop decay heat that could ignite the charcoal adsorber material. The charcoal adsorber plenums are redundant, physically separated and powered from separate Class 1E electrical systems. In the event smoke from a fire is exhausted through any charcoal filter, the filter will be tested for any degradation in charcoal performance as a result of the smoke. This testing will be performed in accordance with the Ventilation Filter Testing Program. If the testing indicates that degradation has occurred beyond acceptable limits, the charcoal will be replaced. For charcoal filters in systems needed to mitigate the consequences of a LOCA, the filters will be tested and the charcoal replaced, if required, within a period specified in the technical specifications. 6.5.1.4 Tests and Inspections Tests and inspections of the CRERS, FHAES and AEGTS charcoal adsorber plenums are performed prior to startup and on a periodic basis thereafter. Other tests and inspections of these filter systems are discussed in <Section 6.4>, <Section 9.4.2>, and <Section 6.5.3> respectively. 6.5.1.4.1 Filter and Charcoal Adsorber Tests HEPA filters are individually tested by an appropriate filter test facility at 100 percent and 20 percent of rated flow, in accordance with the recommendation of <Regulatory Guide 1.52>. Original or replacement HEPA filters used in the CRERS, FHAES and AEGTS are tested as indicated above. Each batch of charcoal adsorber material satisfies the acceptable results recommended by <Regulatory Guide 1.52>. Since the charcoal Revision 19 6.5-7 October, 2015 adsorber material is expected to be replaced several times during the 40 year life of the plant, test methods used may change. Therefore, only acceptable results of the tests are specified. 6.5.1.4.2 Inplace Testing After all the air cleaning units for CRERS, FHAES and AEGTS are installed, preoperational and inplace tests are performed as described in <Chapter 14> and
, with respect to <Regulatory Guide 1.52>. 6.5.1.4.3 Operation Periodic testing and inspection of CRERS, FHAES and AEGTS shall be performed in accordance with the Ventilation Filter Testing Program described in the plant technical specifications. 6.5.1.5 Instrumentation Requirements Instrumentation and actuation requirements for the CRERS, AEGTS and FHAES are discussed in <Section 6.4.6.2>, <Section 7.3.1.1.9>, and <Section 7.3.1.1.16> respectively. Each of the activated charcoal adsorber plenums has locally mounted differential pressure indicators to show the pressure drop across each filter bank in a plenum. These indicators permit the operator to determine when prefilters and HEPA filters should be changed. Each charcoal adsorber bed is provided with a permanently installed temperature sensing device and temperature switches which actuate alarms upon detection of a bed temperature of 225F and 250F. The water deluge fire protection system is manually actuated upon subsequent verification of a plenum fire. Revision 12 6.5-8 January, 2003 6.5.1.6 Materials Estimated quantities of materials used in the activated charcoal adsorber plenums for CRERS, FHAES and AEGTS are listed in
,
, and
respectively. The governing specifications for the various materials are also listed and provide information regarding chemical composition of materials used. There are no radiolytic or pyrolytic decomposition products from the ESF filter systems. Actuation of the activated charcoal adsorber plenum water deluge fire protection systems will extinguish a charcoal fire before pyrolytic decomposition products are formed. None of these systems are located in areas where gamma radiation sources are sufficiently strong to cause radiolytic decomposition products. Therefore, decomposition products do not affect any engineered safety features. 6.5.2 CONTAINMENT SPRAY SYSTEM 6.5.2.1 Design Bases
a. The containment spray system (CSS) is a part of the residual heat removal (RHR) system.
b. The CSS provides containment cooling following a loss-of-coolant accident, in addition to being a fission product removal mechanism.
Refer to <Section 6.2.2> for the heat removal function of the CSS.
c. The CSS consists of two completely redundant and independent loops.
(Loops A & B)
d. The CSS is designed to remain operable in the containment accident environment, which is discussed in <Section 3.11>.
Revision 12 6.5-9 January, 2003
e. The CSS is designed such that a single failure of any active component will not degrade the ability of the system to fulfill design objectives. Each loop of the CSS receives power from a separate emergency diesel generator, in the event that offsite power is unavailable during an accident. The two loops are physically separate from each other, so that a failure in one loop will not result in failure of the other loop due to fire, flooding, pipe breaks, or missiles.
f. The CSS is designed to Seismic Category I requirements. System components as appropriate are designed to meet ASME Code Section III, Class 2 requirements.
g. The CSS is designed to permit periodic testing as described in
<Section 6.2.2> and <Section 6.5.2.4>. 6.5.2.2 System Design The source of water supply for the CSS during all phases of system operation is the suppression pool. The water is pumped by the RHR pumps through the RHR heat exchangers to the containment sprayheaders. The CSS is shown on <Figure 5.4-14 (3)>. Each loop of the containment spray system consists of three concentric spray ring headers with equally spaced spray nozzles. Loop A consists of 104 nozzles on the top ring, 113 nozzles on the middle rings and 129 nozzles on the bottom ring. Loop B consists of 102 nozzles on the top, 113 nozzles on the middle and 129 nozzles on the bottom ring. The system diagram for the containment spray system is shown in <Figure 6.5-3>. The spray nozzles used are SPRACO 1713A hollow-cone ramp bottom nozzles each of which is capable of a flow of 15.2 gpm with a pressure drop of 40 psid. These nozzles have an approximately 3/8-inch spray orifice and Revision 12 6.5-10 January, 2003 are not subject to clogging by particles less than 1/4 inch in maximum dimension. Each nozzle header is independently oriented to ensure efficient coverage of the containment volume. The minimum water supply flow rate to the containment spray system is 5,250 gpm. There are no spray additives for the CSS (other than the pH buffering chemical, boron solution, from the standby liquid control system, which is injected into the reactor vessel and suppression pool following a design basis LOCA). The CSS will automatically initiate after 10 minutes of a LOCA signal if containment pressure exceeds the high pressure setpoint. If containment pressure is less than high pressure setpoint, the control room operator can actuate the system manually. The sprayed and unsprayed volumes and regions of the containment, with their associated mixing rates, are discussed in <Section 15.6.5>. The CSS takes no credit for ventilation. 6.5.2.3 Design Evaluation The containment spray mode of the RHR system is safety-related and is designed to operate following the postulated design basis loss-of-coolant accident. A high degree of system reliability is maintained through system quality control, by general equipment arrangement to provide access for inspection and maintenance and by periodic testing. A single failure analysis of the RHR system is given in <Section 6.2.2>. Because of the large volume of the containment atmosphere swept by the sprays, the spray mode serves as a removal mechanism for fission products postulated to be dispersed in the containment atmosphere following an accident. Radioiodine in its various forms is the fission Revision 20 6.5-11 October, 2017 product of primary concern in the evaluation of a loss-of-coolant accident. The major benefit of the containment spray is its capacity to collect and remove particulate (aerosol) and elemental iodines from the containment atmosphere and thus reduce their release to the environment. Offsite and control room operator doses are a function of both the rate of removal and the final equilibrium decontamination factor. The dose calculation assumes (non-mechanistically) that the containment spray will operate for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. However, the dose calculations also expand on this assumption, noting the following:
1) The dose calculations assume the sprays are run for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, then are suspended. This is the most important time period for scrubbing of radiation down into the suppression pool.
However, in an actual event, spray use would not necessarily be suspended at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, if appropriate conditions for their use still existed. Therefore, the phrase up to is not intended to be interpreted to stop using sprays after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
2) The phrase up to is intended to mean that in an actual event, the sprays will be run when it is appropriate, and not necessarily the entire time during the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of a LOCA. This does not invalidate the assumptions in the dose calculations. The accident guidance to operators must be written to be symptom based, rather than event based. Most postulated LOCAs will not result in large radiation releases. Therefore, it would not be appropriate to run containment sprays for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following such an event. Another critical factor in spray use is containment pressure. Use of the sprays will work to reduce containment pressures, due to steam condensation and the containment heat removal function that they provide. In the majority of cases, if a high radiation signal is present from the containment radiation monitor and pressures are elevated in containment, the sprays would be run. However, if containment pressure gets reduced to near zero and use of the sprays is terminated by the operators, this does not have an Revision 19 6.5-12 October, 2015
adverse impact on offsite doses (or the dose calculations) since the driving pressure for containment and MSIV leakage has been eliminated. The dose calcs assume that the maximum allowable leakage (La) corresponding to the peak postaccident pressure (Pa) remains during the entire 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, so if containment pressure actually gets reduced to substantially less than Pa, a reduction in leakage and the resultant offsite doses will follow. 6.5.2.3.1 Iodine Removal Performance Evaluation The elemental, organic, and particulate (aerosol) iodine removal analysis is based on the assumptions presented below and in
. The analysis uses the flow associated with only one RHR pump operating in the containment spray mode. It is conservatively assumed that the containment spray system directly sprays approximately 41 percent of the total containment free volume (excluding the drywell). <Section 15.6.5> provides a description of the volumes and flow paths used in the analyses. Elemental iodine removal is credited in the drywell and containment volumes. Airborne elemental iodine is removed by deposition to the walls in the drywell and containment. As reported in <Section 5.1.2> of <NUREG/CR-0009> (Reference 1), this process is driven by the temperature differences between the surfaces and the atmosphere. The calculated elemental iodine deposition removal factors for the sprayed and unsprayed containment and the drywell are given in
. These elemental iodine removal factors are applied until a decontamination factor (DF) of up to 200 is obtained. It has been conservatively assumed in these evaluations of spray removal effectiveness that organic iodine forms are not removed by the sprays. Revision 19 6.5-13 October, 2015 The model for particulate (aerosol) iodine removal is built into the RADTRAD code. Input parameters are presented in
. The particulate removal coefficient is reduced by a factor of 10 after the aerosol mass has been depleted by a factor of 50. Particulate removal is assumed to end at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when the sprays are assumed to be stopped. 6.5.2.3.2 Evaluation of Analytical Assumptions 6.5.2.3.2.1 Iodine Retention by Spray Solution The equilibrium between the concentrations of iodine in the liquid and vapor phases is given by the partition coefficient, H, which is a Revision 19 6.5-13a October, 2015 function of iodine concentration, pH and temperature. In accordance with (Reference 3) re-evolution of iodine does not have to be considered, (i.e., H will be very large) as long as the pH of the suppression pool is maintained greater than or equal to 7.0 postaccident. 6.5.2.3.2.2 Elemental Iodine and Particulate Removal Constant (Deleted) Revision 19 6.5-14 October, 2015 6.5.2.4 Tests and Inspections The CSS spray nozzles will be verified unobstructed following maintenance which could result in nozzle blockage. The test may be performed using an inspection of the nozzle or an air or smoke flow test. Further testing and inspection of the CSS is described in <Section 6.2.2>. 6.5.2.5 Instrumentation Requirements Instrumentation requirements for the CSS are discussed in <Section 7.3.1.1.4>. 6.5.2.6 Materials No spray additives are used in the CSS other than the pH buffering chemical (boron solution) from the standby liquid control system, which is injected into the reactor vessel and suppression pool following a design basis LOCA. 6.5.3 FISSION PRODUCT CONTROL SYSTEMS 6.5.3.1 Primary Containment The primary containment vessel is a hybrid pressure retaining structure composed of a steel cylinder and ellipsoidal dome secured to a steel lined reinforced concrete foundation mat. The containment vessel is designed to contain radioactive material that might be released during an accident and to ensure leak tightness during normal operating and Revision 19 6.5-15 October, 2015 accident conditions. Details of the primary containment vessel design are discussed in <Section 3.8>, and a section layout of containment vessel is shown on <Figure 3.8-1>. The primary containment pressure suppression concept uses the General Electric Mark III design. The primary containment vessel steel shell, mechanical penetrations, isolation valves, hatches, and locks will limit release of radioactive materials (subsequent to postulated accidents) such that the resulting offsite doses are less than the licensing basis limits. Primary containment parameters affecting fission product release accident analyses are given in
. Long term primary containment pressure response to the design basis accident is discussed in <Section 6.2.1>. Redundant, safety-related hydrogen recombiners are provided in the primary containment as the primary means of controlling postaccident hydrogen concentrations. A hydrogen purge system is provided for alternate hydrogen control. Details of the postaccident hydrogen control system are discussed in <Section 6.2.5>. During normal operation, the primary containment may be intermittently vented through a charcoal filter train. These normal primary containment ventilation supply and exhaust system penetrations are automatically isolated in response to LOCA signals (high drywell pressure and low reactor water level) and high radiation signals. The penetrations are provided with redundant, Seismic Category I, air operated, fail-closed, ASME Code Section III, Class 2 butterfly valves which assure prompt and tight closure of the openings. <Section 9.4.6> presents a detailed discussion of the containment purge system. Revision 12 6.5-16 January, 2003 6.5.3.2 Secondary Containment The secondary containment (shield building) is a reinforced concrete structure consisting of a flat foundation mat, a cylindrical wall and a shallow dome. The secondary containment boundary consists of the volume between the shield building and the primary containment vessel steel shell. Details of the shield building structural design are discussed in <Section 3.8> and the boundary region is shown in <Figure 3.8-1>. The annulus exhaust gas treatment system (AEGTS) processes the ambient air in the annular space between the shield building and the primary containment vessel to limit the release to the environment of radioisotopes which may leak from the primary containment under accident conditions. The AEGTS is a recirculation type system with split flow. Some of the filtered air extracted from the annulus space is recirculated and some is discharged to the unit vent. An analysis indicating the effectiveness of this system in controlling contamination releases is presented in <Section 15.6.5>. 6.5.3.2.1 Design Bases Design bases for the annulus exhaust gas treatment system are as follows:
a. The AEGTS is classified as Safety Class 2, Seismic Category I. The design of this system complies with the requirements of General Design Criteria (GDC) 1, 2, 3, 4, and 5 of <10 CFR 50, Appendix A>,
and <10 CFR 50, Appendix B> concerning ground level accident releases. The recommendations of <Regulatory Guide 1.26>, <Regulatory Guide 1.29>, <Regulatory Guide 1.47>, <Regulatory Guide 1.52>, <Regulatory Guide 1.53>, and <Regulatory Guide 3.2>, National Fire Protection Association (NFPA) 90A, and Branch Technical Position APCSB 9.5-1 have also been considered in the system design and equipment procurement. Revision 12 6.5-17 January, 2003
b. The AEGTS is:
1. Required to function during normal, shutdown and refueling operations, loss of offsite power periods and following a LOCA.
2. Started manually from the control room with the redundant system started automatically when low system air flow is indicated.
3. Designed to continuously maintain a negative pressure differential of 0.25 inches of water gauge minimum between the containment vessel annulus ambient and the outside (sensed in the auxiliary, intermediate and fuel handling buildings). The design parameters of this system include the leakage through the shield building (100 percent of the annulus volume per day), leakage from the containment vessel following an accident (0.2 percent of the containment volume per day),
increased annulus temperature following an accident, increased annulus air pressure resulting from the containment vessel expansion following an accident, and the discharge from the hydrogen purge subsystem.
4. Designed to direct the exhaust flow from the annulus through a charcoal filter plenum to ensure that the release of radioactivity to the environment is below permissible discharge limits.
5. Designed so that the exhaust inlet points from the annulus are remotely located from the return air to the annulus, thus promoting mixing of the annulus air.
6. Continuously monitored in the control room to indicate system operating status, system malfunction, high radiation in fan Revision 12 6.5-18 January, 2003
discharges, high smoke in fan discharges, temperatures in the charcoal plenums, and annulus to outside ambient pressure differential (sensed in the auxiliary, intermediate and fuel handling buildings).
7. Provided with redundant and separated equipment, control and power supplies so that a single active component failure will not prevent satisfactory system operation.
8. Designed with system operating components located in equipment areas not affected by internally generated missiles, pipe whip or jet impingement resulting from breaks in high or moderate energy piping.
6.5.3.2.2 System Description The AEGTS is shown on <Figure 6.5-1>. This system functions continuously during normal, shutdown and refueling operations, during loss of offsite power periods and following a LOCA to maintain a negative pressure differential between the containment vessel annulus ambient and the outside. The system includes two 100 percent capacity filter plenums (M15-D001A, B), two 100 percent capacity centrifugal fans (M15-C001A, B), and redundant supply, recirculation and exhaust ductwork systems. The plenums and fans are located in the intermediate building at Elevation 620-6. The system is provided with A equipment and B equipment, located in separate rooms. The duct distribution systems in the annulus are arranged so that the annulus ambient air is continuously circulated and mixed throughout the annulus space and then directed to the charcoal filter plenum. Air is extracted at one location and returned at another remote location to ensure adequate mixing of the recirculated air with the annulus volume. Also, adequate distribution ductwork is provided. The main exhaust header draws air Revision 19 6.5-19 October, 2015 from various regions of the annulus and the recirculation header returns the recirculated air at a different region. The exhaust header and the recirculation headers are located at appropriate distance from each other to assure that adequate mixing occurs in the annulus <Figure 6.5-2>. A portion of this filtered air is then discharged to the unit vent and the remaining portion is returned to the annulus. The continuous circulation and mixing ensures that any inleakage to the annulus ambient will be mixed with this ambient before being filtered and discharged. The amount of air discharged to the plant vent and the amount returned to the annulus is automatically controlled so that the negative differential pressure is maintained. The total extraction rate from the annulus is 2,000 cfm and the design maximum discharge rate to the atmosphere is 2,000 cfm. During normal operation the expected discharge to the unit vent is approximately 700 cfm, based on test data leakage through the shield building into the annulus (100 percent of annulus volume per day) at a negative pressure differential of 0.66 inches of water gauge. The 0.66 inches of water gauge pressure differential is provided to maintain the 0.25 inches of water gauge minimum pressure differential required due to instrument location, to meet plant post-LOCA conditions, and to adjust for all environmental conditions. During an accident, the maximum expected discharge rate is approximately 1,000 cfm. This takes into consideration a postulated leakage from the containment vessel to the annulus of 1.6 cfm (equivalent to 0.2 percent of containment volume per day at a containment pressure of 15 psi), the air expansion due to increase in temperature during the accident, and the increase in annulus air pressure due to the expansion of the containment steel shell. However, the discharge and recirculation dampers will modulate to vary the discharge flow from the expected maximum (approximately 1,000 cfm) to the design maximum (2,000 cfm), as required, to achieve and maintain a negative pressure differential of 0.66 inches of water gauge between the annulus and the atmosphere (sensed in the auxiliary, intermediate and fuel handling buildings). Revision 12 6.5-20 January, 2003 Two pressure differential transmitters, each located 180 apart, are provided for each filter plenum and fan. These transmitters are used to monitor the negative pressure differential in the annulus and send appropriate signals to the differential pressure controllers and recorders located in the control room. The differential pressure controller will modulate the discharge and recirculation dampers accordingly. Regular ac offsite power sources are provided for this system. If loss of offsite power occurs during a LOCA, redundant emergency power is available from the diesel generators. Inactive circulating and filtering components are isolated from the annulus space and the unit by check dampers, and by automatically controlled duct dampers. The redundant system automatically starts upon indication of low air flow from the operating system. Design information for the annulus exhaust gas treatment system components is listed in
. 6.5.3.2.3 Safety Evaluation The AEGTS maintains a negative pressure differential between the containment vessel annulus and the outside so that leakage from the containment vessel will be detained in the annular space, mixed with the annulus space air, diluted with air leakage into the annular space and filtered before release to the unit vent. The mixing and dilution of the annulus air is ensured by the supply and exhaust duct arrangement which includes distribution ducts with multiple supply and exhaust outlets along the circumference of the annulus space. The supply distribution ducts are near the bottom of the annulus (approx. Elevation 599-0) and the exhaust distribution ducts are near the top of the annulus (approx. Elevation 742-0). The annulus width is five feet. This resultant volume is the space in which containment Revision 12 6.5-21 January, 2003 vessel leakage is mixed with annulus space air before being directed to the filter plenum. The maximum exhaust flow rate from the annulus space directed to the filter is 2,000 cfm and the maximum expected amount of the filtered air released to the unit vent is 1,000 cfm. The remaining 1,000 cfm is circulated back to the annulus space for subsequent refiltering. This arrangement of duct systems, and the high proportion of recirculated and refiltered air, assures maximum mixing of leakage and maximum filtering before release to the unit vent. Minimum release of contamination after filtering is further assured by the filter plenum components which include a roughing filter, a demister, an electric heating coil for lowering of relative humidity, HEPA prefilters, 4-inch deep charcoal filters, and HEPA after-filters. When the system is operating at normal meteorological conditions (wind velocity up to 30 mph), the annulus is maintained at a negative pressure differential of 0.25 inches water gauge minimum relative to the outside by modulating the exhaust and recirculation dampers (sensed in the auxiliary, intermediate and fuel handling buildings). Operation of the system is monitored with alarms in the control room for system malfunctions including high temperature in ducts and plenums, high smoke, high radiation, loss of negative differential pressure, and high relative humidity of the exhaust air. Malfunctioning system components which affect sytem operation are stopped and isolated and redundant components are automatically placed in service. This assures maintenance of the negative differential pressure in the annulus at all times. The main components of the system are located in separate rooms. No unguarded high energy lines pass through the annulus space or in the AEGTS equipment areas. Revision 12 6.5-22 January, 2003 Redundancy in this system provides capability to maintain a negative differential pressure and to remove contaminants when considering failure of an active or passive component. If decay heat in the charcoal filter section raised the charcoal temperature to 250F, a control room alarm would alert the operator so that the charcoal filter deluge system could be manually activated upon verification of a plenum fire. 6.5.3.2.4 Inspection and Testing Requirements The various components of the AEGTS are accessible for inspection and testing during normal plant operation. The ability to isolate an idle redundant component enables inspection maintenance and testing to be performed while the system is in normal operation. Periodic tests, as recommended by <Regulatory Guide 1.52>, will be performed on the systems. These tests will include measurement of differential pressure across the filter banks and field and laboratory determination of filter leakage and efficiency. This will demonstrate that aging, weathering or poisoning of the filters has not significantly degraded the filter mounting or adsorptive material in the charcoal banks. These tests will also include verification of the functional performance of fans, dampers, controls, and other safety devices to ensure that these components perform their function reliably. 6.5.3.2.5 Instruments, Controls and Protective Devices Operation of the AEGTS is initiated by manually starting (from the control room) one of the two exhaust fans which then operates continuously. The details of the instrumentations and controls for this system are discussed in <Section 7.3.1>. Revision 12 6.5-23 January, 2003 6.5.4 ICE CONDENSER AS A FISSION PRODUCT CLEANUP SYSTEM This section is not applicable to PNPP. 6.

5.5 REFERENCES

FOR SECTION 6.5

1. Postma, A. K.; Sherry, R. R.; Tam, P. S.; Technological Bases for Models of Spray Washout of Airborne Contaminants in Containment Vessels, <NUREG/CR-0009>, October 1978.
2. ANSI/ANS-56.3-1979, American National Standard for PWR and BWR Containment Spray System Design Criteria.
3. Electrical Power Research Institute, Generic Framework for Application of Revised Accident Source Terms to Operating Plants, TR-105909, Interim Report, November, 1995.
4. Regulatory Guide 1.52, Design, Inspection, and Testing Criteria for Air Filtration and Adsorption Units of Post-Accident Engineered-Safety-Feature Atmosphere Cleanup Systems in LightWater-Cooled Nuclear Power Plants, Revision 2, March 1978.
5. NUREG-0800, Standard Review Plan (SRP) 6.5.2, Containment Spray As A Fission Product Cleanup System, Revision 4, March 2007.
6. Calculation 3.2.15.16, Design Basis LOCA Dose Evaluation Using Alternate Source Terms, Revision 1, July 2014.

Revision 19 6.5-24 October, 2015

TABLE 6.5-1 COMPARISON OF CONTROL ROOM EMERGENCY RECIRCULATION(1)(2)

SYSTEM WITH <REGULATORY GUIDE 1.52> POSITIONS Regulatory Position System Design Feature 1.a The design conforms with this position.

1.b The design conforms with this position.

1.c The design conforms with this position.

1.d The design conforms with this position.

1.e The design conforms with this position.

2.a The design conforms with this position.

2.b The design conforms with this position.

2.c The design conforms with this position.

2.d The filter units are not exposed to pressure surges from the postulated DBA.

2.e The design conforms with this position.

2.f The design conforms with this position.

2.g Pressure drops and flow rates are not monitored in the control room.

2.h The design conforms with this position.

2.i The design conforms with this position.

2.j The design conforms with the intent of this position. See <Section 12.1> for a discussion of conformance with <Regulatory Guide 8.8>.

2.k The design conforms with this position.

2.l The design conforms with this position. Duct and housing leak tests will be performed in accordance with Section 6 of ANSI N510-1980 instead of ANSI N510-1975.

3.a The design conforms with this position.

3.b The design conforms with this position.

Heater sizing conforms with Section 5.5 of ANSI N509-1980 rather than ANSI N509-1976.

Revision 21 6.5-25 October, 2019

TABLE 6.5-1 (Continued)

Regulatory Position System Design Feature 3.c The design conforms with this position.

3.d The design conforms with this position.

3.e The design conforms with this position.

3.f The design conforms with this position.

3.g The design conforms with this position.

3.h The design conforms with the intent of the recommendations of Section 4.5.8 of ERDA 76-21.

3.i The design conforms with this position. The impregnated activated carbon shall meet the qualification and batch test results summarized in Table 5-1 of ANSI N509-1980, which meets or exceeds the requirements of Table 5-1 of ANSI N509-1976.

3.j The design conforms with this position. The adsorbent shall meet the requirements of Table 5-1 of ANSI N509-1980, which meets or exceeds the requirements of Table 5-1 of ANSI 509-1976.

3.k The design of the charcoal adsorber section considers possible radioactivity-induced fires.

Water spray deluge fire protection system is provided.

3.l The design conforms with the intent of the recommendations of Sections 5.7 and 5.8 of ANSI N509-1976.

3.m The design conforms with this position.

3.n The design conforms with the recommendations of Section 5.10 of ANSI N509-1976.

3.o The design conforms with this position.

Revision 13 6.5-26 December, 2003

TABLE 6.5-1 (Continued)

Regulatory Position System Design Feature 3.p The design conforms with the intent of the recommendations of Section 5.9 of ANSI N509-1976.

4.a The design conforms with the intent of the recommendations of Section 2.3.8 of ERDA 76-21 and Section 4.7 of ANSI N509-1976.

4.b The maximum length of component plus 2-6, approximately, is provided due to space limitation imposed by equipment room size. It was determined that this is adequate for the replacement of the roughing and HEPA filters and is consistent with the manufacturers recommendations.

4.c The design conforms with this position.

4.d Refer to Regulatory Position 6.a.

4.e Preoperational Phase Testing meets the intent of this position. The testing will be performed while active construction is in progress on the project but sufficiently complete to assure that the installed HEPA filters and charcoal are not subjected to airflow that would invalidate inplace testing.

Revision 21 6.5-27 October, 2019

TABLE 6.5-1 (Continued)

Regulatory Position System Design Feature 6.a Testing procedure will operate the train for at least 15 minutes each month. The heaters will not be tested due to revised charcoal adsorber testing requirements consistent with ventilation systems without heaters.

6.b Testing conforms to this position.

6.c Testing procedures will meet the intent of this position. An exception has been made to use ANSI N510-1980 in lieu of ASME N511-2007 to align with Plant Technical Specifications.

6.d Testing conforms to this position.

6.e Testing conforms to this position.

6.f Testing procedures will meet the intent of this position. An exception has been made to use ANSI N510-1980 in lieu of ASME N511-2007 to align with Plant Technical Specifications.

6.g Testing conforms to this position.

6.h Testing conforms to this position.

6.i Testing conforms to this position.

7.a Testing meets the intent of this position.

7.b Sampling and analysis is performed at least once per 18 months, or following painting, fire or chemical release in any ventilation zone communicating with the subsystem. Laboratory testing is performed in accordance with ASTM-D3803-1989.

Revision 21 6.5-28 October, 2019

TABLE 6.5-1 (Continued)

Regulatory Position System Design Feature 7.c The activated carbon methyl iodide penetration has an acceptance criteria of less than 10%.

The LOCA analysis is the only accident analysis that credits the control room emergency recirculation system charcoal adsorbers. The LOCA analysis utilizes an 80 percent elemental and organic iodine removal efficiency with a safety factor of two.

7.d Testing conforms to this position.

Revision 21 6.5-29 October, 2019

TABLE 6.5-1 (Continued)

Regulatory Position System Design Feature NOTE:

(1) As discussed in <Section 15.6.5.5.1.9>, the design basis LOCA only credits an 80 percent removal efficiency of elemental and organic iodines by the charcoal filters in the CRERS. The steam system piping break outside containment <Section 15.6.4>, Control Rod Drop Accident <Section 15.4.9>, and the Fuel Handling Accident

<Section 15.7.4> and <Section 15.7.6>, do not take credit for the charcoal filters in the CRERS.

(2) Regulatory Positions 1.a through 4.e evaluate System Design Features against Revision 2 of <Regulatory Guide 1.52>, which detailed Environmental Design Criteria, System Design Criteria, Component Design Criteria and Qualification Testing, and Maintenance.

Regulatory Positions 6.a through 7.d evaluate System Design Features against Revision 4 of <Regulatory Guide 1.52>, which detail In-Place Testing Criteria and Laboratory Testing Criteria for Activated Carbon. Revision 4 of <Regulatory Guide 1.52> has been implemented by License Amendment 180.

Revision 21 6.5-30 October, 2019

TABLE 6.5-2 COMPARISON OF FUEL HANDLING AREA EXHAUST(1)

SUBSYSTEM WITH <REGULATORY GUIDE 1.52> POSITIONS Regulatory Position System Design Feature 1.a The design conforms with this position.

1.b The design conforms with this position.

1.c The design conforms with this position.

1.d The design conforms with this position.

1.e The design conforms with this position.

2.a The design conforms with this position.

2.b The design conforms with this position.

2.c The design conforms with this position.

2.d The filter units are not exposed to pressure surges from the postulated DBA.

2.e The design conforms with this position.

2.f The design conforms with this position.

2.g Pressure drops and flow rates are not monitored in the control room.

2.h The design conforms with this position.

2.i The design conforms with this position.

2.j The design conforms with the intent of this position. See <Section 12.1> for a discussion of conformance with <Regulatory Guide 8.8>.

2.k The design conforms with this position.

2.l The design conforms with this position. Duct and housing leak tests will be performed in accordance with Section 6 of ANSI N510-1980 instead of ANSI N510-1975 3.a The design conforms with this position.

3.b The design conforms with this position.

3.c The design conforms with this position.

Revision 21 6.5-31 October, 2019

TABLE 6.5-2 (Continued)

Regulatory Position System Design Feature 3.d The design conforms with this position.

3.e The design conforms with this position.

3.f The design conforms with this position.

3.g The design conforms with this position.

3.h The design conforms with the intent of the recommendations of Section 4.5.8 of ERDA 76-21.

3.i The design conforms with this position. The impregnated activated carbon shall meet the qualification and batch test results summarized in Table 5-1 of ANSI N509-1980, which meets or exceeds the requirements of Table 5-1 of ANSI N509-1976.

3.j The design conforms with this position. The adsorbent shall meet the requirements of Table 5-1 of ANSI N509-1980, which meets or exceeds the requirements of Table 5-1 of ANSI N509-1976.

3.k The design of the charcoal adsorber section considers possible radioactivity-induced fires.

Water spray deluge fire protection system is provided.

3.l The design conforms with the intent of the recommendations of Sections 5.7 and 5.8 of ANSI N509-1976.

3.m The design conforms with this position.

3.n The design conforms with the recommendations of Section 5.10 of ANSI N509-1976.

3.o The design conforms with this position.

Revision 12 6.5-32 January, 2003

TABLE 6.5-2 (Continued)

Regulatory Position System Design Feature 3.p The design conforms with the intent of the recommendations of Section 5.9 of ANSI N509-1976.

4.a The design conforms with the intent of the recommendations of Section 2.3.8 of ERDA 76-21 and Section 4.7 of ANSI N509-1976.

4.b The maximum length of component plus 2-6, approximately, is provided due to space limitation imposed by equipment room size. It was determined that this is adequate for the replacement of the roughing and HEPA filters.

4.c The design conforms with this position and is consistent with the manufacturers recommendations.

4.d Refer to Regulatory Position 6.a.

4.e Preoperational Phase Testing meets the intent of this position. The testing will be performed while active construction is in progress on the project but sufficiently complete to assure that the installed HEPA filters and charcoal are not subjected to airflow that would invalidate inplace testing.

Revision 21 6.5-33 October, 2019

TABLE 6.5-2 (Continued)

Regulatory Position System Design Feature 6.a An exception has been taken to this position.

The Fuel Handling Building and FHBES are not credited in mitigating the consequences of a fuel handling accident in the Fuel Handling Building, thus there is no need for testing.

6.b Testing conforms to this position.

6.c Testing procedures will meet the intent of this position. An exception has been made to use ANSI N510-1980 in lieu of ASME N511-2007 to align with Plant Technical Specifications.

6.d Testing conforms to this position.

6.e Testing conforms to this position.

6.f Testing procedures will meet the intent of this position. An exception has been made to use ANSI N510-1980 in lieu of ASME N511-2007 to align with Plant Technical Specifications.

6.g Testing conforms to this position.

6.h Testing conforms to this position.

6.i Testing conforms to this position.

7.a Testing meets the intent of this position.

7.b Sampling and analysis is performed at least once per 18 months, or following painting, fire or chemical release in any ventilation zone communicating with the subsystem. Laboratory testing is performed in accordance with ASTM-D3803-1989.

Revision 21 6.5-34 October, 2019

TABLE 6.5-2 (Continued)

Regulatory Position System Design Feature 7.c Testing procedures meet the intent of this position. Acceptance criteria is penetration less than 10 percent. Laboratory testing is performed in accordance with ASTM-D3808-1989.

7.d Testing conforms to this position.

NOTE:

(1) Regulatory Positions 1.a through 4.e evaluate System Design Features against Revision 2 of <Regulatory Guide 1.52>, which detailed Environmental Design Criteria, System Design Criteria, Component Design Criteria and Qualification Testing, and Maintenance.

Regulatory Positions 6.a through 7.d evaluate System Design Features against Revision 4 of <Regulatory Guide 1.52>, which detail In-Place Testing Criteria and Laboratory Testing Criteria for Activated Carbon. Revision 4 of <Regulatory Guide 1.52> has been implemented by License Amendment 180.

Revision 21 6.5-35 October, 2019

THIS PAGE INTENTIONALLY LEFT BLANK Revision 21 6.5-36 October, 2019

TABLE 6.5-3 COMPARISON OF ANNULUS EXHAUST GAS TREATMENT(1)(2)

SYSTEM WITH <REGULATORY GUIDE 1.52> POSITIONS Regulatory Position System Design Feature 1.a The design conforms with this position.

1.b The design conforms with this position.

1.c The design conforms with this position.

1.d The design conforms with this position.

1.e The design conforms with this position.

2.a The design conforms with this position.

2.b The design conforms with this position.

2.c The design conforms with this position.

2.d The filter units are not exposed to pressure surges from the postulated DBA.

2.e The design conforms with this position.

2.f The design conforms with this position.

2.g Pressure drops and flow rates are not monitored in the control room.

2.h The design conforms with this position.

2.i The design conforms with this position.

2.j The design conforms with the intent of this position. See <Section 12.1> for a discussion of conformance with <Regulatory Guide 8.8>.

2.k The design conforms with this position.

2.l The design conforms with this position. Duct and housing leak tests will be performed in accordance with Section 6 of ANSI N510-1980 instead of ANSI N510-1975 3.a The design conforms with this position.

3.b The design conforms with this position.

3.c The design conforms with this position.

Revision 21 6.5-37 October, 2019

TABLE 6.5-3 (Continued)

Regulatory Position System Design Feature 3.d The design conforms with this position.

3.e The design conforms with this position.

3.f The design conforms with this position.

3.g The design conforms with this position.

3.h The design conforms with the intent of the recommendations of Section 4.5.8 of ERDA 76-21.

3.i The design conforms with this position. The impregnated activated carbon shall meet the qualification and batch test results summarized in Table 5-1 of ANSI N509-1980, which meets or exceeds the requirements of Table 5-1 of ANSI N509-1976.

3.j The design conforms with this position. The adsorbent shall meet the requirements of Table 5-1 of ANSI N509-1980, which meets or exceeds the requirements of Table 5-1 of ANSI N509-1976.

3.k The design of the charcoal adsorber section considers possible radioactivity-induced fires.

Water spray deluge fire protection system is provided.

3.l The design conforms with the intent of the recommendations of Sections 5.7 and 5.8 of ANSI N509-1976.

3.m The design conforms with this position.

3.n The design conforms with the recommendations of Section 5.10 of ANSI N509-1976.

3.o The design conforms with this position.

Revision 12 6.5-38 January, 2003

TABLE 6.5-3 (Continued)

Regulatory Position System Design Feature 3.p The design conforms with the intent of the recommendations of Section 5.9 of ANSI N509-1976.

4.a The design conforms with the intent of the recommendations of Section 2.3.8 of ERDA 76-21 and Section 4.7 of ANSI N509-1976.

4.b The maximum length of component plus 2-6, approximately, is provided due to space limitation imposed by equipment room size. It was determined that this is adequate for the replacement of the roughing and HEPA filters and is consistent with the manufacturers recommendations.

4.c The design conforms with this position.

4.d Refer to Regulatory Position 6.a.

4.e Preoperational Phase Testing meets the intent of this position. The testing will be performed while active construction is in progress on the project but sufficiently complete to assure that the installed HEPA filters and charcoal are not subjected to airflow that would invalidate inplace testing.

Revision 21 6.5-39 October, 2019

TABLE 6.5-3 (Continued)

Regulatory Position System Design Feature 6.a Testing procedure will operate the train for at least 15 minutes each month. The heaters will not be tested due to revised charcoal adsorber testing requirements consistent with ventilation systems without heaters.

6.b Testing conforms to this position.

6.c Testing procedures will meet the intent of this position. An exception has been made to use ANSI N510-1980 in lieu of ASME N511-2007 to align with Plant Technical Specifications.

6.d Testing conforms to this position.

6.e Testing conforms to this position.

6.f An exception has been taken to this position.

None of the accident analyses credit iodine removal by charcoal adsorbers, thus there is no need for testing.

6.g An exception has been taken to this position.

None of the accident analyses credit iodine removal by charcoal adsorbers, thus there is no need for testing.

6.h An exception has been taken to this position.

None of the accident analyses credit iodine removal by charcoal adsorbers, thus there is no need for testing.

6.i Testing conforms to this position.

Revision 21 6.5-40 October, 2019

TABLE 6.5-3 (Continued)

Regulatory Position System Design Feature 7.a Testing meets the intent of this position.

7.b Sampling and analysis is performed at least once per 18 months, or following painting, fire or chemical release in any ventilation zone communicating with the subsystem. Laboratory testing is performed in accordance with ASTM-D3803-1989.

7.c Testing procedures meet the intent of this position. Acceptance Criteria meets or exceeds the standards in <Regulatory Guide 1.52>

Table 2. Laboratory testing is performed in accordance with ASTM-D3803-1989.

7.d Testing conforms to this position.

Revision 21 6.5-41 October, 2019

TABLE 6.5-3 (Continued)

Regulatory Position System Design Feature NOTE:

(1) As discussed in <Chapter 15>, none of the design basis events credit any removal of elemental and organic iodines by the charcoal filters in the AEGTS.

(2) Regulatory Positions 1.a through 4.e evaluate System Design Features against Revision 2 of <Regulatory Guide 1.52>, which detailed Environmental Design Criteria, System Design Criteria, Component Design Criteria and Qualification Testing, and Maintenance.

Regulatory Positions 6.a through 7.d evaluate System Design Features against Revision 4 of <Regulatory Guide 1.52>, which detail In-Place Testing Criteria and Laboratory Testing Criteria for Activated Carbon. Revision 4 of <Regulatory Guide 1.52> has been implemented by License Amendment 180.

Revision 21 6.5-42 October, 2019

TABLE 6.5-4 CONTROL ROOM EMERGENCY RECIRCULATION SYSTEM MATERIALS LIST (DESIGN DATA)

Filter Unit Housing Number of filter units 2 for Unit 1 & Unit 2 Manufacturer CVI-Pennwalt Filter holding frame Stainless steel, ASTM A 479, Type 304 Demisters Number, per filter unit 21 Manufacturer & model no. ACS, 101-55 General standards MSAR-71-45 Frame Material Stainless steel, ASTM A 479, Type 304 Media Stainless steel and fiberglass woven mesh Roughing Filters Number, per filter unit 21 Manufacturer Flanders (or equal)

Model number 00A-0-02-03NL General standards UL 900 Class 1; UL 586 Frame material 14-gauge Type 409 Stainless Steel Filter material 95 percent boron silicate fiberglass, 5 percent organic material (MIL-F-51079B)

Revision 12 6.5-43 January, 2003

TABLE 6.5-4 (Continued)

Adhesives Fire retardant polyurethane and rubber based adhesives Gaskets Sponge Neoprene (SCE-43)

Weight, per filter, lbs Steel, approx. 25 Glass and Miscellaneous Material, approx. 10 Total 35 HEPA Filters Upstream and Downstream Number, per filter unit 42 Manufacturer Flanders (or equal)

Model number 007-0-02-03NU General standards MIL-F-51068D; UL 900 Class 1; UL 586 Frame material 14-gauge Type 409 Stainless Steel Filter material 95 percent boron silicate fiberglass, 5 percent organic material (MIL-F-51079)

Adhesives Fire retardant solid urethane Gaskets Sponge Neoprene (SCE-43)

(ASTM D1056)

Weight, per filter, lb Steel, approx. 25 Glass and miscellaneous material, approx. 15 Total 40 Revision 12 6.5-44 January, 2003

TABLE 6.5-4 (Continued)

Activated Charcoal Adsorber Manufacturer CVI-Pennwalt Type of media New, activated coconut shell charcoal Impregnant Potassium iodide (KI) and elemental iodine type Weight of carbon, lb 5,700 Adsorber enclosure Stainless steel, ASTM A240, Type 304 Electric Heating Coil Manufacturer CVI-Pennwalt Frame material Stainless steel Heating element Stainless steel sheathed elements Revision 12 6.5-45 January, 2003

TABLE 6.5-5 FUEL HANDLING AREA EXHAUST SUBSYSTEM MATERIALS LIST (DESIGN DATA)

Filter Unit Housing Number of filter units 3 Manufacturer CVI-Pennwalt Filter holding frame Stainless steel, ASTM A479, Type 304 Demisters Number per filter unit 12 Manufacturer & model no. ACS, 101-55 General standards MSAR-71-45 Frame material Stainless steel, ASTM A479, Type 304 Media Stainless steel and fiberglass woven mesh Roughing Filters Number, per filter unit 12 Manufacturer Flanders (or equal)

Model number 00A-0-02-03NL General standards UL 900 Class 1; UL 586 Frame material 14-gauge Type 409 Stainless Steel Filter material 95 percent boron silicate fiberglass, 5 percent organic material Adhesives Fire retardant polyurethane and rubber based adhesives Revision 19 6.5-46 October, 2015

TABLE 6.5-5 (Continued)

Gaskets Sponge Neoprene (SCE-43)

Weight, per filter, lbs Steel, approx. 25 Glass and miscellaneous material, approx. 10 Total 35 HEPA Filters Upstream and Downstream Number, per filter unit 24 Manufacturer Flanders (or equal)

Model number 007-0-02-03NU General standards MIL-F-51068D; UL 900 Class 1; UL 586 Frame material 14-gauge Type 409 Stainless Steel Filter material 95 percent boron silicate fiberglass, 5 percent organic material (MIL-F-51079)

Adhesives Fire retardant solid urethane Gaskets Sponge Neoprene (SCE-43)

(ASTM D1056)

Weight, per filter, lb Steel, approx. 25 Glass and miscellaneous material, approx. 15 Total 40 Revision 12 6.5-47 January, 2003

TABLE 6.5-5 (Continued)

Activated Charcoal Adsorber Manufacturer CVI-Pennwalt Type of media New, activated coconut shell charcoal Impregnant Potassium iodide (KI) and elemental iodine type Weight of carbon, lb 3,040 Adsorber enclosure Stainless steel, ASTM A240, Type 304 Electric Heating Coil Manufacturer CVI-Pennwalt Frame material Stainless steel Heating element Inconel steel sheathed elements Revision 12 6.5-48 January, 2003

TABLE 6.5-6 ANNULUS EXHAUST GAS TREATMENT SYSTEM MATERIALS LIST (DESIGN DATA)

Filter Unit Housing Number of filter units 2 Manufacturer CVI-Pennwalt Filter holding frame Stainless steel, ASTM A479, Type 304 Demisters Number, per filter unit 2 Manufacturer & model no. ACS, 101-55 General standards MSAR-71-45 Frame material Stainless steel, ASTM A479, Type 304 Media Stainless steel and fiberglass woven mesh Roughing Filters Number, per filter unit 2 Manufacturer Flanders (or equal)

Model number 00A-0-02-03NL General standards UL 900 Class 1; UL 586 Frame material 14-gauge Type 409 Stainless Steel Filter material 95 percent boron silicate fiberglass, 5 percent organic material Revision 19 6.5-49 October, 2015

TABLE 6.5-6 (Continued)

Adhesives Fire retardant polyurethane and rubber based adhesives Gaskets Sponge Neoprene (SCE-43)

Weight, per filter, lbs Steel, approx. 25 Glass and miscellaneous material, approx. 10 Total 35 HEPA Filters Upstream and Downstream Number, per filter unit 4 Manufacturer Flanders (or equal)

Model number 007-0-02-03NU General standards MIL-F-51068D; UL 900 Class 1; UL 586 Frame material 14-gauge Type 409 Stainless Steel Filter material 95 percent boron silicate fiberglass, 5 percent organic material (MIL-F-51079)

Adhesives Fire retardant solid urethane Gaskets Sponge Neoprene (SCE-43)

(ASTM D1056)

Weight, per filter, lb Steel, approx. 25 Glass and miscellaneous material, approx. 15 Total 40 Revision 12 6.5-50 January, 2003

TABLE 6.5-6 (Continued)

Activated Charcoal Adsorber Manufacturer CVI-Pennwalt Type of Media New, activated coconut shell charcoal Impregnant Potassium iodide (KI) and elemental iodine type Weight of carbon, lb 804 Adsorber enclosure Stainless steel, ASTM A240, Type 304 Electric Heating Coil Manufacturer CVI-Pennwalt Frame material Stainless steel Heating element Inconel steel sheathed elements Revision 12 6.5-51 January, 2003

TABLE 6.5-7 PRIMARY CONTAINMENT OPERATION FOLLOWING A DESIGN BASIS ACCIDENT Type of structure Steel cylinder with ellipsoidal dome secured to a steel lined reinforced concrete foundation mat.

Internal fission product removal None systems Free volume of primary containment, ft3 1.16 x 106 (excluding drywell)

Hydrogen purge system operation <Section 6.2.5>

Containment leakage rate, Vol%/day 0.20 Effectiveness of internal fission Not applicable product removal systems Revision 12 6.5-52 January, 2003

TABLE 6.5-8 DESIGN DATA FOR ANNULUS EXHAUST GAS TREATMENT SYSTEM COMPONENTS Plenums (M15-D001A, 1B)

No. of plenums 2 Manufacturer CVI Corporation Demisters Manufacturer and model ACS, 101-55 No. of banks per plenum 1 No. of cells per bank 2 Material Stainless steel mesh Rated flow per cell, cfm 1,600 Max. resistance at rated flow, in. w.g. 0.97 (clean)

Roughing Filters Manufacturer and model Flanders, 00A-0-02-03NL (or equal)

No. of filter banks per plenum 1 No. of cells per bank 2 Rated flow per cell, cfm 2,000 Material Glass fiber without separators Efficiency, % 90 (per ASHRAE 52-68)

Max. resistance at rated flow, in. w.g. 0.49 (clean)

Revision 19 6.5-53 October, 2015

TABLE 6.5-8 (Continued)

HEPA Filters Manufacturer and model Flanders, 007-0-02-03NU (or equal)

No. of filter banks per plenum 2 No. of cells per bank 2 Rated flow per cell, cfm 1,500 Material Glass fiber without separators Efficiency, % 99.97 (on particles 0.3 micron or larger)

Max. resistance at rated flow, in w.g. 1.2 (clean)

Charcoal Filters Manufacturer and Model CVI, HECA module No. of charcoal beds per plenum 2 (4 inches thick)

Rated flow per bed, cfm 1,000 Material Activated coconut charcoal impregnated with KI Efficiency, % 99.9 on elemental Iodine 97 on methyl iodide at 86°F and 95 percent RH Maximum resistance at rated flow, in w.g. 2.5 (clean)

Heating Coil Manufacturer CVI-Pennwalt No. of coils per plenum 1 Revision 12 6.5-54 January, 2003

TABLE 6.5-8 (Continued)

Heating Coil (Continued)

Heating capacity per coil, kW 20 Electrical characteristics 480V, 3 phase, 60 Hertz Fans (M15-C001A, 1B)

No. required 2 Manufacturer Westinghouse Fan type Centrifugal SISW Fan size (wheel diameter), in. 15-1/2 Arrangement No. 8 Discharge position Upblast Air quantity required per fan, cfm 2,000 Static pressure required, in w.g. 11 Fan motor horsepower 15 Motor electrical characteristics 460V, 3 phase, 60 Hertz Revision 19 6.5-55 October, 2015

TABLE 6.5-9 INPUT PARAMETERS FOR THE SPRAY REMOVAL ANALYSIS Containment (excluding drywell) net free volume, ft3 1.1654 x 106 Sprayed containment volume, F3 481174 Unsprayed containment volume, F3 684226 Mean spray fall height, ft 54.05 Number of spray pumps operating 1 Spray flow rate, gpm 5,250 Spray solution pH 7.0 Q, Spray Flux, cfm/ft2 0.0621 Alpha, unsprayed/sprayed volume 1.422 Pct, uncertainty percentile 10 Revision 19 6.5-56 October, 2015

DELETED Revision 12 6.5-57 January, 2003 TABLE 6.5-11 ELEMENTAL IODINE DEPOSITION REMOVAL FACTORS Removal Volume Wall Area Factor (ft3) (ft2) (hr-1) Drywell 276,500 15,000 0.878 Sprayed Containment 481,174 29,000 0.975 Unsprayed Containment 684,226 61,000 1.443 Revision 19 6.5-58 October, 2015 6.6 INSERVICE INSPECTION OF CLASS 2 AND 3 COMPONENTS 6.6.1 COMPONENTS SUBJECT TO EXAMINATION All Quality Group B and Quality Group C components will be examined in accordance with Section XI of the ASME Code. The edition and addenda will be in accordance with <10 CFR 50.55a> as indicated in the Inservice Examination Program. The Inservice Examination Program covers Class 2 and 3 systems and components as described in Section XI. Exceptions for those portions of systems that cannot be examined to fully meet the requirements of Section XI, if any, are fully identified and the reasons for the exceptions given in the program. The program also defines a schedule for examinations. 6.6.2 ACCESSIBILITY The design and arrangement of Class 2 system components provide adequate clearances to conduct the required examinations at the code required inspection interval, and the design and arrangement of Class 3 system components also provides adequate clearances. 6.6.3 EXAMINATION TECHNIQUES AND PROCEDURES The Inservice Examination Program describes the scope of the examinations and includes isometric drawings and component sketches. The drawings show weld locations in the various piping systems and on components. Boundary diagrams and classification tables are incorporated into the program to delineate systems boundaries. The program specifies the type of examinations to be performed and the total extent of the examination coverage for each system component. Revision 12 6.6-1 January, 2003 Detailed procedures for volumetric (ultrasonic), surface penetrant and visual examinations are used in support of the program. Accompanying drawings include diagrams of calibration blocks and unique designations for each block to be used in the examination procedure. 6.6.4 INSPECTION INTERVALS An inspection schedule for Class 2 system components is developed in accordance with the guidance of Section XI, Subarticle IWC-2400, and a schedule for Class 3 system components is developed according to Subarticle IWD-2400. 6.6.5 EXAMINATION CATEGORIES AND REQUIREMENTS The inservice examination categories and requirements for Class 2 components are in agreement with Section XI, Subarticle IWC-2500. Inservice examination categories and requirements for Class 3 components are in agreement with Section XI, Subarticle IWD-2500. 6.6.6 EVALUATION OF EXAMINATION RESULTS The evaluation of Class 2 component examination results will comply with the requirements of Article IWC-3000 of Section XI. The method to be used in the evaluation of examination results for Class 3 components will comply with the requirements of Article IWD-3000 of Section XI. The repair procedures for Class 2 components will comply with the requirements of Article IWA-4000 of Section XI. The procedures to be used for repair of Class 3 components will be in agreement with Article IWA-4000 of Section XI. Revision 21 6.6-2 October, 2019 6.6.7 SYSTEM PRESSURE TESTS The program for Class 2 system pressure testing will comply with the criteria of Code Section XI, Article IWC-5000. The program for Class 3 system pressure tests will comply with the criteria of Article IWD-5000. 6.6.8 AUGMENTED INSERVICE INSPECTION TO PROTECT AGAINST POSTULATED PIPING FAILURES An Augmented Inservice Examination Program for high energy piping in containment penetration break exclusion regions <Section 3.6.2.1.7> is included in the Inservice Examination Program. It follows the same general outline as the Inservice Examination Program and includes areas subject to examination, method of examination, and extent and frequency of examinations. Revision 12 6.6-3 January, 2003 6.7 MAIN STEAM LINE ISOLATION VALVE LEAKAGE CONTROL SYSTEM The main steam line isolation valve leakage control system (MSIVLCS) has been eliminated and is abandoned in place. Revision 12 6.7-1 January, 2003 6.8 SAFETY-RELATED INSTRUMENT AIR SYSTEM 6.8.1 DESIGN BASES The function of the safety-related instrument air system is to continuously supply clean, dry, oil-free air for the initial charge and recharging of the automatic depressurization system (ADS) safety relief valveaccumulators when the depressurization function of the safety relief valves is used. The B Train safety-related instrument air system also provides postaccident makeup to the outboard MSIV air accumulators. Air receiver tanks are sized by volume to provide a sufficient quantity of air for recharging the ADSaccumulators, outboard MSIVaccumulators and the low-low set relief valve accumulator under accident conditions. In addition, the tanks contain a sufficient volume of air to provide makeup for system leakage for a period of seven days after an accident occurs. After this initial seven-day period, the system can be recharged with the air compressors or commercially available compressed air bottles, thus assuring the required 100 days of operation of the ADS valves and a continued pneumatic source for the outboard MSIVs. As long as the ADS valves remain open the reactor will not repressurize and low pressure ECCS pumps will be able to maintain cooling flow to the reactor. 6.8.2 SYSTEM DESIGN The safety-related instrument air system is shown on <Figure 6.8-1>. The system is designed to provide clean, dry air continuously at 160 to 170 psig to the ADS and low-low set relief valve accumulators and at an approximate setting of 85 psig (45 psig minimum) for the outboard MSIVaccumulators. The system stores air at 160 to 170 psig in receiver tanks downstream of the purifier package. Revision 12 6.8-1 January, 2003 One reciprocating type air compressor and air dryer is provided. The compressor supplies nominal 21.3 scfm and is automatically operated by a pressure switch on the compressor. The compressor automatically starts and stops to maintain a tank pressure of approximately 160 to 170 psig. The compressor unloads automatically after it shuts off. The system has a connection for recharging the receiver tanks or safety relief valveaccumulators directly to supplement compressor recharging in emergency and normal situations when the compressor is out-of-service. One large, low pressure air receiver tank is provided for safety-related air storage in each of two supply lines for the ADS and low-low set relief valve accumulators. The B Train safety-related instrument air system also provides post-accident makeup to the outboard MSIV air accumulators. Two small air receiver tanks are also provided in each supply line to supply nonsafety air storage to minimize compressor cycling. The six tanks are of welded steel construction and are designed in accordance with ASME Section III, Division 1, of the Boiler and Pressure Vessel Code. However, only the large air receiver tanks are designated as Safety Class 3; the small air receiver tanks are designated as Nonsafety Class. Revision 19 6.8-2 October, 2015 Air receiver tank pressure in the large air receiver tanks is sensed and transmitted to the control room. An alarm is sounded in the control room if the receiver tank pressure in the large air receiver tanks decreases to 155 psig. Each large tank is of the vertical, cylindrical type, measuring 10 feet in diameter and 24 feet in height. The smaller tanks are 18 inches in diameter and six feet in height. The tanks are equipped with relief and drain valves. The relief valves are set to relieve at 180 psig for the larger tank and 2,750 psig for the smaller tanks. Motor-operated containment and drywell isolation valves are also provided for the safety-related instrument air system. 6.8.3 DESIGN EVALUATION The air system is Safety Class 2 and 3, except for the section upstream of the dual isolation check valves which are upstream of the large safety-related air receiver tanks; this section is nonsafety <Figure 6.8-1>. The system has one compressor for supplying air to the air receiver tanks, which in turn supply air to the ADS, outboard MSIVs and low-low set relief valve accumulators. Physically separate air lines are employed to distribute air at 160 to 170 psig to ADS and low-low set relief valve accumulators and at an approximate setting of 85 psig (45 psig minimum) for the outboard MSIVAccumulators. Each of the two physically separate air lines supplies eight ADS valve accumulators. The A Train air storage tank also supplies the low-low set relief valve accumulator. The B Train also supplies the outboard MSIVaccumulators. Check valves are provided Revision 19 6.8-3 October, 2015 between each divisions large safety-related receiver tank and the compressor to assure no backflow from the receiver tanks to the compressor. The storage capacity (1,350 cubic feet water volume) for each divisions safety-related receiver tank is based on the requirements established by the General Electric Company for the operation of the safety relief valves as well as sufficient storage capacity to allow for leakage from ADS/SRV valves and the outboard MSIVs over seven days. This capacity is based on a minimum tank pressure of 150 psig. The selection of piping and valves in the safety-related Class 2 and 3 portion of the system is based on a design pressure of 200 psig. Relief valves are provided on the air receiver tanks to ensure that the system does not exceed the design pressure. The valves are set to relieve at 180 psig. The design pressure for portions of the system not protected by a relief valve has been increased to 210 psig to address thermal overpressure concerns. A relief valve set at 150 psig is installed downstream of pressure regulator 1P57-F002B. 6.8.4 TESTS AND INSPECTIONS Operator action during normal operation consists of periodically checking that system pressure is maintained within the correct range, and servicing the compressor and air dryer as necessary. This includes checking the compressor and air dryer visual indicators which signal when filter replacement is necessary. When the alarm in the control room indicates low receiver tank pressure, the air compressor is manually operated and runs until the system pressure is returned to the operating range. Scheduled checks will be made to assure that the air receiver tanks have retained their pressure integrity. Revision 16 6.8-4 October, 2009 A scheduled program of testing and inspection will be maintained to ensure that all system components and their control systems are in good working condition. Air quality will be tested on a yearly basis downstream of the air dryer for dewpoint and particulate contamination. The required air quality to safety-related components supplied from this system is: zero particulates larger than 40 microns and a dewpoint less than 0F for ADS valves and MSIVs. All instrumentation, control and alarm devices will be tested and calibrated at regular intervals. Manufacturer recommendations will be observed for inspection, and preventive and inservice maintenance. 6.8.5 INSTRUMENTATION REQUIREMENTS Instrumentation provided on the compressor control panel includes a high air temperature switch, and a discharge pressure switch. Revision 17 6.8-5 October, 2011 Pressure indication is provided locally and in the control room. An alarm is sounded in the control room when the safety-related receiver tank pressure decreases to 155 psig. Manual switches with status lights are provided in the control room for closing motor-operated containment and drywell isolation valves if a LOCA condition occurs. No automatic closure signal is provided. Relief valves are provided upstream of the double check valves on the air receiver tanks and downstream of the MSIV source line pressure regulator to ensure that the system does not exceed the design pressure of each section of the system. Revision 12 6.8-6 January, 2003 6.9 FEEDWATER LEAKAGE CONTROL SYSTEM 6.9.1 DESIGN BASES
a. The feedwater leakage control system (FWLC) is designed in accordance with Seismic Category I and quality group classification requirements to comply with <Regulatory Guide 1.26> and <Regulatory Guide 1.29>. The system meets the intent of <Regulatory Guide 1.96>, where applicable
.
b. The FWLC system is designed with sufficient redundancy, separation, reliability, and capacity as a safety-related system consistent with the need to maintain containment integrity for as long as postulated LOCA conditions require.
c. The FWLC system is capable of performing its intended safety function following a loss of all offsite power coincident with the postulated design basis LOCA.
d. The FWLC system is designed with sufficient capacity and capability to prevent leakage through the feedwater lines consistent with containment integrity under the conditions associated with the postulated design basis LOCA.
e. The FWLC system is provided with interlocks actuated from appropriately designed safety systems or circuits to prevent inadvertent system operation.
f. The FWLC system is designed to permit testing of the operability of controls and actuating devices as well as the complete functioning of the system during plant shutdowns.
Revision 12 6.9-1 January, 2003
g. The FWLC system is designed so that effects resulting from a system single active component failure will not affect the integrity of the feedwater lines or the operability of containment isolation valves.
h. The FWLC system is protected from the effects of internally generated missiles, pipe break failures and adverse environments associated with a LOCA.
i. The normal power supply to the feedwater penetration motor-operated gate valves is from Division 1. The licensing basis for the feedwater penetrations is that the gate valves are successfully closed by the control room operator. Power is also available to these gate valves from Division 3 (alternate power source connected per plant procedures). This improves the reliability of the penetration in the event of a total loss of both the normal and emergency AC power from Division 1. Physical and electrical separation between Division 1 and Division 3 will be maintained during normal operation by employing two features:
1. Normally open, fused disconnect switches at both ends of the circuit, and
2. Fuses normally stored out of the circuit.
6.9.2 SYSTEM DESCRIPTION The FWLC consists of piping, valves and instrumentation as shown in <Figure 6.9-1>. The system components are designed to the requirements of
, Item XLIX. The FWLC system consists of two subsystems designed to eliminate through-line leakage in the feedwater piping by providing a positive seal for the stem, bonnet and seat of the outboard isolation valve on Revision 12 6.9-2 January, 2003 each line. The Division 2 subsystem uses the residual heat removal (RHR) waterleg pump and the Division 1 subsystem uses the low pressure core spray (LPCS) waterleg pump to supply sealing water through the bonnets of the MOVs. Following closure of the MOVs, the sealing water seals the stems, bonnets and seats, and isolates the feedwater lines. Following a LOCA, the FWLC system is manually initiated from the control room. The operator first verifies feedwater unavailability through low feedwater pressure (approximately 30 psig), then closes the outboard containment isolation (motor-operated gate) valves with the keylock switches, and opens one of the motor-operated FWLC system valves from the control room. The suppression pool sealing water from one of the waterleg pumps (or both if they are available) is routed to both MOVs. Since the source of sealing water is the suppression pool, a 30-day water supply is ensured. Operation of the FWLC system will not affect the function of the suppression pool since the allowed valve leakage outside of the containment is very small, and inleakage to containment would eventually return to the pool when the drywell is flooded back over the weir wall. When the FWLC system is initiated manually following a LOCA, there should be no demand for keep-fill water in the RHR and LPCS systems since these systems will be operating. Therefore, the waterleg pump should be totally dedicated to provide sealing water to the FWLC system. A single waterleg pump has the capacity to provide the necessary sealing water to the FWLC system. The feedwater system will not be completely drained since the system will be intact and operating initially post-LOCA. The feedwater design includes a backup flow path through a motor driven pump. When the turbine driven feed pumps lose driving steam and trip on Revision 12 6.9-3 January, 2003 vessel Level 2 post-LOCA, flow is automatically diverted through the motor driven pump. The motor driven feed pump and/or the feedwater booster pumps will continue to pump water into containment post-LOCA. The pumps will continue to operate for about 10 minutes before the feedwater booster pumps trip on low water level. During this time, no extraction heating is available and cold water from the condenser hotwell is being pumped into the vessel which cools down the feedwater and the piping. When feedwater flow is finally stopped, feedwater flashing is not expected to occur. Therefore, a significant voiding of the piping is not expected. In the case where the feedwater lines do not remain completely water filled, the feedwater system can be operated to ensure positive pressurization up to the motor-operated gate valve, and thus leakage is into the reactor vessel (or drywell if the LOCA is a feedwater line break inside the drywell). The FWLC system will be initiated and begin to fill the volume in the bonnet and seat of the motor-operated gate valve. When the volumes fill up, the pressure will increase and the water seal will be established. If a divisional failure is assumed, the redundant waterleg pump would still be available for providing a water seal on the feedwater line. Under these conditions, calculations show it would take less than 9 minutes to fill and maintain a feedwater water seal. Based on the conservative assumptions listed above, the FWLC system will provide an adequate seal within approximately one hour following a LOCA. If a loss of offsite power is assumed at this time, one or both of the FWLC subsystems will maintain the volume of water on the stem, bonnet and seat of the outboard motor-operated gate valves, thus maintaining the feedwater line isolation. During this first hour, operation of the feedwater system will maintain a system pressure higher than the drywell pressure, thus ensuring water leakage into the vessel. Revision 12 6.9-4 January, 2003 In the event that the feedwater system becomes inoperable during the rapid vessel depressurization following a LOCA, the water in the feedwater piping will begin to flash into the drywell. It is expected that a water seal would remain for a sufficient length of time following the accident until the operator remotely isolates the motor-operated valve. Thus, a water seal would exist in the piping beyond (outboard) of the motor-operated valve. Initiation of the FWLCS to the bonnet, stem and seats of the motor-operated valve will then provide the water seal for the remainder of the 30 days. 6.9.3 DESIGN EVALUATION The FWLC system is designed to prevent the release of radioactivity through the feedwater line isolation valves by providing a supplemental water seal following a loss of all offsite power coincident with the postulated design basis loss-of-coolant accident. The two redundant subsystems are physically separated to the maximum amount practical in order to minimize the exposure of the system components to missiles and to the effects of pipe whip or jet impingement from high energy line breaks. The common piping segments are physically protected from these postulated effects. The FWLC system is Seismic Category I and is capable of performing its intended function following an active component failure. Each subsystem is powered from a different division of the ESF power supply. The possibility of a single active failure of one of the feedwater system motor-operated valves (which are a part of the feedwater system rather than the Feedwater Leakage Control System) is addressed in
. Double series isolation valves are provided in the FWLCS supply lines to ensure that no single active failure will affect the integrity of the feedwater lines. Revision 12 6.9-5 January, 2003 Non-seismic systems and components in the area of the FWLC system have been analyzed for the effects of their failure. Additional supports or protection by barriers is provided to assure the FWLC system is not jeopardized by non-seismic failures during an earthquake. A single failure analysis of the FWLC system is contained in
. 6.9.4 TESTS AND INSPECTIONS The FWLC system is hydrostatically tested prior to startup. The complete functioning of the system, including operability of controls and actuating devices, can be tested during periods of plant shutdown, but in no case at intervals greater than two years. 6.9.5 INSTRUMENTATION REQUIREMENTS Each FWLC subsystem is manually initiated from the control room following a postulated LOCA. Independent pressure instrumentation is provided for each FWLC subsystem in order to prevent operation while the feedwater lines are pressurized. Division 1 of the FWLC system is interlocked to preclude initiation unless the motor-operated shutoff valves are closed. The operation of Division 2 is controlled by plant procedures/instructions. Revision 12 6.9-6 January, 2003 TABLE 6.9-1 SINGLE FAILURE ANALYSIS OF FEEDWATER LEAKAGE CONTROL SYSTEM COMPONENT/EQUIPMENT MALFUNCTION CONSEQUENCES RHR waterleg pump Either pump fails to One subsystem is LPCS waterleg pump operate inoperative. System requirements met by redundant pump and associated subsystem. Motor-operated valve on Either valve fails to One subsystem is either waterleg pump open inoperative. System discharge line requirements met by redundant subsystem. Division 1 AC Total loss of both the Division 3 electrical electrical power normal and emergency power is made avail-Division 1 AC able to the feedwater electrical power system motor-operated sources gate valves by manual operator action per plant procedure. The Division 2 FWLC subsystem is then utilized to provide the water seal on the MOV. Feedwater shutoff Feedwater shutoff valve The Feedwater Leakage valve fails to close Control System is vulnerable to this extremely unlikely event. However, the licensing basis for the feedwater penetrations is that a water seal in the feedwater piping outboard of the shutoff valves would remain for a sufficient length of time following the accident until the control room operator successfully isolates the motor-operated valves. Therefore, Revision 12 6.9-7 January, 2003 TABLE 6.9-1 (Continued) COMPONENT/EQUIPMENT MALFUNCTION CONSEQUENCES these valves are assumed to work. Also, each feedwater line contains two check valves which are classified as containment isolation valves on this penetration, and they provide a redundant containment isolation function. The proper closure of the check valves is verified per the Inservice Testing Program. Revision 12 6.9-8 January, 2003
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