ML14010A301

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Final Safety Analysis Report, Amendment 62, Chapter 6 - Engineered Safety Features
ML14010A301
Person / Time
Site: Columbia Energy Northwest icon.png
Issue date: 12/30/2013
From:
Energy Northwest
To:
Office of Nuclear Reactor Regulation
Shared Package
ML14010A476 List:
References
GO2-13-174
Download: ML14010A301 (295)
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Text

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 6

ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS

Section Page LDCN-05-009,06-064 6-i 6.1 ENGINEERED SAFETY FEATURE MATERIALS................................6.1-2

6.1.1 METALLIC

MATERIALS............................................................6.1-2 6.1.1.1 Materials Se lection and Fabrication................................................6.1-2 6.1.1.1.1 Material Specifications.............................................................6.

1-2 6.1.1.1.2 Compatibility of Construction Materials with Core Cooling Water and Containment Sprays.................................................................

6.1-2 6.1.1.1.3 Controls for Austenitic Stainless Steel..........................................

6.1-2 6.1.1.2 Composition, Compatibility, and Stability of Containment and Core Spray Coolants..................................................................6.1-3

6.1.2 ORGANIC

MATERIALS..............................................................6.1-4

6.1.3 POSTACCIDENT

CHEMISTRY.....................................................6.1-5

6.2 CONTAINMENT

SYSTEMS............................................................6.2-1

6.2.1 CONTAINMENT

F UNCTIONAL DESIGN.......................................6.2-1 6.2.1.1 Pressure Suppression Containment.................................................6.2-1 6.2.1.1.1 Design Basis.........................................................................6.2-1 6.2.1.1.2 Design Features.....................................................................6.2-2 6.2.1.1.3 Design Evaluation..................................................................6.2-5 6.2.1.1.3.1 Su mmary Evaluation.............................................................6.2-5 6.2.1.1.3.2 Contai nment Design Parameters...............................................6.2-5 6.2.1.1.3.3 Accide nt Response Analysis....................................................6.2-6 6.2.1.1.3.3.1 Recirc ulation Line Rupture..................................................6.2-6 6.2.1.1.3.3.1.1 Assumptions for Reactor Blowdown.....................................6.2-7 6.2.1.1.3.3.1.2 Assumptions for Containment Pressurization..........................6.2-9 6.2.1.1.3.3.1.3 Assumpti ons for Long-Term Cooling....................................6.2-9 6.2.1.1.3.3.1.4 Initial Conditions for Accident Analyses................................6.2-10 6.2.1.1.3.3.1.5 Short-Term Accident Response...........................................6.2-10 6.2.1.1.3.3.1.6 Long-Term Accident Responses..........................................6.2-11 6.2.1.1.3.3.1.7 Chrono logy of Accident Events...........................................6.2-13 6.2.1.1.3.3.2 Main Steam Line Break.......................................................6.2-13 6.2.1.1.3.3.3 Hot St andby Accident Analysis.............................................6.2-15 6.2.1.1.3.3.4 Intermediate Size Breaks.....................................................6.2-15 6.2.1.1.3.3.5 Small Size Breaks..............................................................6.2-16 6.2.1.1.3.3.5.1 Reactor System Blowdown Consideration..............................6.2-16 6.2.1.1.3.3.5.2 Containment Response.....................................................6.2-16 6.2.1.1.3.3.5.3 R ecovery Operations........................................................6.2-17 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 6

ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-05-009 6-ii 6.2.1.1.3.3.5.4 Drywell Design Temperature Consideration...........................6.2-17 6.2.1.1.3.4 Accide nt Analysis Models......................................................6.2-17 6.2.1.1.3.4.1 Short-Te rm Pressurization Model...........................................6.2-17 6.2.1.1.3.4.2 L ong-Term Cooling Mode...................................................6.2-17 6.2.1.1.3.4.3 Analytical Assumptions.......................................................6.2-18 6.2.1.1.3.4.4 Energy Balance Consideration...............................................6.2-18 6.2.1.1.4 Negative Pressure Design Evaluation...........................................

6.2-18 6.2.1.1.5 Suppression P ool Bypass Effects.................................................6.2-20 6.2.1.1.5.1 Protecti on Against Bypass Paths...............................................6.2-20 6.2.1.1.5.2 Reactor Blowdown Conditions and Operator Response...................6.2-20 6.2.1.1.5.3 Anal ytical Assumptions.........................................................6.2-21 6.2.1.1.5.4 An alytical Results................................................................6.2-21 6.2.1.1.6 Suppression Pool Dynamic Loads...............................................6.2-22 6.2.1.1.7 Asymmetric Loading Conditions.................................................

6.2-22 6.2.1.1.8 Primary Containmen t Environmental Control.................................6.2-22 6.2.1.1.8.1 Temperature, Humidity, and Pressure Control During Reactor Operation...........................................................................6.2-22 6.2.1.1.8.2 Primary Containment Purging.................................................6.2-23 6.2.1.1.8.3 Post-LOCA........................................................................6.

2-25 6.2.1.1.9 Postaccident Monitoring...........................................................6.2-25 6.2.1.2 Containment Subcompartments.....................................................6.2-25 6.2.1.3 Mass and Energy Release Anal yses for Postulated Loss-of-Coolant Accidents................................................................................6.2-29 6.2.1.3.1 Mass and En ergy Release Data...................................................

6.2-29 6.2.1.3.2 Ener gy Sources......................................................................6.

2-30 6.2.1.3.3 Reactor Blowdown and Co re Reflood Model Description...................6.2-30 6.2.1.3.4 Effects of Metal-Water Reaction.................................................6.2-31 6.2.1.3.5 Thermal Hydraulic Data for Reactor Analysis.................................6.2-31 6.2.1.3.6 Long Term Cooli ng Model Description........................................

6.2-31 6.2.1.3.7 Single Failure Analysis............................................................6.2-31 6.2.1.4 Not Applicable to BWR Plants......................................................6.2-31 6.2.1.5 Not Applicable to BWR Plants......................................................6.2-31 6.2.1.6 Testing and Inspection................................................................6.2-31 6.2.1.6.1 Structural Integrity Test...........................................................6.2-31 6.2.1.6.2 Integrated Leak Rate Test.........................................................

6.2-31 6.2.1.6.3 Drywell Bypass Leak Test........................................................6.2-31 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 6

ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-05-009,06-064 6-iii 6.2.1.6.4 Vacuum Relief Testing.............................................................6.2-32 6.2.1.7 Require d Instrumentation............................................................6.2-32

6.2.2 RESIDUAL

HEAT REMOVAL CONTAINMENT HEAT REMOVAL SYSTEM..................................................................................

6.2-32 6.2.2.1 Design Bases...........................................................................6.2-32 6.2.2.2 Residual Heat Removal Containment Cooling System Design................6.2-33 6.2.2.3 Design Evaluation of the Containment Cooling System........................6.2-34 6.2.2.4 Tests and Inspections.................................................................6.2-36 6.2.2.5 Instrumentation Requirements.......................................................6.2-36

6.2.3 SECONDARY

CONTAINM ENT FUNCTIONAL DESIGN...................6.2-36 6.2.3.1 Design Bases...........................................................................6.2-36 6.2.3.2 System Design.........................................................................6.2-38 6.2.3.3 Design Evaluation.....................................................................6.

2-41 6.2.3.3.1 Calculation Model..................................................................6.2-41 6.2.3.3.2 Results................................................................................

6.2-42 6.2.3.4 Tests and Inspections.................................................................6.2-42 6.2.3.5 Instrumentation Requirements.......................................................6.2-43

6.2.4 CONTAINMENT

IS OLATION SYSTEM..........................................6.2-43 6.2.4.1 Design Bases...........................................................................6.2-43 6.2.4.2 System Design.........................................................................6.2-45 6.2.4.3 Design Evaluation.....................................................................6.

2-46 6.2.4.3.1 Intr oduction..........................................................................6.2-46 6.2.4.3.2 Evaluati on Against General De sign Criteria...................................6.2-46 6.2.4.3.2.1 Evaluatio n Against Criterion 55...............................................6.2-46 6.2.4.3.2.1.1 Influent Lines...................................................................6.

2-47 6.2.4.3.2.1.1.1 Feedwater Lines.............................................................6.2-47 6.2.4.3.2.1.1.2 High-Pr essure Core Spray Line...........................................6.2-48 6.2.4.3.2.1.1.3 Low-Pressure Coolant Injection Lines...................................6.2-48 6.2.4.3.2.1.1.4 Control Rod Drive Lines...................................................6.2-48 6.2.4.3.2.1.1.5 Residual Heat Removal and Reactor Core Isolation Cooling Head Spray Lines............................................................6.2-49 6.2.4.3.2.1.1.6 Standby Liquid Control System Lines...................................6.2-49 6.2.4.3.2.1.1.7 Reactor Water Cleanup System...........................................6.2-49 6.2.4.3.2.1.1.8 Recirculati on Pump Seal Water Supply Line...........................6.2-50 6.2.4.3.2.1.1.9 Low-Pr essure Core Spray Line...........................................6.2-50 6.2.4.3.2.1.1.10 Residual Heat Removal Shutdo wn Cooling Return Lines..........6.2-50 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 6

ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-05-009,06-039, 06-064 6-iv 6.2.4.3.2.1.2 Effluent Lines..................................................................6.2-50 6.2.4.3.2.1.2.1 Main Steam, Main Steam Drain Lines, and Residual Heat Removal/Reactor Core Isolation Cooling Steam Supply Lines......6.2-50 6.2.4.3.2.1.2.2 Recircul ation System Sample Lines......................................6.2-51 6.2.4.3.2.1.2.3 Reactor Water Cleanup System...........................................6.2-51 6.2.4.3.2.1.2.4 Residual Heat Removal Shutdo wn Cooling Line......................6.2-51 6.2.4.3.2.1.3 Conc lusion on Criterion 55..................................................6.2-51 6.2.4.3.2.2 Evaluatio n Against Criterion 56...............................................6.2-52 6.2.4.3.2.2.1 Influent Lines to Suppression Pool.........................................6.2-52 6.2.4.3.2.2.1.1 Low-Pressure Core Spray, High-Pr essure Core Spray, and Residual Heat Removal Test and Minimum Flow Bypass Lines....6.2-52 6.2.4.3.2.2.1.2 Reactor Core Isolati on Cooling Turbine Exhaust, Vacuum Pump Discharge, and RCIC Pump Minimum Flow Bypass Lines..........6.2-53 6.2.4.3.2.2.1.3 Residual Heat Removal Heat Exchanger Vent Lines.................6.2-53 6.2.4.3.2.2.1.4 Low-Pressure Core Spray, High-Pr essure Core Spray, and Residual Heat Removal Relie f Valve Discharge Lines...............6.2-53 6.2.4.3.2.2.1.5 Fuel Pool Cooling and Clea nup Return Lines..........................6.2-54 6.2.4.3.2.2.1.6 Deactivated Residu al Heat Removal Steam Condensing Mode Steam Line Relief and Drain Lines.......................................6.2-54 6.2.4.3.2.2.1.7 Process Sampling Suppression Pool Sample Return Line............6.2-54 6.2.4.3.2.2.2 Effluent Lines From Suppression Pool.....................................6.2-54 6.2.4.3.2.2.2.1 High-Pre ssure Core Spray, Low-Pre ssure Core Spray, Reactor Core Isolation Cooling, and Resi dual Heat Removal Suction Lines 6.2-54 6.2.4.3.2.2.2.2 Fuel Pool Cooling Suction Line..........................................6.2-54 6.2.4.3.2.2.2.3 PSR S uppression Pool Sample Line......................................6.2-55 6.2.4.3.2.2.3 Influent and Effluent Lines From Drywell and Suppression Chamber Free Volume....................................................................6.

2-55 6.2.4.3.2.2.3.1 Containment Atmosphere Control Lines (Deactivated)...............6.2-55 6.2.4.3.2.2.3.2 Containment Purge S upply, Exhaust, and Inerting Makeup Lines.6.2-55 6.2.4.3.2.2.3.3 Drywell and Suppression Cham ber Air Sampling Lines.............6.2-56 6.2.4.3.2.2.3.4 Suppression Chamber Spray Lines.......................................6.2-56 6.2.4.3.2.2.3.5 Reactor Buildi ng to Wetwell Vacuum Relief Lines...................6.2-56 6.2.4.3.2.2.3.6 Drywell Spray Lines........................................................6.2-56 6.2.4.3.2.2.3.7 Reactor Closed Co oling Water Supply and Return Lines............6.2-56 6.2.4.3.2.2.3.8 Air Supply Lines............................................................6.2-57 6.2.4.3.2.2.3.8.1 Check Valve Air Supply Lines.........................................6.2-57 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 6

ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-05-009,06-039, 06-064 6-v 6.2.4.3.2.2.3.8.2 Primary Containment Instrument Air System Nitrogen Supply Lines...............................................................6.2-57 6.2.4.3.2.2.3.8.3 Service Air System Maintenan ce Supply Line to the Drywell....6.2-57 6.2.4.3.2.2.3.9 Demineralized Water Maintenan ce Supply Line to the Drywell....6.2-57 6.2.4.3.2.2.3.10 Drywell Equipment and Floor Drain Lines...........................6.2-57 6.2.4.3.2.2.3.11 Traversing In-Core Probe (TIP) System Guide Tubes..............6.2-57 6.2.4.3.2.2.4 Conc lusion on Criterion 56..................................................6.2-58 6.2.4.3.2.3 Evaluatio n Against Criterion 57...............................................6.2-58 6.2.4.3.2.4 Evalua tion Against Regulatory Guide 1.11, Revision 0...................6.2-58 6.2.4.3.3 Failure Mode and Effects Analyses..............................................

6.2-59 6.2.4.3.4 Operat or Actions....................................................................6.

2-59 6.2.4.4 Tests and Inspections.................................................................6.2-60

6.2.5 COMBUSTIBLE

GAS CONT ROL IN CONTAINMENT.......................

6.2-60 6.2.5.1 Design Bases...........................................................................6.2-61 6.2.5.2 System Design.........................................................................6.2-61 6.2.5.2.1 Atmosphere Mixing System.......................................................6.2-61 6.2.5.2.2 Hydrogen and Oxygen Concentration M onitoring System..................6.2-62 6.2.5.2.3 Contai nment Purge.................................................................6.2-62 6.2.5.3 Design Evaluation.....................................................................6.

2-63 6.2.5.3.1 Hydrogen and Oxygen Generation...............................................6.2-63 6.2.5.4 Testing and Inspections...............................................................6.2-63 6.2.5.5 Instrumentation Requirements.......................................................6.2-64 6.2.5.6 Materials................................................................................6.2-64 6.2.5.7 Containment Nitrogen Inerting System............................................6.2-64

6.2.6 CONTAINMENT

LEAKAGE TESTING...........................................6.2-64 6.2.6.1 Containment Leakage Rate Tests...................................................6.2-64 6.2.6.2 Special Testing Requirements.......................................................6.2-65 6.

2.7 REFERENCES

...........................................................................

6.2-65

6.3 EMERGENCY

CORE COOLING SYSTEM.........................................6.3-1

6.3.1 DESIGN

BASES AND

SUMMARY

DESCRIPTION............................6.3-1 6.3.1.1 Design Bases...........................................................................6.3-1 6.3.1.1.1 Performance and Functional Requirements....................................6.3-1 6.3.1.1.2 Reliability Requirements...........................................................6.3-2 6.3.1.1.3 Emergency Co re Cooling System Require ments for Protection from Physical Damage....................................................................

6.3-4 C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-08-035 6-vi 6.3.1.1.4 Emergency Core Cooling System Environmental Design Basis............6.3-4 6.3.1.2 Summary Descriptions of Emergency Core Cooling System..................6.3-5 6.3.1.2.1 High-Pressu re Core Spray.........................................................6.3-5 6.3.1.2.2 Low-Pressu re Core Spray.........................................................6.3-5 6.3.1.2.3 Low-Pressure Coolant Injection..................................................6.3-5 6.3.1.2.4 Auto matic Depressuriza tion System.............................................6.3-6

6.3.2 SYSTEM

DESIGN......................................................................6.3-6 6.3.2.1 Schematic Piping and Instru mentation Diagrams................................6.3-6 6.3.2.2 Equipment and Component Descriptions..........................................6.3-6 6.3.2.2.1 High-Pressure Core Spray System...............................................6.3-6 6.3.2.2.2 Auto matic Depressuriza tion System.............................................6.3-9 6.3.2.2.3 Low-Pressure Core Spray System...............................................6.3-9 6.3.2.2.4 Low-Pressure C oolant Injection System........................................

6.3-11 6.3.2.2.5 Emergency Core Cooling System Discharge Line Fill System.............6.3-14 6.3.2.2.6 Emergency Core Cooli ng System Suction Strainers..........................6.3-14 6.3.2.3 Applicable Codes and Classifications..............................................6.3-18 6.3.2.4 Materials Specifications and Compatibility.......................................6.3-18 6.3.2.5 System Reliability.....................................................................6.

3-18 6.3.2.6 Protection Provisions.................................................................6.3-19 6.3.2.7 Provisions for Performance Testing................................................6.3-19 6.3.2.8 Manual Actions........................................................................6.

3-20 6.3.3 EMERGENCY CORE COOLING SYSTEM PERFORMANCE EVALUATION..........................................................................6.3-20 6.3.3.1 Emergency Core Cooling System Bases for Technical Specifications.......6.3-21 6.3.3.2 Acceptance Criteria for Emergency Core Cooling System Performance....6.3-21 6.3.3.3 Single Failure Considerations.......................................................6.3-22 6.3.3.4 System Performance During the Accident........................................6.3-23 6.3.3.5 Use of Dual Function Components for Emer gency Core Cooling System..6.3-24 6.3.3.6 Emergency Core Cooling System Analyses for Loss-of-Coolant Accident.6.3-24 6.3.3.6.1 Loss-of-Coolant Ac cident Description..........................................

6.3-25 6.3.3.6.2 Loss-of-Coolant Accident Analysis Procedures and Input Variables......6.3-26 6.3.3.6.2.1 LOCA Analysis Methodology, GE Hitachi Nuclear Energy.............6.3-26 6.3.3.6.2.2 LOCA Analysis Methodology, AREVA NP................................6.3-27 6.3.3.6.2.3 LOCA An alysis Input Variables...............................................6.3-28 6.3.3.7 Break Spectrum Calculations........................................................6.

3-28 6.3.3.7.1 Break Spectrum Calculati on, GE Hitachi Nucl ear Energy..................6.3-29 C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-08-035 6-vii 6.3.3.7.2 Break Spectrum Ca lculation, AREVA NP.....................................

6.3-29 6.3.3.8 Loss-of-Coolant A ccident Analysis Conclusions.................................6.3-30 6.3.3.8.1 Loss-of-Coolant Acci dent Analysis Conclusions, GE Hitachi Nuclear Energy.......................................................6.3-30 6.3.3.8.2 Loss-of-Coolant Accident Analysis Conclusions, AREVA NP.............6.3-30

6.3.4 TESTS

AND INSPECTIONS.........................................................6.3-31 6.3.4.1 Emergency Core Cooling System Performance Tests..........................6.3-31 6.3.4.2 Reliability Tests and Inspections....................................................6.3-31 6.3.4.2.1 High-Pressure Core Spray Testing...............................................

6.3-31 6.3.4.2.2 Automatic Depressu rization System Testing...................................6.3-32 6.3.4.2.3 Low-Pressure Core Spray Testing...............................................

6.3-32 6.3.4.2.4 Low-Pressure Cool ant Injection Testing........................................

6.3-32 6.3.5 INSTRUMENTATIO N REQUIREMENTS........................................6.3-33 6.

3.6 REFERENCES

...........................................................................

6.3-33

6.4 HABITABILITY

SYSTEMS.............................................................6.4-1

6.4.1 DESIGN

BASIS..........................................................................6.4-1

6.4.2 SYSTEM

DESIGN......................................................................6.4-2 6.4.2.1 Definition of Main Control Room Envelope.....................................6.4-2 6.4.2.2 Ventilation System Design...........................................................6.4-2 6.4.2.3 Leaktightness...........................................................................6.4-2 6.4.2.4 Interaction With Other Zo nes and Pressure Containing Equipment..........6.4-2 6.4.2.5 Shielding Design.......................................................................6.4-3 6.4.3 SYSTEM OPERA TIONAL PROCEDURES.......................................6.4-3

6.4.4 DESIGN

EVALUATION..............................................................6.4-4 6.4.4.1 Radiological Protection...............................................................6.4-4 6.4.4.2 Toxic Gas Protection.................................................................6.4-4 6.4.4.2.1 Chlorine..............................................................................

6.4-4 6.4.4.2.2 Sodi um Oxide.......................................................................6.4-5 6.4.4.2.3 Miscellaneous Chemicals..........................................................6.4-7

6.4.5 TESTING

AND INSPECTION.......................................................6.4-8

6.4.6 INSTRUMENTATIO

N REQUIREMENTS........................................6.4-9 6.

4.7 REFERENCES

...........................................................................

6.4-9 C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page 6-viii 6.5 FISSION PRODUCT RE MOVAL AND CONTROL SYSTEMS.................6.5-1

6.5.1 ENGINEERED

SAFETY FE ATURE FILTER SYSTEMS.....................6.5-1 6.5.1.1 Design Bases...........................................................................6.5-1 6.5.1.2 System Design.........................................................................6.5-1 6.5.1.3 Design Evaluation.....................................................................6.5-5 6.5.1.4 Tests and Inspections.................................................................6.5-5 6.5.1.5 Instrumentation Requirements.......................................................6.5-6 6.5.1.6 Materials................................................................................6.5-7

6.5.2 CONTAINMENT

SPRAY SYSTEM................................................6.5-7

6.5.3 FISSION

PRODUCT CONTROL SYSTEMS......................................6.5-8 6.5.3.1 Primary Containment.................................................................6.5-8 6.5.3.2 Secondary Containment..............................................................6.5-8 6.5.3.3 Standby Liquid C ontrol (SLC) System............................................6.5-8

6.6 INSERVICE

INSPECTION OF ASME CODE CLASS 2 AND CLASS 3 COMPONENTS............................................................................6.6-1

6.7 MAIN STEAM ISOLATION VALVE LEAKAGE CONTROL SYSTEM.....6.7-1

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 6

ENGINEERED SAFETY FEATURES

LIST OF TABLES

Number Title Page LDCN-05-009,06-039, 06-064 6-ix 6.1-1 Engineered Safety Features Systems and Related Systems Component Materials...........................................................

6.1-7 6.2-1 Containment Design Parameters.............................................6.

2-69 6.2-2 Engineered Safety Systems Information for Containment Response Analyses..............................................................6.2-70

6.2-3 Accident Assumptions and In itial Conditions for Recirculation Line Break.......................................................................6.

2-72 6.2-4 Initial Conditions Employed in Containment Response Analyses......6.2-73

6.2-5 Summary of Accident Results for Containment Response to Limiting Line Breaks...........................................................

6.2-75 6.2-6 Loss-of-Coolant Accident L ong-Term Primary Containment Response Summary.............................................................6.

2-76 6.2-7 Energy Balance for Design Ba sis Recirculation Line Break Accident..........................................................................6.2-77

6.2-8 Accident Chronol ogy Design Basis Recirc ulation Line Break Accident..........................................................................6.2-78

6.2-9a Reactor Blowdown Data for Recirculation Line Break - Original Rated Power..........................................................

6.2-79 6.2-9b Reactor Blowdown Data for Recirculation Line Break -

Uprated Power..................................................................6.2-80 6.2-10 Reactor Blowdown Data for Main Steam Line Break....................6.2-81

6.2-11 Core Decay Heat Following Loss-of-Coolant Accident for Containment Analyses..........................................................6.2-82

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF TABLES (Continued)

Number Title Page LDCN-08-028 6-x 6.2-12 Secondary Containment Desi gn and Performance Data .................. 6.2-83 6.2-13 DELETED (Rep laced by Table 6.2-16) 6.2-14 Containment Penetrations Subject to Type B Tests ....................... 6.2-84

6.2-15 DELETED

6.2-16 Primary Containment Isolation Valves ...................................... 6.2-85

6.2-17 Hydrogen Recombiner (DEACTIVATED)

................................. 6.2-110

6.2-18 DELETED

6.2-19 Assumptions and Initial C onditions For Negative Pressure Design Evaluati on............................................................... 6.2-111

6.2-19a Limiting Conditions for Maximum Negative Pressure Differentials Applied to Columbia Generating Station Specifications . 6.2-112

6.2-20 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 6-in. RCIC Line Steam

............................................. 6.2-113

6.2-21 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 6-in. RCIC Line Water

............................................. 6.2-114

6.2-22 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 24-in. Recirculation Line Steam .................................. 6.2-116

6.2-23 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 24-in. Recircula tion Line Water .................................. 6.2-117

6.2-24 Nodal Volume Data for the Case of a 6-in. RCIC Line Break and the Case of a 24-in. Recircula tion Line Break ................................. 6.2-118

6.2-25 Flow Path Data for the Case of a 6-in. RCIC Line Break ............... 6.2-119 C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF TABLES (Continued)

Number Title Page LDCN-08-028 6-xi 6.2-26 Flow Path Data for the Case of a 24-in. Recirculation Line Break .... 6.2-120

6.2-27 Peak Differential Pressure and Time of Peak .............................. 6.2-121

6.2-28 Analytical Sequence of Events in Secondary Containment .............. 6.2-122

6.2-29 DELETED

6.2-30 Post-LOCA Transient Heat Input Rates to Secondary Containment ... 6.2-123

6.3-1 Emergency Core Cooling System Design Parameters .................... 6.3-37

6.3-2 Loss-Of-Coolant Accident Analysis Initial Conditions and Input Parameters - ATRIUM-10 ............................................. 6.3-38

6.3-2a Plant Operational Parameters (GE14) ....................................... 6.3-41

6.3-2b GE14 Fuel Pa rameters ......................................................... 6.3-42

6.3-2c SAFER/GESTR-LOCA ECCS Parameters (GE14)

....................... 6.3-43

6.3-3 Single Failures Considered in the ECCS Performance Evaluation -

AREVA ...........................................................................

6.3-47 6.3-3a Single Failure Considered in ECCS Performance Evaluation Based on SAFER/GESTR-LOCA (GE14) .............................................. 6.3-48 6.3-4 Loss-Of-Coolant Accident Sequence of Events for Limiting Break (AREVA NP Analys is) ........................................................

6.3-49 6.3-4a Event Scenario for 100% DBA Recirculation Suc tion Line Break HPCS DG Failure (Appendi x K, GE14) ................................... 6.3-50

6.3-4b Event Scenario for 0.07 ft 2 Recirculation Suction Line Break HPCS DG Failure (Appendi x K, GE14) ................................... 6.3-51 C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF TABLES (Continued)

Number Title Page LDCN-08-035 6-xii 6.3-5 ECCS Performance Analysis Results........................................6.3-52

6.5-1 Standby Gas Treatment System Component Description Per Unit.....6.5-9

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES

Number Title 6-xiii 6.2-1 Typical 24 in. Downcome r Vent with Jet Deflector 6.2-2 Diagram of the Recirc ulation Line Break Location 6.2-3 Pressure Response for Recirculation Line Break (Initial Containment Pressure 2 psig) 6.2-4 Temperature Response for Recirculation Line Br eak (Initial Containment Pressure 2 psig) 6.2-5 Drywell Floor P Response for Recirculation Li ne Break (Initial Containment Pressure 2 psig) 6.2-6 Containment Vent System Flow Rate for Recirculation (Initial Containment Pressure 2 psig)

6.2-7 Containment Pressure Response Cases A, B, and C - Original Rated Power

6.2-8 Drywell Temperature Response Case s A, B, and C - Original Rated Power

6.2-9 Suppression Pool Temper ature Response, Long-Term Response - Original Rated Power 6.2-10 Containment Pressure Re sponse - Case C Uprated Power

6.2-11 Drywell Temperature Re sponse - Case C Uprated Power

6.2-12 Suppression Pool Temperature Response - Case C Uprated Power

6.2-13 Residual He at Removal Rate

6.2-14 Effective Blowdown Area Main Steam Line Break 6.2-15 Bounding Pressure Response - Main Steam Line Break - Original Rated Power

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xiv 6.2-16 Bounding Temperatur e Response - Main Steam Li ne Break Original Rated Power 6.2-17 Pressure Response - Reci rculation Line Break (0.1 ft

2) Original Rated Power

6.2-18 Temperature Response - R ecirculation Line Break (0.1 ft

2) Original Rated Power 6.2-19 Schematic of ECCS Loop

6.2-20 Allowable Leakage Capacity

6.2-21 Containment Transient for Maximum Allowable Bypass Capacity Ax= 0.050 6.2-22 Containment Transient for

=KA 0.0045 ft 2 6.2-23 Nodalization Scheme for Drywell

6.2-24 Venting Through Bulkhead Plate

6.2-25 Absolute Pressure in Upper Head Region and Lower Regi on from 6 in. RCIC Line Break

6.2-26 Absolute Pressure in Lower Re gion and Upper Head Region from 24 in.

Recirculation Line Break

6.2-27 Downward Pressure Differential Across Bulkhead Plate from 6 in. Line Break

6.2-28 Upward Pressure Differential Across Bulkhead Plate from 24 in. Recirculation Line Break

6.2-29 Recirculation Break Blowdown Flow Rates Liquid Flow - Short-Term Original Rated Power

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xv 6.2-30 Recirculation Break Blowdown Flow Rates Steam Flow - Short-Term Original Rated Power 6.2-31 Main Steam Line Break Blowdown Flow Rates

6.2-32 Suppression Pool Suction and Return Lines

6.2-33 Reactor Feedwater Line - Routing

6.2-34 Long-Term Post-LOCA Secondary Containment Temp erature Transient

6.2-35 Short-Term Post-LOCA Seconda ry Containment Pr essure Transient

6.2-36 Notes on Type C Testing

6.2-37 Isolation Valve Arra ngement for Penetrations X-53, X-66, X-17A, and X-17B

6.2-38 Isolation Valve Arra ngement for Penetrations X-89B, X-91, X-56, X-43A, and X-43B 6.2-39 Isolation Valve Arrangement for Penetrations X-117, X-118, and X-77Aa

6.2-40 Isolation Valve A rrangement for Penetrati ons X-21, X-45, and X-2

6.2-41 Isolation Valve Arrangement for Penetrations X-49, X-63, X-26, and X-22

6.2-42 Isolation Valve Arra ngement for Penetrations X-96, X-97, X-98, X-99, X-102, X-103, X-104, X-105, X-11A, and X-11B

6.2-43 Isolation Valve A rrangement for Penetrations X-65, X-25A, and X-25B

6.2-44 Isolation Valve Arra ngement for Penetration X-100

6.2-45 Isolation Valve A rrangement for Penetrations X-18A, X-18B, X-18C, X-18D, X-3, and X-67

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xvi 6.2-46 Isolation Valve Arrangement for Penetrations X-20, X-14, X-23, and X-24 6.2-47 Isolation Valve A rrangement for Penetrations X-92, X-12A, X-12B, X-12C, X-6, and X-8 6.2-48 Isolation Valve A rrangement for Penetrati ons X-19A, X-19B, and X-13

6.2-49 Isolation Valve Arra ngement for Penetrations X-33, X-31, X-35, X-32, X-36, and X-34 6.2-50 Isolation Valve Arrangement for Penetr ations X-46 and X-101

6.2-51 Isolation Valve Arrangement for Penetr ations X-47 and X-48

6.2-52 Isolation Valve Arrangement for Penetrations X-66, X-67, X-119, and X-64

6.2-53 Isolation Valve Arrangement for Penetrations X-42D, 54Aa, 54Bf, 61F, 62F, 69C, 78D, 78E, and 82E

6.2-54 Isolation Valve Arrangement for Penetrations X-85A, X-29A, X-85C, X-29C, X-72F, and X-73E

6.2-55 Isolation Valve Arrangement for Penetr ations X-5 and X-93

6.2-56 Isolation Valve Arrangement for Penetr ations X-4 and X-116

6.2-57 Isolation Valve Arrangement for Penetrations X-73F, X-77Ac, X-77Ad, and X-80B 6.2-58 Isolation Valve Arrangement for Penetrations X-82D, X-82F, X-83A, X-84F, and X-88 6.2-59 Isolation Valve Arrangement for Penetr ations X-94 and X-95

6.2-60 DELETED C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xvii 6.2-61 Sensible Energy Transient in the Reactor Vessel and Internal Metals - Original Rated Power 6.3-1 Head Versus Low-Pressure Core Spray Flow Used in LOCA Analysis

6.3-2 Head Versus Low-Pressure Coolant Injection Flow Used in LOCA Analysis

6.3-3 High-Pressure Core Spray Process Diagram (Sheets 1 and 2)

6.3-4 High-Pressure Core Spray and Low-Pressure Core Spray Flow Diagrams

6.3-5 Head Versus High-Pressure Core Spray Flow Used in LOCA Analysis

6.3-6 Low-Pressure Core Spray Process Diagram

6.3-7 Typical 48 in. Diameter Strainer

6.3-8 Typical 36 in. Diameter Strainer

6.3-9 Peak Cladding Temperature and Ma ximum Local Oxidation Versus Break Area - Hanford Original Rated Power

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 6.1-1 Chapter 6 ENGINEERED SAFETY FEATURES

The engineered safety features (ESF) of this plant are those systems provided to mitigate the consequences of postulate d serious accidents, in spite of the fact that these accidents are very unlikely. The ESF can be divided into four general groups: containment systems, emergency core cooling systems, habitability systems, fi ssion product removal and control systems. The systems in each general group are

a. Containment systems
1. Primary containment,
2. Secondary containment,
3. Containment heat removal system,
4. Containment isolation system, and
5. Combustible gas control.
b. Emergency core cooling systems
1. High-pressure core spray,
2. Automatic depressurization system,
3. Low-pressure core spray, and
4. Low-pressure coolant injection.
c. Habitability systems
d. Fission product removal and control systems

Related systems which help to mitigate the cons equences of such accidents are discussed in other sections. These are

a. Overpressurization protection,
b. Control rod drive housing support systems,
c. Control rod velocity limiter,
d. Main steam line flow restrictor, and
e. Standby liquid control system.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 6.1-2 6.1 ENGINEERED SAFETY FEATURE MATERIALS

Materials used in the engineered safety feat ure (ESF) components have been evaluated to ensure that material interactions will not o ccur that could potentially impair operation.

Materials have been selected to withstand the environmental conditions encountered during normal operation and postulated acci dents. Their compatibility with core and containment spray solutions has been considered and the e ffects of radiolytic d ecomposition products have been evaluated.

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

possibility of stress corrosion cracking.

6.1.1 METALLIC

MATERIALS

6.1.1.1 Materials Sel ection and Fabrication

6.1.1.1.1 Material Specifications

Table 5.2-7 lists the principal pressure retaining materials and the appropriate material specifications for the reactor cool ant pressure boundary components.

Table 6.1-1 lists the principal pressure retaining materials and the appropriate material specifications for the ESF of

the plant.

6.1.1.1.2 Compatibility of Construction Materials with Core Cooling Water and Containment Sprays

The compatibility of the reactor coolant with materials of cons truction exposed to the reactor coolant is discussed in Section

5.2.3. These

same materials of construction are found in the ESF components.

Demineralized water with no additives is employed in BWR core cooling water and containment sprays. No detrimental effects w ill occur on the ESF construction materials from allowable contaminant levels in this high purity water.

6.1.1.1.3 Controls for Au stenitic Stainless Steel

a. Control of the use of sensitized stainless steel

Wrought austenitic stainless steels that ha ve been heated to temperatures over 800 F by means other than welding or th ermal cutting are either resolution C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 6.1-3 annealed or otherwise demonstrated to be unsensitized in accordance with Regulatory Guide 1.44, Control of th e Use of Sensitized Stainless Steel.

Controls to avoid significant sensitization discussed in Section 5.2.3 are the same for ESF components.

b. Process controls to minimize exposure to contaminants

Process controls for austenitic stainless steel discussed in Section 5.2.3 are the same for ESF components.

c. Use of cold worked austenitic stainless steel

Austenitic stainless steel with a yield st rength greater than 90,000 psi was not used in ESF systems with the exception of screen material in the emergency core cooling system (ECCS) suppression pool strainers. Fabrication of the

screens entailed operations that cold-wor ked the screen material (i.e., punching, drilling, de-burring, and/or forming).

The cold-working caused yield stresses, as determined by hardness testing, to exceed 90,000 psi. The screens were found to be acceptable due to their nonpr essure retaining function and the controlled chemistry and pool temp erature of the suppression pool.

d. Thermal insulation requirements

All thermal insulation materials in ESF sy stems were selected, procured, tested, stored, and installed in accordance with Regulatory Guide 1.36, Revision 0.

The leachable concentrations of chloride s, fluorides, sodium, and silicates for nonmetallic thermal insulation for austenitic stainless steel were required to meet the requirements of Regulatory Guide 1.36, Revision 0. Cer tified reports and test reports for the materials are available.

e. Avoidance of hot cracking of stainless steel Process controls to avoid hot cracking discussed in Section 5.2.3 are the same for ESF components.

6.1.1.2 Composition, Compatibility, and Stability of Containment and Core Spray Coolants Containment spray and core cooling water for the ESF systems are supplied from the condensate storage tanks or the suppression pool.

C OLUMBIA G ENERATING S TATION Amendment58 F INAL S AFETY A NALYSIS R EPORT December2005 LDCN-05-002 6.1-4 The quality of the water stored in the condens ate storage tanks is maintained as follows:

Conductivity

  • 1 µS/cm at 25

°C Chlorides 0.05 ppm

pH* 6 to 8 at 25

°C Boron (as BO

3) 0.1 ppm The suppression pool is initially filled with high-purity water from either the condensate

storage or demineralized water makeup system.

The chloride concentration in the suppression pool water is maintained at less than 0.5 ppm Cl. To maintain suppression pool water quality, provision is made for periodic filtration and demineralizati on using the fuel pool filter demineralizer or by means of blowdown and reprocessing through the radwaste treatment system.

6.1.2 ORGANIC

MATERIALS

Significant quantities of organic materials that ex ist within the primary containment consist of cable insulating material, motor insulation material and coatings for containment surfaces, equipment, and piping.

Insulation properties for electric power cable are discussed in Section 8.3.1.2.3. Motors for the reactor recirculation pumps and drywell fan coil units contain small quantities of lubricating oil. Motor-operated valve b earings are grease lubricated.

Equipment, piping, and primary surfaces ar e provided with various coatings including galvanized zinc and aluminum. A minimal amount of hydrogen is liberated from zinc paint, galvanized, radiolytic and thermal decompositi on of organic materials. Since Columbia Generating Station (CGS) is an oxygen control plant with an in erted containment, the hydrogen concentration is not flammable. Therefor e, the minimal amount of hydrogen potentially generated by organic materi als is not a threat to containment integrity.

The suppression chamber (wetwell) above the water level from el. 472 ft 0 in. is coated with

one coat of Dimetcote 6 (inorga nic zinc). Approximately 4000 ft 2 of this coating do not meet ANSI N101.4 requirements because of damage. The damage to the coating will not result in the failure of the coating to adhere to its s ubstrate. Regardless, the design of the ECCS strainers assumes the complete failure of th e coating system and the entrainment of the resulting particles on the strainer bed following a LOCA.

Coatings on insulated piping that were damaged during construction were not repaired, and the insulation will contain any flakes which may form.

  • Conductivity and pH limits apply after correction for dissolved CO
2.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.1-5 In general protective coatings, except NSSS vendor-supplied equipment and valve contracts placed prior to issuance of Regulatory Guide 1.54, Revision 0, have been applied in accordance with the guidelines included in ANSI N101.4-1972, "Quality Assurance for Protective Coatings Applied to Nuclear Facilitie s." In addition, the coatings and coating systems used meet the requirements of AN SI N101.2-1972 for the design basis accident.

Certain items of equipment in the drywell have been coated with unqualified organic paint.

There are an estimated 5000 ft 2 of unqualified organic paint in the drywell. Under certain postaccident conditions, the unqualifie d organic paint could fail in flakes and, therefore, has been evaluated as a potential source of debris which can clog emergency core cooling suction strainers. It is unlikely that all paint would fail simultaneously or that a significant portion of

resulting paint flakes would be transported to the suppression pool. For conservatism, however, the design of the ECCS strainers is based on the complete fa ilure of the unqualified coatings, their transport to the wetwell, and th eir eventual entrainmen t on the strainer beds.

6.1.3 POSTACCIDENT

CHEMISTRY

Since the water chemistry conditions of the r eactor coolant are similar to suppression pool water, with the exception being the addition of activation, corrosion, and fission products, no appreciable pH changes are expected to occur during the LOCA transient.

There are no soluble acids and bases within the primary containment that would change post-LOCA water chemistry. Since the pH does not change appreciably there are no detrimental effects on containment equipment or structures.

The design basis source term LOCA accident re quires the addition of sodium pentaborate solution post-accident to maintain the suppression pool pH equal to or greater than 7.0. The Standby Liquid Control (SLC) tank contents are injected and mixed in the suppression pool within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> post-accident. This action is disc ussed in the dose consequences analysis in Section 15.6.5.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Table 6.1-1

Engineered Safety Features Systems and Related Systems Component Materials

Component Form Material Specification (A/SA) a LDCN-07-013 6.1-7 RHR heat exchanger Head and shell Plate Carbon steel 516 Grade 70 Flanges and nozzles Forging Carbon steel 105 Grade 2 Tubes U-Tube Stainless steel 249 Type 304L Tube sheet Forging Carbon steel 105 Grade 2 Bolts Bar Alloy steel 193 Grade B7 Nuts Bar Alloy steel 194 Grade 7

RHR pump Shell and dished head Plate Carbon steel 516 Grade 70 Suction nozzle Pipe Carbon steel 333 Grade 6 Flange Forging Carbon steel 350 Grade LF2 Impeller Casting Stainless steel 296 CA15 Shaft Bar Stainless steel 276 Type 410 Shell/suction/discharge plate Plate Carbon steel 516 Grade 70 Studs Bar Alloy steel 193 Grade B7 Nuts Bar Alloy steel 194 Grade 7 HPCS pump Shell and dished head Plate Carbon steel 516 Grade 70 Flange Plate Carbon steel 516 Grade 70 Discharge elbow Pipe Carbon steel 234 Grade WPB Impeller Casting Stainless steel 296 CA15 or A487 CA6NM CL A Shaft Bar Stainless steel 276 Type 410 Shell/suction/discharge plate Plate Carbon steel 516 Grade 70 Studs Bar Alloy steel 193 Grade B7 Nuts Bar Alloy steel 194 Grade 7 LPCS pump Shell and dished head Plate Carbon steel 516 Grade 70 Suction nozzle Pipe Carbon steel 333 Grade 6 Flange Forging Carbon steel 350 Grade LF2 Elbow Pipe Carbon steel 234 Grade WPB Impeller Casting Stainless steel 296 CA15 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Table 6.1-1

Engineered Safety Features Systems and Related Systems Component Ma terials (Continued)

Component Form Material Specification (A/SA) a LDCN-06-060 6.1-8 LPCS pump (Continued) Shaft Bar Stainless steel 276 Type 410 Shell/suction/discharge plate Plate Carbon steel 516 Grade 70 Studs Bar Alloy steel 193 Grade B7 Nuts Bar Alloy steel 194 Grade 7

HPCS valves Body, bonnet Casting Carbon steel 216 Grade WCB Disc (globe) Casting Carbon steel 216 Grade WCB Disc (gate) Forging Carbon steel 105 Grade 2 Stem (globe) Bar Stainless steel 479 Type 410 Stem (gate) Bar 17-4 pH (H1150) 461 Grade 630 Studs Bar Alloy steel 193 Grade B7 Nuts Bar Alloy steel 194 Grade 7 Isolation valves Body Casting Carbon steel 216 Grade WCB Forging Stainless steel 182 Grade F316 Forging Carbon steel 350 Grade LF2 Forging Carbon steel 105 Grade 2 Bonnet Forging Carbon steel 105 Grade 2 Casting Carbon steel 216 Grade WCB Forging Carbon steel 350 Grade LF2 Disc Forging Alloy steel 182 Grade F11 Forging Stainless steel 182 Grade F316 Casting Carbon steel 216 Grade WCB Forging Carbon steel 105 Forging Carbon steel 350 Grade LF2 Stem Bar Stainless steel 276 Type 410 Bar Stainless steel 479 Type 410 Bar Stainless steel 564 Type 630 Bar Stainless steel 461 Type 630 Forging Stainless steel 182 Grade F6a Stud Bar Alloy steel 540 Grade B23 Bar Alloy steel 193 Grade B7 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Table 6.1-1

Engineered Safety Features Systems and Related Systems Component Ma terials (Continued)

Component Form Material Specification (A/SA) a LDCN-06-060 6.1-9 Isolation valves (Continued) Nut Bar Carbon steel 194 Grade 7 Bar Carbon steel 194 Grade 2H Safety relief valves Body and bonnet Forging Carbon steel 105 Grade 2 Disc holder Forging Inconel 718 MS 5662B Shaft Bar Stainless steel 582 Type 416 Spindle Bar 17-4 pH (H1085) 564 Type 630 Studs Bar Alloy steel 193 Grade B7 Nuts Bar Carbon steel 194 Grade 2H (An acceptable equivalent is Grade 7.)

Standby liquid control pump Fluid cylinder Forging Stainless steel 182 Grade F304 Cylinder head, valve cover, and stuffing box flange plate Plate Stainless steel 240 Type 304 Cylinder head extension, valve stop, and stuffing box Shapes Stainless steel 479 Type 304 Stuffing box gland and plungers Bar 17-4 pH (H1075) 564 Grade 630 Studs Bar Alloy steel 193 Grade B7 Nuts Bar Alloy steel 194 Grade 7 Standby liquid control explosive valve Body and fittings Shapes Stainless steel 479 Type 304 Flanges Forging Stainless steel 182 Grade F304 Pipe Pipe Stainless steel 312 Type 304 Control rod velocity limiter Casting Stainless steel 351 Grade CF8 or 351 Grade CF3 Main steam flow restrictor Upstream part Casting Stainless steel 351 Grade CF8 Downstream part Casting Carbon steel 216 Grade WCB C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Table 6.1-1

Engineered Safety Features Systems and Related Systems Component Ma terials (Continued)

Component Form Material Specification (A/SA) a 6.1-10 Piping HPCS Pipe Carbon steel 106 Grade B LPCS Pipe Carbon steel 106 Grade B RHR (unless otherwise noted) Pipe Carbon steel 106 Grade B RHR connection to RRC Pipe Stainless steel 312 Type 304 or Pipe Carbon steel 333 Grade 1 or 6 RHR spray headers Pipe Carbon steel 333 Grade 1 or 6 SRV discharge line Pipe Carbon steel 333 Grade 1 or 6 24-in. downcomer vents Pipe Carbon steel 106 Grade B or C and 312 Type 304L or 316L (bottom 6 in.

only) 28-in. downcomer vents Pipe Carbon steel 155 KC70 Class 2 and 312 Type 304L

or 316L (bottom 4 in.

only) Fittings Carbon steel 181 Grade II Fittings Carbon steel 234 Grade WPB Fittings Stainless steel 182 Grade F304 Fittings Stainless steel 182 Grade WP304 Containment Vessel Plate Carbon steel 516 Grade 70 Plate C-Mn-Si steel 537 Class 1 Structural members Plate Carbon steel 36 Downcomer bracing Pipe Carbon steel 106 Grade B Rings Carbon steel 572 Grade 60 Pipe restraints Plate Carbon steel 516 Grade 70 Penetration nozzle Pipe Stainless steel 312 Grade TP 304 Pipe Carbon steel 333 Grade 1 or 6 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Table 6.1-1

Engineered Safety Features Systems and Related Systems Component Ma terials (Continued)

Component Form Material Specification (A/SA) a 6.1-11 Containment (Continued) Guard pipe Pipe Carbon steel 333 Grade 1 or 6 Flued head Forging Carbon steel 350 Grade 1 Fl or 2 Drywell floor seal Pipe Stainless steel 312 Type 304L a SA materials for ASME Secti on III pressure boundary item.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-1 6.2 CONTAINMENT SYSTEMS

6.2.1 CONTAINMENT

FUNCTIONAL DESIGN

6.2.1.1 Pressure Su ppression Containment

6.2.1.1.1 Design Basis

The pressure suppression containment system, including subcompartment s, meets the following functional capabilities:

a. The containment has the cap ability to maintain its functional in tegrity during and following the 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 pressure and temperature) and is furthe r postulated to occur simultaneously with loss of offsite power. In developing the load combinations, a safe shutdown earthquake (SSE) is postulated to occur simultaneously with the LOCA;
b. The containment in combination with other accident mitigation systems limits fission product leakage during and following the postulated de sign basis accident (DBA) to values less than leakage rates which would result in offsite doses greater than those set forth in 10 CFR 50.67;
c. The containment system w ill withstand coincident fluid jet forces associated with the flow from the postulated rupture of any pipe within the containment;
d. The containment design permits remova l of fuel assemblies from the reactor core after the postulated LOCA;
e. The containment system is protected from or designed to withstand missiles from internal sources and excessive motion of pipes which could directly or indirectly endanger the inte grity of the containment;
f. The containment system provides means to channel the flow from postulated pipe ruptures in the drywell to the pressure suppression pool;
g. The containment system is designed to allow for periodically conducting tests at the peak pressure calculated to result from the postulated DBA to confirm the leaktight integrity of the contai nment and its penetrations; and
h. The containment system, which includes the wetwell-to-drywell and the reactor building-to-wetwell vacuum breaker sy stems, can withstand the maximum C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 6.2-2 calculated external pressure on the c ontainment vessel and upward pressure on the drywell floor due to containment spray actuation under the most severe conditions.

6.2.1.1.2 Design Features

A general description of the primary containment and its compliance with applicable codes, standards and guides is given in Section 3.8.2. The design of the primary containment incorporates the following:

a. Protection against dynamic effects The design of the containment takes into account dynamic effects such as pipe

whip, missiles, and jet loads which coul d result from a postulated LOCA. The design ensures that the capability of the containment a nd other engineered safety feature (ESF) equipment which mitigate the consequences of an accident are not impaired by the dynamic effects of th e accident. The de sign provisions are discussed in Section 3.8.2. The capability of the primary steel containment vessel to withstand the hydrodynamic effects of safety/relief valv e (SRV) actuation or a LOCA and the proposed modifications, if any, for those portions and components of the vessel which are determined to have insufficient capability to accommodate these hydrodynamic effects are di scussed in References 6.2-7 and 6.2-8. b. Pressure suppression The primary containment conforms to the fundamental principles of a MKII pressure suppression system. A comparison of the containment with similar

containments is made in Table 1.3-4. The water stored in the suppression pool is capable of condensing the steam displaced into the wetwell through the downcomer vents, and the amount of wa ter is sufficient su ch that operator action is not required for at least 10 minutes immedi ately following initiation of a LOCA. In addition, the design allows the water from any pipe break within the primary containment to drain back to the suppression pool. This "closed loop" ensures a continuous, adequate supply of water fo r core cooling.

c. Negative loading The primary containment is designed for the following negative loadings:
1. A drywell pressure of 2.0 ps i below reactor building pressure, 2. A wetwell pressure of 2.0 psi below reactor building pressure, and

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 6.2-3 3. An upward pressure across the diaphragm floor of 6.4 psid.

The nine 24-in. wetwell-to-drywell (WW-DW) and the three 24-in. reactor building-to-wetwell (RB-WW) vacuum breaker lines are sized to ensure that negative loadings are not ex ceeded. The vacuum break er systems are described in Section 3.8.2.

The primary containment is designed for a total external pressure of 4 psid. However, since the compressed insulation between the concrete biological shield and the containment exerts a uniform 2 psid external pressure (half of the total external pressure differen tial allowed) the drywell pressure may be no less than 2 psi below the reacto r building pressure.

d. Environmental conditions

The means to maintain the required environmental conditions inside the primary containment during normal opera tion is discussed in Section 6.2.1. With the exception of energy removal from th e suppression pool, there are no requirements for environm ental controls during a LOCA. All equipment required to mitigate the conse quences of an accident is designed to perform the required functions for the required duration of time in the accident environment.

The equipment accident e nvironment is listed in Table 3.11-2. e. Insulation

Inside the primary containment, the type of thermal insulation used for piping is primarily reflective metal panel. Nonmetallic mass insulation may also be used, in limited applications, where configuration of the component to be insulated precludes the use of reflective insulation (i.e., at pipe whip restraints, pipe supports, and interferences), and as stop gaskets between circumferential joints of reflective insulation. Also, nonmetallic insulation ha s been used to expedite the replacement of damaged reflective in sulation panels when as low as is reasonably achievable (ALARA) considerations apply.

Reflective metal insulation pane ls used for the pipes are typically 2 ft long, 3 in.

to 4 in. thick, and cover ha lf of the pipe's circumfere nce. These panels have 24-gauge stainless steel sheet s which fully encase the 6 mil aluminum sheets.

The panels used for the reactor pressure vessel (RPV) are larger, typically 2 ft x 6 ft, and are encased by 18-gauge stainless steel.

Panels on piping covering areas which require inserv ice inspection, such as welds, are fastened by quick-release buckle bands. Nonremovable insulation panels around pipes are fastened. The fasteners have been designed to be

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 6.2-4 weaker than the panels; ther efore, it is postulated that some panels near a pipe break will be blown away, but that the panels themselves will not be sheared open.

The insulation panels and nonmetallic ma ss insulation that may be blown off constitute a credible debris source with in the primary containment following a LOCA and seismic event. Equipment w ithin the primary containment, if not designed to Seismic Category I standards, is at least supported so as to remain fastened during a seismic event.

Large pieces of insulation debris could be lodged agains t the perimeter of the jet deflectors, but the square footage of panels blown off the piping would not be sufficient to result in significant blockage of the downcomers. If metallic or nonmetallic insulation were blown off in a pipe break accident, it is probable that most debris would remain in la rge pieces and would be lodged against piping, equipment, or grating before it reached the drywell floor, or remain on the floor or be lodged against the jet defl ector stiffener plates rather than be swept through the downcomers into the s uppression pool. Insulation fibers and bits of foil liberated by the rupture has a higher potential of reaching the suppression pool, either during the immediat e aftermath of the rupture or in the subsequent washdown by the containment sprays.

Insulation that is transported to the suppression pool could affect the performance of strainers in the wetwell.

For this reason, the design of the strainers uses the follo wing conservative bases:

1. Unlimited amounts of reflective metal insulation will be transported to the suppression pool;
2. Dependent on location in the drywell, from 21% to 76% of nonmetallic (fibrous) insulation disl odged by a pipe rupture event is transported to the wetwell.

The higher transport percentage, 76%, is used when dislodged insu lation is below drywell grating that would hinder the transport of insulation to the wetwell; and

3. All metallic and fibrous insula tion that reaches the suppression pool following a LOCA is assumed to be entrained on the beds of operating ECCS strainers.

Strainers on the RHR and LPCS suction lines are located at a centerline of 11 ft 9 in. to 12 ft 4 in. above the pool bottom. The HPCS suction strainers are located 3 ft 6 in. above the pool bottom.

These strainers are designed to operate with their beds entrained with the insulation and debris postulated in the C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDC N-0 3-0 0 3 6.2-5 suppression pool following a LOCA. Base d on the above, neither the metallic insulation panels nor the nonmetallic mass insulation will cause the degradation of the ECCS systems due to clogging of suction strainers. The analysis is discussed in Sec tion 6.3.2.2.6. 6.2.1.1.3 Design Evaluation

6.2.1.1.3.1 Summary Evaluation. The key design pa rameters for the pressure suppression containment are shown in Table 6.2-1.

The design parameters are not determined from a single event but from an envelope of accident conditions.

A maximum drywell and suppression chamber pressure occurs near the end of a blowdown

phase of a LOCA. Approximately the same peak pressure occurs for either the break of a recirculation line or a main steam li ne. Both accidents are evaluated.

The most severe drywell temperature condition (peak temperatur e and duration) occurs for a small primary system rupture a bove the reactor water level that results in the blowdown of reactor steam to the drywell (small steam break). To demonstrat e that breaks smaller than the rupture of the largest primary system pipe will not exceed the containment design parameters, the containment system responses to an interm ediate size liquid break and a small size steam break are evaluated. The results show that the containment design conditions are not exceeded for these smaller break sizes.

A single recirculation loop opera tion (SLO) containment analysis was performed. The peak wetwell pressure, diaphragm download and pool swell containment responses were evaluated over the entire SLO power/flow region.

The highest peak wetwell pressure during SL O occurred at the maximum power/flow condition of 78.7% power/64.3% core flow. This peak wetwell pressure decreased by about 1%

(0.5 psi) compared to the rated two-loop ope ration pressure. The di aphragm floor download and pool swell velocity evalua ted at the worst power/flow condition during SLO were found to be bounded by the rate d power analysis.

The analytical results and method of analysis ut ilized to determine the seismic sloshing effects in the wetwell are discussed in Section 3.8.2. 6.2.1.1.3.2 Containm ent Design Parameters. Table 6.2-1 provides a listing of the key design parameters of the primary containment system including the design characteristics of the

drywell, suppression pool, and pr essure suppression vent system.

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDC N-0 3-0 0 3, 0 3-062 6.2-6 The downcomer loss coefficient is 2.77. This value was used in the assessment of the limiting containment performance analysis. The nonlimiting events not r eanalyzed for the power uprate assumed a loss of coefficient of 1.9.

There are eighty-four 24-in. diameter downcomers and eighteen 28-in. downcomers. Three of the downcomers are capped.

No known studies have been pe rformed to experimentally dete rmine 4T test downcomer vent loss coefficients. However, in Pool Swell Analytical Model (PSAM)/4T test data comparisons (References 6.2-27 and 6.2-28), General Electric (GE) used downcomer vent loss coefficients of 2.51 and 3.50 for the 4T test 20-in. downcomers and 24-in. downcomers, respectively.

These values were used as input to the GE PS AM and were calculated using information from Reference 6.2-15. The Columbia Generating Station (CGS) downcomer friction loss coefficient (fl/D) that is used in pool swell studies is equal to 1.9 (see Table 3.8-1

). Use of a value of 1.9 versus a 4T value ensures conservatism in CGS pool swell studies in that lower values of fl/D maximizes pool swell ve locity (see Figure 4-24 of Reference 6.2-5).

Table 6.2-2 provides the performance parameters of the related ESF systems which supplement the design conditions of Table 6.2-1 for containment cooling pur poses during post blowdown long-term accident operation. Performance parameters given incl ude 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 functi onal evaluation was initially based on the consideration of se veral postulated accident conditi ons resulting in release of reactor coolant to the containment. These accidents include

a. An instantaneous guillotine r upture of a recirculation line, b. An instantaneous guillotine r upture of a main steam line, c. An intermediate size liquid line rupture, and d. A small size steam line rupture.

The containment response to the main steam line, inte rmediate liquid line, and small size steam line breaks, were bounded by the recirculation lin e break. As part of the evaluations to support the reactor power uprate to 3486 MWth, only the recirculation line rupture (Case C), the bounding event for containment response, was reanalyzed. Th e containment response analyses are not cycle specific nor are they pa rt of the analyses performed to support core reload analyses. For further discussion, s ee Sections 6.2.1.1.3.3.4 and 6.2.1.1.3.3.5.

6.2.1.1.3.3.1 Recirc ulation Line Rupture. Immediately following the rupture of the recirculation line, the flow out both sides of the break will be limited to the maximum allowed by critical flow consideration.

Figure 6.2-2 shows a schematic view of the flow paths to the break. In the side adjacent to the suction nozzle, the flow will correspond to critical flow in

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDC N-0 3-0 0 3 6.2-7 the pipe cross section. In the side adjacent to the injection nozzle, the flow will correspond to critical flow at the 10 jet pump nozzles associat ed with the broken loop. In addition, the cleanup line cross tie will add to the critical flow area.

Table 6.2-3 provides a summation of the break areas. References 6.2-1 and 6.2-2 provide a detailed descri ption of the analytical models and assumptions for this event.

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. The initial conditions for the recirculation line break accident are such that the system energy is maximized and the syst em mass is minimized. That is
1. For the nonlimiting events which we re not reanalyzed for power uprate, the reactor is operating at 104.2% of maximum power (3323 MWt). This maximizes the postaccident decay heat.
2. For the limiting events, the reactor is operating at 3702 MWt. This power corresponds to 102% of 3629 MWt. The analysis power was chosen to support a future uprat e to 3629 MWt and bounds a power uprate to 3486 MWt (current).
3. For the nonlimiting events which we re not reanalyzed for power uprate, the standby service water (SW) te mperature is assumed to be 95 F, which exceeds the maximum expected temperature. For power uprate, a less conservative value of 90 F was assumed.
4. The suppression pool mass is at the low water level.
5. The suppression pool temperature is assumed to be at the maximum value allowed for power operation.
b. The recirculation line is considered to be severed instantly.

This results in the most rapid coolant loss and depressuriza tion of the vessel, with coolant being discharged from both ends of the break.

c. Reactor power generation ceases at the time of accident initiation because of void formation in the core re gion. Scram also occurs in less than 1 sec from receipt of the high drywell pressure signal. The difference between the shutdown times is negligible.
d. The vessel depressurization flow rates are calculated using M oody's critical flow model (Reference 6.2-3) assuming "liquid only" outfl ow, since this assumption C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 6.2-8 maximizes the energy releases to the dr ywell. "Liquid only" outflow implies that all vapor formed in the RPV 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 the RPV discharge flow rates. Further, Moody's critical flow m odel, which assumes annular, isentropic flow, thermodynamic phase equilibrium, a nd maximizes slip ratio, accurately predicts vessel outfl ows through small diameter orifices.

Actual rates through larger flow areas, however, are less than the model indicates because of the effects of a n ear homogeneous two-phase flow pattern and phase nonequilibrium. These effects are conservatively neglected in the analysis.

e. The core decay heat and the sensible heat released in cooling the fuel to approximately 550F are included in the RPV depressurization calculation. The rate of energy release is calculated us ing a conservatively high heat transfer coefficient throughout the depressurization period. The resulting high-energy release rate causes the RPV to maintain nearly rated pressure for approximately 20 sec. The high RPV pressure increases the calculated blowdown flow rates which is again conservative for analyses purposes. The sens ible energy of the fuel stored at temperatur es below approximately 550 F is released to the vessel fluid along with the stored energy in the vessel and internals as vessel fluid temperatures decrease below approximately 550 F during the remainder of the transient calculation.
f. The main steam isolation valves (MSIV) start closing at 0.5 sec after the accident. They are fully closed in th e shortest possible tim e of 3 sec following closure initiation. In actuality, the clos ure signal for the MSIV will occur from low reactor water level, so the valves will not receive a signal close for at least 4 sec, and the closing time may be as long as 5 sec. By assuming rapid closure of these valves, the RPV is maintained at a high pre ssure, which maximizes the calculated discharge of high-en ergy water into the drywell.
g. For the nonlimiting events which are not reanalyzed for power uprate, reactor feedwater flow was assumed to stop in stantaneously at time zero. Since feedwater flow tends to depressurize the RPV, thereby reduci ng the discharge of steam and water into the drywell, th is assumption is conservative for the analysis since MSIV closure cuts of f motive power to the steam-driven feedwater pumps.

For the limiting events, reactor feedwater flow is assumed to continue until all high-energy feedwater is injected into the reactor.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-9 h. 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 vita l systems for long-term coo ling 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 blowdown period of the accident is analyzed using the following assumptions:

a. Thermodynamic equilibrium exists in the drywell and suppression chamber. Since nearly complete mixing is achieved, the analysis assumes complete mixing; b. The fluid flowing through the drywell-to-suppression pool vents is formed from a homogeneous mixture of the fluid in the drywell. The 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. The fluid flow in the drywell-to-suppr ession pool vents is compressible except for the liquid phase; and
d. No heat loss from the gases inside the primary containment is assumed. In reality, condensation of some steam on the drywell surfaces would occur.

6.2.1.1.3.3.1.3 Assumpti ons for Long-Term Cooling. Following the blowdown period, the ECCS provides water for core fl ooding, containment spray, and l ong-term decay heat removal. The containment pressure and temperature resp onse during this period is analyzed using the following assumptions:

a. The low-pressure coolan t injection (LPCI) pumps ar e used to flood the core prior to 600 sec after the accident. The HPCS is assumed available for the entire accident;
b. After 600 sec, the LPCI pump flow may be diverted from the RPV to the containment spray. This is manual operation. Actually, the containment spray need not be activated at all to keep the containment pressure below the containment design pressure. Prior to activation of the containment cooling mode (assumed at 600 sec after the acciden t) all of the LPCI pump flow will be used to flood the core. In response to i ndications of significa nt core damage the operators are directed to initiate containment spray to reduce potential radioactivity released;

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-10 c. The effects of decay energy, stored energy, and energy from the metal-water reactor on the suppression pool temperature are considered;

d. The suppression pool is assumed to be the only h eat sink available in the containment system;
e. After approximately 600 sec, it is assumed that the RHR heat exchangers commence to remove energy from the c ontainment by means of recirculation cooling from the suppression pool with the SW system; and
f. The performance of the ECCS equipment during the long-term cooling period is evaluated for each of the following three cases of interest:

Case A: Offsite power available - all ECCS equipment and containment spray operating.

Case B: Loss of offsite power, minimum diesel power availa ble for ECCS and containment spray.

Case C: Same as Case B except no containment spray.

Case C is limiting as it results in the highest peak suppression pool temperature and containment pressure. Since power upr ate does not change the results of the three cases relative to each other, Case C was reevaluated for power uprate

conditions.

6.2.1.1.3.3.1.4 In itial Conditions for Accident Analyses. Table 6.2-4 provides the initial reactor coolant system and cont ainment conditions used in the accident response evaluation. The tabulation includes parameters for the react or, the drywell, the s uppression chamber, and the vent system.

Table 6.2-3 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.

The mass and energy release sources and rates fo r the containment respons e analyses are given 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 reci rculation line break are shown in Figures 6.2-3 and 6.2-4 , respectively.

The suppression chamber is pressurized by the carryover of noncon densables from the drywell and by heatup of the suppression pool. As the vapor formed in the drywell is condensed in the suppression pool, the temperature of the suppr ession pool water peak s and the suppression chamber pressure stabilizes. The drywell pressure stabilizes at a sligh tly higher pressure; the C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-11 difference being equal to the downcomer subm ergence. During the RPV depressurization phase, most of the noncondensable gases initially in th e drywell are forced into the suppression chamber. However, following the depressurization, noncondensab les will redistribute between the drywell and suppression chamber by means of the vacuum breaker system. This redistribution takes place as steam in the drywell is conde nsed by the relatively cool ECCS water which is beginning to cascade from the break causing the dr ywell pressure to decrease.

The ECCS supplies sufficient core cooling water to control co re heatup and limit metal-water reaction to less than 0.07%. After the RPV 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 RPV, through the broken recirculation line, in th e form of hot water which flows into the suppression chamber by means of the drywell-to-suppression chamber vent system. This flow provides a heat sink for the drywell atmosphere and there by causes the drywell to depressurize.

Table 6.2-5 provides the peak pressure, temperature, and time parameters fo r the recirculation line break as predicted for the conditions of Table 6.2-4 and corresponds with Figures 6.2-3 and 6.2-4. Figure 6.2-5 shows the time dependent response of the floor (deck) 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 dryw ell to the suppression p ool for condensation of the steam. The pressure differential between th e drywell and suppression pool controls this flow. Figure 6.2-6 provides the mass flow versus time relationship through the vent system for this accident.

6.2.1.1.3.3.1.6 Long-Te rm Accident Responses. To assess the adequacy of the containment following the initial blowdown tran sient an analysis was made of the long-term temperature and pressure response following the accident. The anal ysis assumptions are those discussed in Section 6.2.1.1.3.3.1.3 for the three cases of interest.

The initial pressure response of the containment (the first 600 sec afte r break) is the same for each case. As can be seen from Figures 6.2-7 , 6.2-8 , and 6.2-9 , Case C is the limiting event.

Case A: All ECCS equipment ope rating - with containment spray This case assumes that offsite ac power is available to operate a ll cooling systems.

During the first 600 sec following the pi pe break, the HPCS, LPCS, and all LPCI pumps are assumed operating. All flow is injected directly into the reactor vessel.

After 600 sec, both RHR heat exchangers are activated to remove energy from the containment. During this mode of operation the flow from two of the LPCI pumps is routed through the RHR heat exchangers where it is cool ed before being discharged into the containment spray header.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-12 The containment pressure response to this set of conditions is shown as Curve A in Figure 6.2-7. The corresponding drywell and suppression pool temperature responses are shown as Curve A in Figures 6.2-8 and 6.2-9. After the initial blowdown and subsequent depressurizati on due to core spray and LPCI core flooding, energy addition due to core decay heat results in a gradual pressure and temperature rise in the containment. When the energy removal rate of the RHR system exceeds the energy addition rate from the decay heat, the containment pressure and temperature reach a second peak value and decrease gradually.

Table 6.2-6 summarizes the cooling equipment operation, the peak long term containm ent pressure following the initial blowdown peak, and the peak suppression pool temperature.

Case B: Loss of offsite power - with delayed containment spray

This case assumes no offsite power is available following the acc ident and that only the HPCS and one LPCI diesel (Divisions 3 and 2, respectively) are available. For the first 600 sec following the break, one HPCS, and two LPCI pumps are used exclusively for core cooling.

After 600 sec, the RHR heat exchanger is activated. The flow from one pump is routed through the heat exchanger a nd is discharged to the containment spray line. The second LP CI pump is assumed to be shut down. The containment pressure response to this set of conditions is shown as Curve B in Figure 6.2-7. The corresponding drywell and suppression pool temperature responses are shown as Curve B in Figures 6.2-8 and 6.2-9. A summary of this case is given in Table 6.2-6. Case C: Loss of offsite power - no containment spray

This case assumes no offsite power is available following the acc ident and that only the HPCS and one LPCI diesel (Divisions 3 and 2, respectively) are available. For the first 600 sec following the accident, one HPCS, and two LPCI pumps are used exclusively to cool the core.

After 600 sec, one RHR heat exchanger is activated to remove energy from the

containment, but containment spray is not activated. The LPCI flow cooled by the RHR heat exchanger is discharged into the RPV. The second LPCI pump is assumed to be shut down. The containment pressu re response to this set of conditions is shown in Figure 6.2-10. The corresponding dryw ell and suppression pool temperature responses are shown in Figures 6.2-11 and 6.2-12. A summary of this case is given in Table 6.2-6. When comparing the "spray" Case B with the "no spray" Case C at the same power level, the same RHR heat exchanger duty is obtained since the suppression pool te mperature response is approximately the sa me as shown in Figure 6.2-9. Thus, the same amount of energy is C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-064 6.2-13 removed from the pool whether the exit flow from the RHR heat exchanger is injected into the reactor vessel or into the drywell as spray. Although the peak containm ent pressure is higher for the "no spray" case, the pressure is significantly less than the cont ainment design pressure.

Figure 6.2-13 shows the rate at which the RHR system heat exchanger will remove heat from the suppression pool following a LOCA.

Cases B and C, above, presume the loss of offsit e power concurrent with a single failure that results in the loss of a safety division. In a different scenario, a single failure is presumed to solely affect the cooling of one RHR heat exchanger. This is similar to Cases B and C, above, except that all ECCS pumps are presumed to be available and running. For this alternate scenario, the operator is assumed to shut down LPCS and th e Division 1 LPCI pump, along with the extra Division 2 LPCI pump, as postula ted in Cases B and C, in order to balance energy removal through pump flows with en ergy addition from pump heat. When the unneeded pumps are shut down, Case C remains bounding over this alternate scenario.

6.2.1.1.3.3.1.7 Chronol ogy of Accident Events. A complete description of the containment response to the design basis recirculation line break has been given in Sections 6.2.1.1.3.3.1.5 and 6.2.1.1.3.3.1.6. Results for this accident are shown in Figures 6.2-3 through 6.2-6 , 6.2-10 , 6.2-11 , 6.2-12 , and 6.2-13. A chronological sequence of ev ents for this accident from time zero is provided in Table 6.2-8.

6.2.1.1.3.3.2 Main Steam Line Break. The sequence of events immediately following the rupture of a main steam line between the reac tor vessel and the flow limiter have been determined. The flow in both sides of the break will accelerate to the maximum allowed by the critical flow considerations. In the side adjacent to the reacto r vessel, the flow will correspond to critical flow in the steam line break area. Blowdown through the other side of the break will occur because the steam lines are all interconnected at a point upstream of the turbine by the bypass header. This interconnection allows primary system fluid to flow from the three unbroken steam lines, thr ough the header and back into the drywell by means of the broken line. Flow will be limited by critical flow in the steam line flow restrictor. The total effective flow area is given in Figure 6.2-14 which is the sum of the steam line cross sectional area and the flow restrictor area. A slower closure rate of the isolati on valves in the broken line would result in a sli ghtly longer time before the total valve area of the three unbroken lines equals the flow limiter area in the broken line. The effective br eak area in this case would start to reduce at 5 sec rather than 4.3 sec as demonstrated in Table 6.2-10. The drywell design temperature (340°F) was determined base d on a bounding analysis of the superheated gas temperature. The short-term peak drywe ll temperature is controlled by the initial steam flow rate during a large steam line break. Since the vessel dome pressure assumed for the original rated analysis (1055 ps ia) is unchanged by power uprate, the initial break flow rate for this event is not impacted. Th is event was not reanalyzed for power uprate as there would be no impact on the original rated short-term peak drywell temperature value. The peak drywell pressure occurs before the reduction in effective break area due to MSIV closure and is, C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-14 therefore, insensitive to a possible slower closure time of the isolation valves in the broken lines. The mass and energy release rates are provided in Section 6.2.1.3.

Immediately following the break, the total steam flow rate leaving the vessel would be approximately 8600 lb/sec, which exceeds the steam generation rate in the core of 4140 lb/sec.

This steam flow to steam generation mismatch causes an initial vessel depressurization of the reactor vessel at a rate of approximately 42 psi/sec. Void formation in the reactor vessel water causes a rapid rise in the water level, and it is conservatively assume d that the water level reaches the vessel steam nozzles 1 sec after the break occurs. The water level rise time of 1 sec is the minimum that could occur under any reactor operating condition. From that time on, a two-phase mixture corresponding to the overall average vessel quality would be discharged from the break. The use of the overall average vessel qua lity results in fluid qualities which are considerably lower than would actually occu

r. Thus, the drywell peak pressure, which increases with decreasing break flow quality, is maximized. During the first second of the blowdown, the blowdown flow will c onsist of saturated steam. This steam will enter the containment in a super-heated condition of approximately 330

°F.

Figures 6.2-15 and 6.2-16 show the pressure and temperature responses of the drywell and suppression chamber during the primary system blowdown phase of the steam line break accident for original rated pow er. The short-term performa nce is not affected by power uprate. The long-term response is bounded by the recirculation suction line break. Therefore, no steam line break analysis was performed for the power uprate condition.

Figure 6.2-16 shows that the drywell atmosphere temp erature approaches 330°F after 1 sec of primary system steam blowdown. At that time, the water level in the vessel will reach the steam line nozzle elevation and the blowdown flow will change to a two-phase mixture. This increased flow causes a more ra pid drywell-pressure rise. The peak differential pressure occurs shortly after the vent clearing transi ent. As the blowdown proceeds, the primary system pressure and fluid invent ory will decrease, resulting in a decrease in the vent system and the differential pressure between the drywell and suppression chamber.

Table 6.2-5 presents the peak pressures, peak temperatures, and times of this accident as compared to the reci rculation line break.

Approximately 50 sec after the start of the accident, the primary system pressure will have dropped to the drywell pressure and the blowdown will be over. At this time the drywell will contain primarily steam, and the drywell and s uppression chamber pressures will stabilize.

The pressure difference corresponds to the hydrostatic pr essure of vent submergence.

The drywell and suppression pool will remain in this equilibrium c ondition until the reactor vessel refloods. During this period, the emer gency core cooling pumps will be injecting cooling water from the suppression pool into the reactor. This injection of water will eventually flood the reactor vesse l to the level of the steam li ne nozzles and the ECCS flow C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-15 will spill into the drywell.

The water spillage will condense the steam in the drywell and, thus, reduce the drywell pressure. As soon as the drywell pressure drops below the suppression chamber pressure, the drywell vacuum breakers will open and noncondens able gases from the suppression chamber will flow back into the drywell until the pressure in the two regions equalize.

6.2.1.1.3.3.3 Hot St andby Accident Analysis. This section is not applicable to BWR-5.

6.2.1.1.3.3.4 Intermediate Size Breaks. The failure of a recircula tion line results in the most severe pressure loading on the drywell structure. However, as part of the original containment performance evaluation, the consequences of intermediate break s were also analyzed. This classification covers those breaks for which the blowdown will result in reactor depressurization and operation of the ECCS. This section describes the consequences to the containment of a 0.1 ft 2 break below the RPV water level.

This break area was chosen as being representative of the interm ediate size break area range. Th ese breaks can involve either reactor steam or liquid blowdown. The conseque nces of an intermediate size break are less severe than from a recirculation line rupture.

Because these breaks are not limiting, they were not reanalyzed for power uprate.

Following the 0.1 ft 2 break, the drywell pressu re increases at approxima tely 1 psi/sec. This drywell pressure transient is su fficiently slow so that the dyna mic effect of the water in the vents is negligible and the vents will cl ear when the drywell-to-suppression chamber differential pressure is equal to the vent submergence hydrostatic pressure.

Figures 6.2-17 and 6.2-18 show the drywell and suppr ession chamber pressure and temperature response for original rated power c onditions at 3323 MWt.

The ECCS response is discussed in Section

6.3. Approximately

5 sec after the 0.1 ft 2 break occurs, air, steam, and water will start the flow from the drywell to the suppressi on pool. The steam will be condensed and the air will enter the suppression chamber free space. The continual purging of drywell air and steam to the suppression chamber will result in a pressurization of both the

wetwell and drywell to about 25 and 30 psig, respectively. The containment will continue to gradually increase in pressure due to long-t erm pool heatup until the ve ssel is depressurized and reflooded.

The ECCS will be initiated as the result of the 0.1 ft 2 break and will provide emergency cooling of the core. The operation of these systems is such that the reactor will be depressurized in approximately 600 sec. This will term inate the blowdown phase of the transient.

In addition, the suppression pool end of blowdown temperature will be the same as that of the recirculation line break because essentially the same amount of primary system energy is released during the blowdown. After reactor depressurization and reflood, water from the ECCS will begin to flow out the break. This flow will condense the drywell steam and C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-16 eventually cause the drywell and suppression chamber pressure s to equalize in the same manner as following a reci rculation line rupture.

The subsequent long-term suppre ssion pool and containment heat up transient that follows is essentially the same as for the recirculation line break.

6.2.1.1.3.3.5 Sm all Size Breaks.

6.2.1.1.3.3.5.1 Reactor System Blowdown Consideration. This section discusses the containment transient associated with small primary systems blowdowns. The sizes of primary system ruptures in this category are thos e blowdowns that will not result in reactor depressurization due either to loss of reactor coolant or automatic operation of the ECCS

equipment. Following the occurrence of a break of this size, it is assumed that the reactor operators will initiate an orderly plant shutdown and depressuriza tion of the reactor system.

The thermodynamic process associat ed with the blowdown of primary system fluid is one of constant enthalpy. If the primary system break is below the water level, the blowdown flow will consist of reactor water. Blowdown from reactor pressure to th e drywell pressure will flash approximately one-third of this water to steam and two-thirds will remain as liquid. Both phases will be at satura tion conditions corresponding to the drywell pressure.

If the primary system rupture is located so that the blowdown fl ow consists of reactor steam only, the resultant steam temperature in the containment is signifi cantly higher than the temperature associated with liquid blowdown. This is because the constant enthalpy depressurization of high pressure , saturated steam will result in superheated conditions inside containment.

A small reactor steam leak (resulting in superheated steam) will impose the most severe temperature conditions on the drywell structures a nd 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 temperatur e condition for the larger break is less. This is because the larger breaks will depre ssurize the reactor more rapidly than the orderly reactor shutdown that is assumed to terminate the small break. Like the main steam line break, the small steam line break is also governed by the dome pressure. The small break response is also governed by the operator actions. Since the vessel dome pressu re assumed for the original rated analysis (1055 psia) is unchanged by power uprate the initia l break flow rate fo r this event will be unchanged. Assuming the operator action is the same, the ev ent would be terminated in the same manner as for the original rated power analysis. Thus, the smal l steam line break was not reanalyzed for power uprate.

6.2.1.1.3.3.5.2 C ontainment Response. For drywell design consideration, the following sequence of events is assumed to occur. W ith the reactor and containment operating at the maximum normal conditions, a small break occurs that allows blowdown of reactor steam to the drywell. The resulting pressu re increase in the drywell will le ad to a high drywell pressure C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-07-011 6.2-17 signal that will scram the reactor and activate th e containment isolation system. The drywell pressure will continue to increase at a rate dependent on the size of the steam leak. The pressure increase will lower the water level in the vents until the level reaches the bottom of the vents. At this time, air and steam will start to enter th e suppression pool. The steam will be condensed and the air will be carried over to the suppression chamber free space. The air

carryover will result in a gradua l pressurization of th e suppression chamber at a rate dependent upon the size of the steam leak. Once all the drywell air is carried over to the suppression chamber, pressurization of the suppression chamber will cease and the system will reach an equilibrium condition. The drywell will contain only superheated steam and continued blowdown of reactor steam will condense in the suppression pool. The suppression pool temperature will continue to incr ease until the RHR heat exchanger heat removal rate is greater than the decay heat release rate.

6.2.1.1.3.3.5.3 R ecovery Operations. The plant operators will be alerted to the incident by the high drywell pressure signal and the reactor scram. For the purposes of evaluating the duration of the superheat condition in the drywell, it is assumed that thei r response is to shut the reactor down in an orderly manner while limiting the reactor cool down rate to 100

°F/hr. This will result in the reactor primary system being depressurized within 6 hr. At this time, the blowdown flow to the drywe ll will cease and the superheat c ondition will be terminated. If the plant operators elect to cool down and de pressurize the reactor primary system more rapidly than at 100

°F/hr, then the drywell superh eat condition will be shorter.

6.2.1.1.3.3.5.4 Drywell Design Temperature Consideration. For drywell design purposes, it is assumed that there is a blowdown of reactor steam for the 6-hr cool down period. The corresponding design temperature is determined by finding the combination of primary system pressure and drywell pressure that produces the maximum superheat te mperature. Drywell design temperature requirement s are defined by the most lim iting environmental conditions assumed to exist inside pr imary containment during a design basis accident (see Table 3.11-2

). As noted in Table 3.11-2 , the design temperature of 340°F is the superheat temperature based on a steam leak with the reactor vessel pressure of 400-500 psi and a design containment pressure of 45 psig.

6.2.1.1.3.4 Accident Analysis Models.

6.2.1.1.3.4.1 Short-Te rm Pressurization Model. The analytical models, assumptions, and methods used by GE to evaluate the containment response during the reactor blowdown phase of a LOCA are described in References 6.2-1 and 6.2-2.

6.2.1.1.3.4.2 Long-Term Cooling Mode. During the long-term, post-blowdown containment cooling transient, the ECCS flow path is a closed loop and th e suppression pool mass will be constant. This closed cooling loop provides subcooled water to the vessel from the suppression pool removing residual decay heat. As a resu lt long-term steaming w ill not occur. This approach is conservative since removal of energy by steaming would require that more energy

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-18 be retained in the vessel, and therefore, not re leased to the containmen t to maintain the vessel fluid inventory at saturation temperature. The cooling model loop is shown in Figure 6.2-19. There is no change in mass storage in the system (the RPV is reflooded during the blowdown phase of the accident).

The break flow area is assu med to remain constant as a function of time following decompression of the broken line and/or closure of the MSIV during the first few seconds of the reactor blowdown.

6.2.1.1.3.4.3 Analytical Assumptions. The key assumptions employed in the model are as follows: a. The drywell and suppression cham ber atmosphere are both saturated (100% relative humidity),

b. The drywell atmosphere temperature is equal to the temperature of the coolant spilling from the RPV or to the spray temperature if the sprays are activated,
c. The suppression chamber atmosphere temperature is equal to the suppression pool temperature or to the spray temper ature if the sprays are activated, and
d. No credit is taken for heat losses from the primary containment or to the containment internal structure.

6.2.1.1.3.4.4 Energy Balance Consideration. The energy balance in the suppression pool is described in References 6.2-1 and 6.2-2.

6.2.1.1.4 Negative Pre ssure Design Evaluation

Columbia Generating Station doe s not have automatic initiation of any drywell spray and controls operation of the sprays through procedural guidance.

The design and sizing of the reactor building to wetwell (RB-WW) and wetwell to drywell (WW-DW) vacuum breakers considered inadvertent operation of containment sprays as limiting transients. Although this is conservative for design considera tions, inadvertent spraying of the drywell is considered more than one single failure or operator error.

The limiting transient for the WW-DW vacuum breaker system for design purposes was considered to be simultaneous operation of both drywe ll spray loops after a large-break LOCA.

Although this event is bounding fo r design purposes, it is based on more than one single failure or operator error and neglects the consideration for adequate co re cooling by us ing both RHR loops. Using the single-failure criterion and considering the need for adequate core cooling following a large-break LO CA, the containment sprays would not be initiated until later in the event by spraying WW first followed by DW with the worse single failure being a RB-WW C OLUMBIA G ENERATING S TATION Amendment 62 F INAL S AFETY A NALYSIS R EPORT December 2013 LDCN-12-036 6.2-19 vacuum breaker to open. This scenario is non limiting with respect to floor uplift or negative pressure.

The limiting transient for negativ e containment pressurization is a small-break LOCA with a coincident single failure of an RB-WW vacuum breaker. Th is transient uses both WW and DW sprays of a single RHR loop. WW/DW sprays are initiated when required by the Emergency Operating Procedures. The sma ll break within the drywell forces the noncondensables into the wetwell airspace, leaving a steam atmos phere inside the drywell. Once drywell sprays are initiated, pressure rapidly drops and the RB-WW and WW-DW vacuum breakers open to mitigate the transient.

The analysis performed to determine peak ne gative pressure after a small-line-break LOCA made the following conservative assumptions:

a. Maximum spray flow of 8100 gpm (combined drywell and wetwell flow),
b. 100% spray efficiency,
c. 40F spray temperature, d. Noncondensable gases are purged into the wetwell as a result of the LOCA,
e. The drywell is full of steam at a pressure above wetwell due to the hydrostatic head from downcomer submergence, and
f. Single failure of RB-WW vacuum breaker.

The initial conditions used in the analysis are provided in Table 6.2-19. A summary of the results is provided in Table 6.2-19a. This analysis was evaluated as part of reactor power uprate, but a change to the initial assumption of reactor power at 3702 MWth did not change the results.

Drywell spray is not required to maintain the primary containment below design pressure nor is it required for containment cooling. If, following a small-line-break LOCA, the noncondensable gases are purged into the wetwell airspace, th e EOPs would direct the operator to initiate wetwell sprays to control wetwell pressure. If containment pressure continues to increase, drywell sprays will be initiated. The approp riate plant procedures direct the operator to initiate drywell sprays in response to indicatio ns of significant fuel failures during a LOCA. For the scenario in which containment sprays are initiated, the limiting single failure (or operator error) would be the failure of a RB-WW vacuum breaker. The results of the analysis indicate that the maximum negative pressure differential will be less than 2.0 psid and within the design values as stated in Section 6.2.1.1.2(c).

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-20 Multiple valve failure is not c onsidered or expected. The analysis considers two WW-DW vacuum breakers initially out of service, in addition to the single failure of the RB-WW vacuum breaker, to preclude unnecessary shutdowns due to failure of the testing mechanism or position indication. Failure of the testing mechan ism is considered more probable than failure of the vacuum breakers to open. It should al so be noted that a si ngle failure of a RB-WW vacuum breaker is more limiting than the single failure of a DW-WW vacuum breaker.

6.2.1.1.5 Suppression Pool Bypass Effects

6.2.1.1.5.1 Protecti on Against Bypass Paths. The pressure boundary between drywell and suppression chamber including the vent pipes, vent header, and downcomers is fabricated, erected, and inspected by nonde structive examination met hods in accordance with the applicable ASME Codes. The de sign pressure differential for th is boundary is 25 psid, which is substantially greater than conditions during a DBA. Actual peak accident differential pressure across this bounda ry is provided in Table 6.2-5.

Penetrations of this boundary except the vacuum breaker seats and vacuum breaker to downcomer flange are welded. The pene trations can be vi sually inspected.

Potential bypass leakage paths (such as the purge and vent system) have been considered.

Each path has at least two isolation valves in the leakage path during normal system lineup. These valves are leaktight containment isol ation valves which are all normally closed.

6.2.1.1.5.2 Reactor Blowdown Co nditions and Operator Response. In the unlikely event of a primary system leak in the drywell accompanied by a simulta neous open bypass path between the drywell and suppression chamber, several postulated conditions may occur. For a given primary system break area, the maximum allowable leakage capac ity can be determined when the containment pressure reaches the accident pressure at the end of reactor blowdown. The most limiting conditions would occur for those pr imary system break sizes which do not cause rapid reactor depressurization but rather have long leakage dura tion. These break sizes which are less than 0.4 ft 2 require operator action to terminate the reactor blowdown if there is a bypass path.

There would also be an increas e in drywell pressure which l eads to drywell venting to the wetwell by means of the downc omers. Both noncondensables and vapor are vented. If no bypass leakage exists, the maximum suppression chamber pressure would be 28 psig, the pressure resulting from displacing all containment noncondensables into the suppression chamber.

Operator action is required to mitigate the consequences of any bypass leakage. Emergency Operating procedures direct initiation of suppression chamber sp rays at a chamber pressure

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-21 less than the value analyzed in Section 6.2.1.1.5.4. Drywell sprays are initiated if the chamber pressure limit is exceeded.

Class 1E indication is availabl e in the control room allowing the operator to track chamber pressure. Additionally, a two-divi sion system of alarms is provided to alert the operator if the suppression chamber spray in itiation value is reached.

6.2.1.1.5.3 Anal ytical Assumptions. When calculating the allowable leakage capacities for a spectrum of break sizes, the following assumptions are made:

a. Flow through the postulated leakage pa th is pure steam. For a given leakage path, if the leakage flow consists of a mixture of liquid and vapor, the total leakage mass flow rate is higher but the steam flow rate is less than for the case of pure steam leakage. Since only th e steam entering the suppression chamber free space results in the additional c ontainment pressurization, this is a conservative assumption; and
b. There is no condensation of the leak age flow on either the suppression pool surface or the containment and vent syst em structures. Since condensation acts to reduce the suppression chamber pressure , this is a conser vative assumption.

For an actual containment there will be condensation, especially for the larger primary system break where vigorous agitation at the pool surface will occur during blowdown.

6.2.1.1.5.4 An alytical Results. The containment has been analyzed to determine the allowable leakage between the drywell and suppression chamber.

Figure 6.2-20 shows the allowable leakage capacity

()A/K as a function of primary syst em break area. The area of the leakage flow path is A, and K is the total geometric loss coefficient associated with the leakage flow path.

Figure 6.2-20 is a composite of two curves. If the break area is greater than approximately 0.4 ft 2, natural reactor depressurization will rapidly terminate the transient. For break areas less than 0.4 ft 2 , however, continued reactor blowdown limits the allowable leakage to small values.

Burns and Roe, Inc., confirme d the results of the above an alysis by GE in Reference 6.2-7. Further evaluation assigned the maximum allowable leak age capacity at A/

K= 0.050 ft

2. Since a typical geometric loss fa ctor would be three or greater , the maximum allowable flow path would be about 0.1 ft
2. This corresponds to a 4-in. line size.

A transient analysis using the CONTEMPT-LT (Reference 6.2-8) computer code was performed. The code was modified to include the mass and energy transfer to the suppression C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-22 pool from relief valve discharge. The limiting case was a very small reactor system break which would not automatically resu lt in reactor depressurization. For this limiting case, it was assumed that the response of the plant operators was to initiate the drywell sprays when the suppression chamber pressure exceed s 30 psig, and then to proceed to cool the reactor down in an orderly manner of 100

°F/hr cool down rate. Heat sinks considered were items such as major support steel inside cont ainment, the reactor pedestal, the diaphragm floor and support columns, and the steel and concrete of the primary containment. Base d on this analysis, the allowable bypass leak age used was 0.050 ft

2. The drywell pressure transient is shown in Figure 6.2-21 along with the corresponding curves of wetwell pressure, we twell temperature, and suppression pool temperature for th e original rated power condition.

The mandated allowable bypa ss leakage of 0.050 ft 2 is above the Technical Specifications containment bypass leakage limits.

Periodic testing is perf ormed to confirm that the containment bypass leakage does not exceed

()A/K = 0.0045 ft

2. Figure 6.2-22 presents the resulting containment transient of 0.0045 ft
2. The peak containment pressure shown in Figure 6.2-22 is well below the cont ainment design pressure.

An evaluation of this scenario with power uprate indicates that the time available for the operator to manually activate the containment spray is not significantly affected by power uprate. Therefore the effect of power uprate on the steam bypass event is determined to be insignificant.

6.2.1.1.6 Suppression Pool Dynamic Loads

A generic discussion of the suppr ession pool dynamic loads and asymmetric loading conditions is given in Mark II Dynamic Forcing Function Information Report, Reference 6.2-4. A unique plant assessment of these dynamic loads is made in Reference 6.2-5.

The impact of power uprate on the suppression pool dynamic loads defined in Reference 6.2-5 was evaluated for a power uprate to 102% of 110% of the original rated power (3323 MWt) and considering operation with extended load line limit analysis (ELLLA) and SRV out-of-service plus a setpoint tole rance increase to 3%. This evaluation confirmed that there are sufficient conservatism in the suppre ssion pool dynamic loads defined in Reference 6.2-5.

6.2.1.1.7 Asymmetric Loading Conditions

See Section 6.2.1.1.6.

6.2.1.1.8 Primary Containm ent Environmental Control

6.2.1.1.8.1 Temperature, Humidity, and Pressure Control During Reactor Operation. The drywell is maintained at its normal operating temperature 135

°F maximum average/150

°F maximum by the use of three lower containmen t coolers and two uppe r containment coolers

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-09-039 6.2-23 mounted in the drywell area.

The cooling coils for these units are supplied with water at 95°F, or less, from the reactor building closed cooling water system. There is no air cooling equipment in the wetwell since there is no h eat producing equipment and the air space is normally less than 95F. However, leakage past the sea ting surfaces of MSRVs may cause the wetwell air space temperature to increase due to heat transfer fr om the MSRV tailpipes to the wetwell atmosphere. In this case, the wetwell air space can be periodically cool ed by spraying with RHR to maintain wetwell air space temperatures at or below 117 F, the limit for equipment qualification.

The unit coolers are sufficient to control the temperature and humidity from all expected heat sources and leaks during normal r eactor operation. The containmen t purge system is not used to control containment temperature or humidity during reactor operation.

To relieve pressure during react or operation, the operator can establish a flow path from the drywell to the standby gas treatm ent (SGT) system through the drywell purge exhaust line.

After the first 24 hr of venting, and assuming the containment atmosphere does not contain unacceptable levels of radioactivity, venting can be valved to the reactor building exhaust

system. By opening the 2-in.

bypass valves around the purge exha ust valves rather than the purge exhaust valve, flow can be limited to 170 scfm. This fl ow is adequate for a drywell atmosphere temperat ure rise from 70F to 150°F in 3 hr while maintaining the primary containment at no greater than 0.5 psi above the reactor building pre ssure. The 2-in. bypass

valves would limit the radioactivit y released prior to valve clos ure to a very small amount in the unlikely event a LOCA occurs with the vent path open. If necessary, the wetwell can be vented in a similar wa y to relieve pressure.

The RB-WW and WW-DW vacuum breakers operate automatically to control containment vacuum.

6.2.1.1.8.2 Primary Containment Purging. The primary containment is provided with a purge system to reduce residual contamination and deinert the containment prior to personnel access.

This system is designed to produce a purge rate equivalent to three air changes per hour to the net free volume.

The drywell is purged of nitrogen for the scheduled refueling shutdown period and as required for inspection or maintenance.

The maximum drywell purge rate is 10,500 cfm. For the first 24 hr of a drywell purge, or if residual airborne contamination is higher than allowable limits for direct release to the atmosphere, the purge is routed through the SGT system. Purge air is taken from the reactor building ventilation s upply duct through two 30-in. normally closed isolation valves into the prim ary containment. The purged n itrogen is extracted from the drywell through two 30-in. normally closed isol ation valves and is routed to one of two systems. The discharge can be routed through a normally closed isolation valve to the reactor building exhaust air plenum or to the SGT system. If a high airborne activity occurs, C OLUMBIA G ENERATING S TATION Amendment 62 F INAL S AFETY A NALYSIS R EPORT December 2013 LDCN-12-041 6.2-24 the radiation monitors at the exhaust air plenum would cause the reac tor building ventilation and primary containment purge systems to isolate.

Provision is also made to purge the nitrogen from the suppression chamber section of the primary containment. Purge air is taken from the reactor building supply duct through two 24-in. normally closed isolation valves into the suppression chamber. The nitrogen is

extracted from the suppression chamber through two 24-in. normally closed isolation valves and routed to the exhaust air plenum or SGT sy stem in the same manner as the drywell purge exhaust. The systems are designed to pu rge either the drywell or the suppression chamber or the two chambers in series or in parallel. To protect the pres sure suppression function of the suppression pool, only one vent line and one purge line will be open at any one time during reactor operation.

Purge system operation during reactor operati on including startup, hot standby, and hot shutdown will be limited to inerting (through the purge system), deinerting, and pressure control. The containment purge system will not be used for temperature or humidity control during reactor operation.

All containment purge valves, including the 2-in. bypass valves, are designed to shut within 4 sec of receipt of a containm ent isolation signal and to shut against full containment design pressure. The containment isolation signals and the purge valves are part of the containment isolation system which is an ESF system. Ea ch purge line has two isolation valves. These valves are opened by allowing compressed air to oppose a spring in the valve actuator. The valve is shut on a loss of compressed air, loss of electrical signa l, or on a containment isolation signal. If the purge system is operating at the time of a LOCA, the system will automatically be secured. The level of the activity released through the purge system before isolation would be limited to the activity present in the coolant prior to the accident since the purge system will be isolated before any postulated fuel failure could occur. Dual isolation valves are also provided on the nitrogen inerting makeup piping connecting to the purge piping downstream of

the 30-in. and 24-in. isolation valves. The nitrogen inerting sy stem permits up to 75 cfh of nitrogen to be added to the containment dur ing reactor operation to compensate for the postulated leakage listed in Table 6.2-1. The 2-in. bypass valves, used for pressure control during operati ons, are located in parallel with each purge system exhaust valve. These 2-in. 150# globe valves meet the design requirements of the containment isolation system. They are designed to the same pressure/temperature ratings of the containment and purge valv es and are designed to close within 4 sec against the containm ent design pressure. All four bypass valves can be remotely operated from the control room; are designed to close on F, A, and Z isolation signals; and are operationally qualified against applicable seismic and hydrodynamic loads.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-25 6.2.1.1.8.3 Post-LOCA. The unit coolers are not required after a LOCA since heat removal is then accomplished by the containment cooli ng system, a subsystem of the RHR system. The Emergency Operating Procedures stipulate that nitrogen inerting is used as long as nitrogen is available. The operation of purge and vent transitions fr om oxygen control to hydrogen control upon loss of the ability to continue to inert with ox ygen levels increasing. The containment purge system has the capability for a controlled purge of the containment atmosphere to aid in atmospheric control, if necessary, in accordance with the guidance provided in the Emergency Operating Procedures.

Any equipment located inside the primary contai nment which is required to operate subsequent to a LOCA has been designed to operate in the worst anticipated accident environment for the required period of time.

6.2.1.1.9 Postaccident Monitoring

A description of the postaccident monitoring systems is provided in Section 7.5.

6.2.1.2 Containment Subcompartments

The subcompartments in the primary containm ent analyzed to determine the effects of subcompartment pressurization ar e the annulus between the sacr ificial shield wall and vessel annulus pressurization and the drywell head. For the power uprate evaluation, the limiting breaks in these two regions were analyzed considering reactor operation throughout the power flow map with power uprate, including final feedwater temperature reduction and single loop operation.

Peak subcompartment pressures occur very quickly (during th e first few seconds) during the limiting subcompartment pressurization events. Therefore, the pressurization is controlled by the initial break flow rates whic h are governed by the break size and location and the initial reactor thermal-hydraulic conditions, such as reactor pressure and enthalpy. The limiting

operating condition with power uprate with re spect to subcompartme nt pressurization was determined to occur at 3702 MWt, 102% of th e uprated power; therefore, the controlling parameters with power upr ate were compared to the original values at this condition. The comparison shows that there are negligible differences between the cont rolling parameters for the original conditions used as the basis for the annulus pressurization and drywell head pressurization analyses and the corres ponding parameters w ith power uprate (Reference 6.2-32). Therefore, the basis for the subcompartment pressurization loads is not affected by power uprate.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-26 Original Conditions (at 3463 MWt)

Power Uprate Conditions (at 3702 MWt)

Vessel dome pressure (psia)

1055 1055 Core inlet enthalpy (Btu/lbm)

532 532 Recirculation line break critical mass flux (lbm/ft 2-sec) 8900 8900 Feedwater enthalpy (Btu/lbm)

403 406 Feedwater line break critical mass flux (lbm/ft 2_sec) 19,300 19,200

The two areas within the primary containment considered to be subcompartments are the area within the sacrific ial shield wall and the ar ea above the refueling bulkhe ad plate at el. 583 ft.

Potential pipe breaks with in the sacrificial shield wall have been evaluate

d. The information is contained in References 3.8-5 , 3.8-6 , 3.8-7 , and 3.8-23.

Two analyses were performed based on original rated power (3323 MWt) to ensure the adequacy of the refueling bulkhead and inner refueling bellows at el. 583 ft. The first analysis, a break of the RCIC head spray line, determines the maximum downward loading due to pipe breaks. The second analysis, a break of the RRC suction line, determines the maximum upward loading.

Subcompartment analyses for a postulated high-energy pipe break in the primary containment were performed for the annulus inside the sacr ificial shield wall, a nd the regions above and below the bulkhead plate which divides the drywell into the upper head region and the lower region.

The analyses for the annulus were reported in References 6.2-9 through 6.2-11. The result of the case of a 60-node model of the shield wall annulus for pr essure transien t calculation was confirmed by the NRC, and the analysis was considered acceptab le for the shield wall base design and the design of the shield wall a bove the base, as stat ed in NRC letters (References 6.2-12 and 6.2-13).

Peak and transient loading used to establish the adequacy of the sa crificial shield wall, including the time/space depende nt forcing functions, are presented in References 6.2-9 through 6.2-11 and 6.2-34.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-27 These loads were used to produce response spectra for use in ev aluating secondary effects such as the dynamic effects on piping systems, equipment, and co mponents att ached to the sacrificial shield wall of the RPV. The fo llowing changes were made in the original assumptions used in the sacr ificial shield wall analysis:

a. The volume in the annulus was utilized to receive the blowdown, with the RPV installation volume conservatively assumed not to be available;
b. A finite time-dependent blowdown was used for the recirculation break utilizing NSSS supplier methodology (Reference 6.2-22). The effect of subcooling was taken into account; and
c. The feedwater pressurization analysis was developed utilizing blowdown values developed by computer analysis.

Annulus pressurization calculations are briefly summarized as follows:

a. Annular volume

The annular volume excluded RPV insula tion volume which is conservatively assumed not to be available.

This approach is cons ervative and more realistic than other analyses where only the a nnular volume on one side of the RPV insulation was available;

b. Finite time dependent blowdown

The blowdown loading values in Reference 6.2-11 were derived with the assumption that the pipe break would occu r instantaneously and that the annulus area would see the maximum blowdown at the same time. In actuality, the full flow from the severed pipe ends separate at a distance equal to one-half the pipe diameter. Movement occurs in a finite time and is a function of the stiffness characteristics of the pipe and the restraining capability of the pipe whip restraints.

Displacement versus time data for a finite break opening was developed and a GE analytical method was used for determining the short-term mass and energy release (Reference 6.2-22). The analysis was used for the recirculation loop break but not for the feedwater line si nce it was determined that the small percentage reduction for the feedwate r would not warrant the additional calculations; and

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-28 c. Feedwater break blowdown data The blowdown analysis for the postulated feedwater line break was based on a comprehensive model developed for the entire feedwater system from the condenser to the reactor vessel. Th is model, in conjunction with the RELAP4/MOD5 computer program (Reference 6.2-14), was used to calculate the transient and en ergy blowdown data.

Information pertaining to the analyses for the upper head and lower regions is as follows:

a. For the subcompartment analysis in the upper head region, the worst case is a double-ended guillotine break in the 6-in. RCIC line above the RPV head at approximately el. 595 ft. For the analysis in the lower region, the worst case is a double-ended guillotine break in the 24-in. recirculation line anywhere inside

the drywell. The pipe breaks were postulated for the subcompartment structural and component support designs;

b. The blowdown mass and energy release ra tes as functions of time for the 6-in. RCIC line break are shown in Tables 6.2-20 and 6.2-21. The blowdown mass and energy release rates as functions of time for th e 24-in. recirculation line break are shown in Tables 6.2-22 and 6.2-23;
c. The subcompartment analyses for the ca se of a 6-in. RCIC line break in the upper head region and the case of a 24-in. recirculation line break were performed with the Computer Code RELAP4/MOD5 (Reference 6.2-14). Figure 6.2-23 shows the nodalization scheme in the drywell.

Figure 6.2-24 depicts the plane view of vents in th e bulkhead plate and shows the sectional views and dimensions of the bulkhead vents;

d. The nodal volume data used for the anal ysis of a 6-in. RCIC line break in the upper head region and the an alysis of a 24-in. recirc ulation line break in the lower region is shown in Table 6.2-24. Table 6.2-25 shows the flow path data for the analysis of a 6-in. RCIC line break and Table 6.2-26 shows the flow path data for the analysis of a 24-in. recirculation line break;
e. Since there are no significant obstructions in the proximity of the pipe break considered in the analysis, significant pre ssure variation in a ny direction is not expected. The two-node model used for the analyses is considered to be adequate and a sensitivity study is not necessary;

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-29 f. There are no movable obstructions in th e vicinity of the vents. Insulation for piping and components was assumed to re main intact during the accident, and volume of insulation was subtracted from the nodal volumes;

g. The absolute pressure responses as a func tion of time in the upper head region and the lower region in the drywell are shown in Figure 6.2-25 for the case of a 6-in. RCIC line break and in Figure 6.2-26 for the case of a 24-in. recirculation line break.

Figures 6.2-27 and 6.2-28 represent the pressure differential across the bulkhead plate for the cases of a 6-in. RCIC line break and a 24-in. recirculation line break;

h. The peak differential pressure and the time of the peak for the cases of a 6-in. RCIC line break and a 24-in. r ecirculation line break are shown in Table 6.2-27
and
i. Peak and transient loading used to establish the adequacy of the sacrificial shield wall, including the time/space-dependent forcing func tions are contained in References 6.2-9 through 6.2-11 and 3.8-23. Peak and transient loading in other major compartments such as the drywell and the upper head region of primary containmen t were included in the basic design.

Since these compartments are large and relatively unencumbered, the loads are time-dependent but relatively uniform throughout. The tim e-dependent loads were applied as equivalent static loads, utilizing the appropriate dynamic loads factors. Following a LOCA, the refueling bulkhead would require requalification prior to use. This is acceptable because th e refueling bulkhead does not perform a safety-related func tion and would not become a missile during the postulated LOCA.

The analyses for the annulus are contained in References 6.2-9 through 6.2-11. Evaluation of potential pipe breaks within the sacrificial sh ield wall are in Reference 3.8-5 , 3.8-6 , 3.8-7 , and 3.8-23. 6.2.1.3 Mass and Energy Release Analyses for Postulated Loss-of-Coolant Accidents Where the ECCS enter into the determination of energy released to the containment, the single failure criterion has been applie d to maximize the energy releas e to the containment following a LOCA.

6.2.1.3.1 Mass and Energy Release Data

Table 6.2-9 provides the mass and enth alpy release data for the recirculation line break. Blowdown flow rates do not change significa ntly during the 24-hr period following the C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-30 accident.

Figures 6.2-29 and 6.2-30 show the blowdown flow rates for the recirculation line break. This data was employed in the DBA containment pressure-temperature transient analyses.

Table 6.2-10 provides the mass and enthalpy release data for the main steam line break. Blowdown flow rates do not change significa ntly during the 24-hr period following the accident.

Figure 6.2-31 shows the vessel blowdown flow ra tes for the main steam line break as a function of time after the postulated rupture. This inform ation has been employed in the containment response analyses.

6.2.1.3.2 Energy Sources

The reactor coolant system conditions pr ior to the line break are presented in Tables 6.2-3 and 6.2-4. Reactor blowdown calculations for containm ent response analyses are based on those conditions during a LOCA.

The energy released to the 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 the reactor structures, e. Energy being added by the ECCS pumps, and
f. Metal-water reaction energy.

All but the pump heat energy addition is discusse d or referenced in this section. The pump heat rate was used in evaluating the containment response to the LOCA and is conservatively selected as a constant input of 4890 Btu/sec to the system. The pump heat rate is added to the decay heat rate for inclusion in the analysis.

Following each postulated accident event, the stored energy in the reactor system and the energy generated by fission product decay will be released. Th e rate of release of core decay heat for the evaluation of the containment response to a LOCA is provided in Table 6.2-11 as a function of time after accident initiation.

Following a LOCA, the sensible energy stored in the reactor primary system metal will be transferred to the recirculating ECCS water a nd will, thus, contribute to the suppression pool and containment heatup.

6.2.1.3.3 Reactor Blowdown and Core Reflood Model Description

The reactor primary system blowdown flow an d core reflood rates were evaluated with the model described in References 6.2-1 and 6.2-2.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-31 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 fo llowing 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 provides

a discussion on the generation of metal-water hydrogen within the containment.

6.2.1.3.5 Thermal Hydraulic Data for Reactor Analysis Sufficient data to perform confirming thermodynamic evaluations of the containment has been provided within Section 6.2.1.1.3.3.

6.2.1.3.6 Long Term Coo ling Model Description

The long term cooling model is described in Section 6.2.1.1.3.4.

6.2.1.3.7 Single Failure Analysis

Containment analysis results assuming the worst single active failure are presented in Section 6.2.1.

6.2.1.4 Not applicable to BWR plants.

6.2.1.5 Not applicable to BWR plants.

6.2.1.6 Testing and Inspection

6.2.1.6.1 Structural Integrity Test

The test for structural integr ity is discussed in Section 3.8.

6.2.1.6.2 Integrated Leak Rate Test

Leak rate tests are conducted to verify that leakage out of the primary containment does not exceed 0.375% per day at 38 psig. Th is test is disc ussed in Section 6.2.6. 6.2.1.6.3 Drywell Bypass Leak Test

Tests are conducted, in accordan ce with the Technical Specifications, to verify that the drywell-wetwell bypass leakage does not exceed an equivalent leakage of A/K equal to 0.0045 ft 2. This is less than th e bypass leakage allowed.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-32 6.2.1.6.4 Vacuum Relief Testing

Tests are conducted in accordance with the Technical Specifications to verify the proper operation of the vacuum relief valves.

6.2.1.7 Required Instrumentation

The instrumentation required to mo nitor containment parameters a nd to initiate safety functions is discussed in Chapter 7.

6.2.2 RESIDUAL

HEAT REMOVAL CONT AINMENT HEAT REMOVAL SYSTEM

6.2.2.1 Design Bases

The RHR containment heat removal function is accomplished by the use of an operational mode of the RHR system. The purpose of this system is to prevent excessive containment temperatures and pressures, t hus maintaining containment in tegrity following a LOCA. To fulfill this purpose, the RHR containment cooling system meets the following safety design bases:

a. The system will limit the long term bul k temperature of th e suppression pool to 204.5°F when considering the energy additio ns to the containment following a LOCA. These energy additions, as a function of time, are provided in Section 6.2.1;
b. The single failure criterion applies to the system;
c. The system is designed to safety grade requirement s including the capability to perform its function following an SSE;
d. The system will remain operational during those envir onmental conditions imposed by a LOCA;
e. Each active component of the system is testable during normal operation of the nuclear power plant;
f. Minimum net positive suction head (N PSH) is maintained on the RHR pumps even with the containmen t at atmospheric pressure , the suppression pool at a maximum temperature, and postaccident debris entrained on the beds of the suction strainers; and

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-33 g. Withstands dynamic effect of pipe breaks inside and outside of containment (see Section 3.6). The primary containment unit coolers provi de for containment heat removal during nonaccident conditions. These coolers are not an ESF and no credit is taken for them during accident events.

6.2.2.2 Residual Heat Removal C ontainment Cooling System Design The RHR containment cooling system is an integral part of the RHR system. Water is drawn from the suppression pool, pumped through one or both RHR heat exchangers and delivered to the vessel, the suppression pool , the drywell spray header, or the suppression pool vapor space spray header.

Water from the SW system is pumped through th e heat exchanger tube side to remove heat from the process water. Two cooling loops are provided, each mechanically and electrically separate from the other to ach ieve redundancy. The process diagram including the process data from all design operating modes and conditions is provided in Section 5.4.

All portions of the RHR containment cooling system are designed to withstand operating loads and loads resulting from natural phenomena.

Construction codes and standards are covered in Section

3.2. Seismic

and environmental qualifications are discussed in Section 3.10 and 3.11 , respectively.

There are no signals which au tomatically initiate containm ent cooling; however, the SW system is automatically initiated by the same signals which star t up the ECCS.

The capacity of power sources, including the sta ndby diesels, is suffici ent to allow operation of the SW pumps simultaneously with the ECCS pumps. An ECCS pump need not be secured prior to starting RHR containment cooling.

To start RHR containment cooling after a LO CA resulting from a large break, the operator needs only to verify that the normally open RHR heat exchanger isolation valves are open and then shut the heat exchanger bypass valve. The rated contai nment cooling flow, 7450 gpm, can be achieved through the LPCI line, the dr ywell spray line, or through the test line and wetwell spray line, which direct s the heat exchanger discharge directly into the suppression pool. Thus, the design allows containment c ooling simultaneously with core flooding or containment spray. If the break size is small enough to limit reactor depressurization, the rated containment cooling flow cannot be established through the LPCI line. The operator must then direct the RHR containment cooling flow through the drywell spray line or through the test line; however, the operator must not divert LPCI flow away from the reactor until adequate core cooling is ensured. In a ddition, an electrical interlock prevents actuation of a drywell spray loop until the corresponding LPCI injection valve has been shut. A second electrical

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-34 interlock prevents actuation of drywell spray if there is no high drywell pressure signal present.

When allowed, the operator may start drywell spray by shutting the LPCI injection valve and then opening the drywell spray valves. Similarly, the operator ma y divert the flow directly to the suppression pool by shutting th e LPCI injection valve and then opening the test line valve.

Preoperational tests were perfor med to verify individual compone nt operation, individual logic element operation, and system operation up to th e drywell spray spargers. A sample of the sparger nozzles were bench tested for flow rate versus pressure drop to evaluate the original hydraulic calculations. The spargers were tested by air and visually inspected to verify that all nozzles were clear.

6.2.2.3 Design Evaluation of th e Containment Cooling System

The containment spray system is discussed in Section

5.4.7. Containment

spray is not required for heat removal.

In the event of the postulate d design basis LOCA, the short-term energy release from the reactor primary system will be dumped to the suppression pool. Th is will cause a pool temperature rise of approximately 56

°F in the short term. Subsequent to the accident, fission product decay heat will result in a continuing energy input to the pool. The RHR containment cooling system will remove this energy which is input to the primary containment system, thus resulting in acceptable suppression pool temperatures and containment pressures.

To evaluate the adequacy of the containment cooling system, the following sequence of events is assumed to occur.

a. With the reactor initially at 3702 MWt, 102% of uprated power, a LOCA occurs;
b. A loss of offsite power occurs and either Division 1 or 2 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 there being no offsite power and minimum onsite power; and
d. After 10 minutes it is assumed that th e plant operators shut the bypass valve on one RHR heat exchanger to start containment heat removal. Once containment cooling has been established, no fu rther operator acti ons are required.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-35 Each RHR pump suppression pool sucti on consists of a pipe "T" with a suction strainer at each end. During normal operation, some fiber and corrosion products have accumulated on the strainers. This accumulation is considered in the design of th e strainers, which will entrain additional debris following a LOCA. The potentia l for the additional ac cumulation of debris during a LOCA is discussed in Section

6.2.1. Wetwell

strainers are periodically cleaned to ensure that post-LOCA accumulation of debris on the strainer beds is within acceptable limits.

The relative locations of the RHR suction and retu rn lines in the suppression pool are shown in Figure 6.2-32. Mixing in the pool is primarily accomplished by the vertic al and horizontal displacement between the suct ion and discharge line for a lo op. The structures in the suppression pool act as ba ffles and improve mixing. Vertic al thermal stratification in the suppression pool is prevented by locating the discharge lines above the suction lines.

Required operator actions are minimal. Even without operator action, some heat removal will occur from the suppression pool to the spray po nds. The ECCS initiation signals start up both

SW and LPCI flow. The LPCI flow is primarily through the RHR heat exchanger bypass line

since the bypass valve is signaled to open. Since the heat ex changer isolation valves are normally open, some of the LP CI flow (approximately 40%)

will flow through the heat exchanger. It is estimated that for break sizes resulting in RPV depressuri zation and rated LPCI flow, the heat exchangers' duty with the partial shell side flow (i.e., no operator action) will be approximately 75% of the heat exchangers' duty with full shell side flow. Thus it is estimated that operator delays af ter a large break would result in only a moderate increase in suppression pool temperatures.

Summary of Containm ent Cooling Analysis

When calculating the long-term, post-LOCA pool temperature transient, it is assumed that the initial suppression pool temperature is at its maximum value and that the SW temperature is as described in Table 6.2-4 throughout the accident period. These assumptions maximize the heat sink temperature to which the containment heat is rejected and maximizes the containment temperature. In addition, the RHR heat exchanger is assumed to be in a fully fouled condition at the time the acciden t occurs. This conservatively mi nimizes the heat exchanger heat removal capacity. The resultant suppression pool temperat ure transient is described in Section 6.2.1 and is shown in Figure 6.2-12. Even with the degr aded conditions outlined above, the maximum uprate temperature is 204.5

°F, which is less than the original 220°F.

When evaluating this long-term suppression pool transient, all he at sources in the containment are considered with no credit taken for any h eat losses other than through the RHR heat exchanger. These heat sources are discussed in Section

6.2.1. Figure

6.2-13 shows the actual heat removal rate of th e RHR heat exchanger.

It can be concluded that the conservative evaluation demonstrates that the RHR system in the suppression pool cooling mode limits the post-DBA containment temperature transient.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-36 6.2.2.4 Tests and Inspections

The preoperational test program of the containment c ooling system is described in Sections 14.2.12 and 5.4.7. Operational testing is in accordance with the Technical Specifications.

6.2.2.5 Instrumentation Requirements The details of the instrumentation are provided in Chapter 7. The containment cooling mode of the RHR system is manually initiated from the control room.

6.2.3 SECONDARY

CONTAINMENT FUNCTIONAL DESIGN

The secondary containment system includes th e secondary containmen t structure and the safety-related systems provided to contro l the ventilation and cleanup of potentially contaminated volumes of the secondary containm ent structure following a DBA. This section discusses the secondary containment design. The SGT system is used to depressurize and clean the secondary containment atmos phere and is disc ussed in Section 6.5.1.

The secondary containment stru cture is synonymous with the reactor building. Sufficient openings exist among all areas of the reactor bu ilding to ensure that no significant long-term pressure gradients can exist within the secondary containment. In addition, with the exception

of the steam tunnel, there are sufficient vent areas in all confined or enclosed spaces such that pressure can be safely relieved into the rest of secondary cont ainment for all postulated pipe breaks within those spaces.

The steam tunnel runs through the reactor building and into the turbine generator building.

The portion of the steam tunnel within the reactor building is phys ically and func tionally part of the secondary containment during normal opera tion, expected transien ts, and all postulated accident events except for a pipe break within the steam tunnel. The steam tunnel relieves pressure through blowout panels which normally separate the turbine generator and reactor building portions of the steam tunnel.

6.2.3.1 Design Bases

The secondary containment structure completely encloses the primar y containment. The secondary containment provides an additional barrier to fissi on product release when primary containment is operable and prov ides the primary barrier during operations with the potential to drain the reactor vessel (OPDRV).

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-37 The secondary containment structure, in c onjunction with other secondary containment systems, provides the means of controlling and minimizing leakage from the primary containment to the outside atmosphere during a LOCA.

The reactor building pressure control system operates togeth er with the reactor building ventilation system during normal op eration to maintain building pr essure greater than or equal to 0.25 in. of vacuum water gauge as indicat ed at the reactor building el. 572 ft. During emergency operation the pressure control system operates together with the SGT system to maintain a vacuum in secondary containment at greater than or equal to 0.25 in. vacuum water gauge on all building surfaces. This ensures that leakage is into the se condary containment during normal and emerge ncy operation. Thus, all the reactor building ai r is either exhausted through the exhaust air plenum, where it is constantly monitore d, or discharged through the filtration units of SGT system. The reactor bu ilding pressure control system and the reactor building ventilation system are described in Section 9.4.

The secondary containment isola tion signals, secondary containmen t isolation valves, isolation valves for the reactor building ventilation system, SGT system, and react or building pressure control system are all designed to Seismic Ca tegory I, Class 1E requirements. The design bases loads for th e SGT system are given in Section

6.5.1. These

systems can be periodically inspected and functionally tested.

The secondary containment struct ure houses the refueling and reactor servicing equipment, the new and spent fuel storage fac ilities, and other reactor aux iliary or service equipment, including all or part of the reactor core isolation cooling system, reactor water cleanup demineralizer system, standby liquid control system, control rod drive (CRD) system equipment, the ECCS, SGT syst em, and electrical equipment components. The secondary containment structure protects the equipment fr om Seismic Category I di sturbances, the design basis tornado and tornado-gene rated missiles, and the design basis wind. The secondary containment structure is designed to meet the following design bases:

a. The reactor building is designed to meet Seismic Category I requirements;
b. The reactor building is designed a nd constructed in accordance with the structural design criteria presented in Section 3.8, and provides for low inleakage and outleakage dur ing reactor operation. Th e building is designed to limit the inleakage rate to 100% of the reactor building free volume per day when maintained at a negative buildi ng pressure of 0.25 in. of water;
c. The reactor building is designed to withstand applied wind pressures resulting from the design basis wind velocity, incl uding gusts of 100 mph at an elevation of 30 ft above grade. Th e pressure of the design basis wind velocity on the reactor building is discussed in Section 3.3; C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-38 d. The reactor building is designed to withstand pipe whip loads plus jet impingement of jet reaction loads due to high-energy pipe breaks outside primary containment;
e. The reactor building desi gn allows for periodic inspec tions and functional tests of the penetrations, ventilation system (i ncluding automatic is olation), pressure control system, and SGT system;
f. The reactor building is designed to withstand applied wind pressures resulting from the design basis tornado. The eff ects of the design basis tornado pressures on the structure are discussed in Section 3.3 and tornado-generated missiles are discussed in Section 3.5; and
g. The reactor building is designed for all probable combinations of the design basis wind and the design basis tornado velocities and associated differences of pressure within the structure and atmospheric pressure outside the structure.

6.2.3.2 System Design

See Figures 1.2-7 through 1.2-12 for general arrangement drawings of the reactor building.

Also see Figures 3.8-1 and 3.8-2. See Table 6.2-12 for the design and performance data for the secondary containment structure.

The major design provisions that prevent primary containment leakage from bypassing the SGT system, except for thos e lines identified as poten tial bypass leakage paths in Table 6.2-16 , are the reactor building pressure control system, the reac tor building ventilation isolation system, the isolation signals, and the standby power system.

Normal reactor building ventilation system is not required to ope rate during accident conditions. The system is automa tically shut down and the SGT system started in the event of any of the following isolation signals:

a. Reactor vessel low-low water level,
b. High drywell pressure, and
c. High radiation level in the reactor building exhaust air plenum.

All ventilation system penetrations of secondary containment (except those of the SGT system) are fitted with two fail-closed, air-operated butterfly dampers in series. All dampers automatically close on any one of the isolation signals.

Penetrations of the secondary containment asso ciated with the SGT sy stem are fitted with two motor operated butterfly va lves in series. The motor ope rated valves, which are powered

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-39 from the essential power buses , are opened automatic ally, and the SGT system is started by any of the signals which isolat e the secondary containment.

Penetrations of the reactor building are designed with leakage ch aracteristics consistent with leakage requirements of the entire building.

Entrance to the reactor building is through interlocking double door pe rsonnel air locks. Entrance to the reactor building vehicle air lock (railroad bay) is through an interlocking air lock system.

The storage/receiving area for casks is the vehicle air lock (railroad bay). The vehicle air lock (railroad bay) is completely within and along the south side of the reactor building at el. 441 ft.

One of the interlocked doors is the exterior vehi cle door at the east end of the vehicle air lock, and the other interlocked door is the interior person door at th e west end of the vehicle air lock. There are also two hatche s that are interlocke d with the vehicle ai r lock entrance doors.

All entrances to the reactor bu ilding are through interl ocking double door air lock systems and, therefore, building ingress and egress do not jeopardize the integrity of the secondary containment. All openings such as personnel doors leading into the secondary containment are under administrative control and are provided with position indi cation and alarm in the main control room if they are not closed after the time allowed for ingress/egress. An exception is an access hatch which has been provided in one of the steam tunnel blowout panels. When not in use, the hatch is secured closed by security bolts and padlocks. Another exception is the CRD rebuild room drop chute which is used to dispose of contaminated CRD components.

The drop chute penetrates the reactor building floor at el.

471 ft and becomes a part of secondary containment when the vehicle air lo ck (railroad bay) exte rior doors are open.

A valve at el. 501 ft allows CRD components (e.g., filters) to be dropped down the chute without breaching secondary containment.

The reactor building pressure control system is designed to elim inate fluctuations in reactor building pressure by such factor s as wind gusts. Reactor building pressure is indicated and recorded in the main control room and loss of negative pressure is alarmed.

The reactor building pressure control system automatically maintains a subatmospheric pressure in the reactor building by monitoring the differentia l pressure between the reactor building interior and the extern al atmosphere. The differen tial pressure is monitored by eight differential pressure transmitters, four in each division, which measure the differential pressure between the internal reactor building and each of the four external sides of the reactor building. The signal which indicat es the least differential pressure controls the position of the blades in the normal reactor building exhaust fan units. In the event of reactor building isolation, the reactor building pr essure control system controls reactor building pressure by SGT system fan flow.

Piping that connects to primary containment an d passes through secondary containment is not considered a potential secondary containment bypass leak path if isolated by blind flanges.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-40 Condensate from the condensate storage tanks can be used to flush ECCS and RHR shutdown cooling lines. Blind flanges ar e installed in the condensate sy stem at spool piece COND-RSP-4 and in the RHR system downstream of RHR-V-108 and RHR-V-109 and at spool piece RHR-RSP-1 to isolate potential se condary containment bypass leak paths. The spool pieces are installed to comply with the piping suppor t analyses. The spool pieces COND-RSP-1, COND-RSP-2, COND-RSP-3, COND-RSP-5, and COND-RSP-6 are connected to the condensate piping with blind fla nges at the other end. If co nnected to the corresponding RHR lines, blind flanges would be necessary to is olate potential secondary containment bypass leak paths. Table 6.2-16 presents a tabulation of primary contai nment process piping penetrations. The lines that penetrate both the primary and secondary containment were evaluated for potential bypass leakage paths as summarized in Table 6.2-16. The guidance of the NRC Branch Technical Position Containment Systems Branch (BTP CSB) 6-3 (Reference 6.2-40) were addressed in considering potentia l bypass leakage paths. Designs provided to prevent through-line leakage are dependent on whether the working fluid in the associated system is gaseous or liquid. Lines that vent (gaseous release) into the reactor bu ilding, will be treated by the SGT system. Lines that penetrate primary and sec ondary containment that normally contain water provide a water seal between the primary containment and the environment upon the primary isolation valve closure. If a br eak were to occur in the lines, the water or gas would evacuate into the reactor building, and any leakage through the failed line would be collected by the floor drain system or processed by the SGT sy stem. Some lines that penetrate both the primary and secondary containment are seis mically qualified outside of the secondary containment. These lines are considered closed systems and are not categorized as potential bypass paths. Lines that penetr ate the primary and secondary c ontainment are contained in one or more of the categories listed below.

a. Operate post-LOCA at pressure higher th an the primary containment pressure or are seismically qualified.
b. Are vented to the secondary containment.
c. Are provided with water seal assess ed against primary containment valve leakage characteristics.

Therefore, the primary containm ent isolation valve leak rate tests and SGT system operability tests are adequate to ensure th at bypass leakage will not occur and separate leakage testing of the secondary containment isola tion valves is not required. An add itional conservative assumption of secondary containment bypass leak age of 0.04% volume pe r day, the secondary containment bypass limit, for the first 24 hr and 0.02% volume per day after 24 hr was included in dose consequence analyses in Chapter 15. The analyses demonstrated that the potential bypass leakage contribution from wate r lines to the dose consequences were negligible.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-41 The design and construction codes, standards, and guide s applied to the buildings and SSCs are discussed in Chapter 3.

6.2.3.3 Design Evaluation

The SGT system will maintain th e secondary containment at a nega tive pressure with respect to the external environment following the design basis loss-of-c oolant accident. The design flow rate of the exhaust system is based on the following criteria:

a. The rate of in-leakag e assumption in based on th e 100% of the secondary containment volume per day.
b. The exhaust flow rate is based on maintaining containment vacuum greater than or equal to 0.25 in. of vacuum water gauge.

The SGT system is described in Section 6.5.

6.2.3.3.1 Calc ulation Model

The parametric analysis of secondary containment res ponses following a LOCA were performed using the general purpose thermal-hydraulic computer program GOTHIC (Reference 6.2-39). The GOTHIC program solves cons ervation of mass, momentum, and energy equations for multi-compone nt, multi-phase flows. The phase balance equations are coupled by mechanistic models fo r interface mass, momentum, and energy transfers that cover the entire flow regime as well as single-phase flows.

Aspects of the reactor building taken into consideration for the model include:

a. Heat loads modeled in the re spective rooms (multiple volumes), b. Heat transfer for primary to secondary containment (negligible), c. Heat transfer between secondary containment and the outside environment, d. Heat transfer between rooms and react or building floors (multiple elevations), e. Room cooler efficiency, and f. Secondary containm ent relative humidity.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-42 6.2.3.3.2 Results

A series of parame tric studies were performed to evaluate varying meteorological conditions and heat loads on the drawdown analyses. Repr esentative temperature and pressure response curves are provided as Figures 6.2-34 and 6.2-35. These analyses are based on the following:

PARAMETER VALUE a) The reactor building was modeled using lumped parameter volumes totaling Approximately 3,500,000 ft 3 b) Exhaust rate during drawdown 4800 cfm c) Secondary containment in leakage rate 2430 cfm d) Initial reactor buildin g temperature range 50°F to 75°F e) Outside temperature range 0°F to 94°F f) Wind speeds range 0 mph to 17 mph The drawdown analyses for secondary containment determined that the SGT system can establish and maintain the seconda ry containment pressure at le ss than 0.25 inches of vacuum water gauge within 20 minutes.

6.2.3.4 Tests and Inspections.

Components of the SGT system ar e tested periodically to ensure operability. The capability of the SGT system to maintain the secondary containment operability is tested in accordance with Technical Specifications. Test s are performed by isolating the secondary containment and starting either of the two SGT units. Design pressure is maintained in the secondary containment by operation of one SGT unit for a period of 1 hr. During the test, flow measurements of the SG T system and differential pressure measurements of the secondary containment are taken. If duri ng testing the SGT system fail s to maintain the secondary containment pressure at 0.25 inch es of water gauge or greater below atmospheric pressure at or below an SGT system air flow rate of 2240 cf m, the reactor building is visually inspected for leakage paths. Leakage paths are repaired permanently (no temporary sealing mechanisms such as tape are used), and the tests are repeated until the acceptance level is met.

Tests are limited to 1 hr becau se isolation of the secondary containment necessitates the shutdown of the normal reactor building ventilati on system which is re quired for the operation of non-ESF equipment housed in the secondary containment.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-43 6.2.3.5 Instrumentation Requirements

Secondary containment negative pr essure is automatically main tained by the reactor building pressure control system. Duri ng normal operations, this system controls the position of the blades in the normal reactor building exhaust fan units. During accident conditions, the SGTS is started and the secondary containment is isolated by the primary containment and reactor vessel isolation control system. Under this condition, the system controls reactor building negative pressure by controlling the SGT system fans.

Descriptions of the instrument ation and controls for the reactor building pressure control system, primary containment and reactor vessel isolation contro l system, and SGT system are contained in Section 7.3.1. The analyses are described in Section 7.3.2. 6.2.4 CONTAINMENT ISOLATION SYSTEM

6.2.4.1 Design Bases

Safety Design Bases

a. Isolation valves provide for the necessary isolation of the containment in the event of accidents or other conditions wh en the unfiltered release of containment contents cannot be permitted,
b. Capability for rapid closure or isolati on of all pipes or ducts that penetrate the containment is achieved by means that provide a containment barrier in such pipes or ducts sufficient to maintain leakage within permissible limits,
c. The design of isolation valving for line s penetrating the containment follows the requirements of General Design Criteria (GDC) 54 through 57 as noted in Table 6.2-16 ,
d. Isolation valving for instrument lines which penetrate the c ontainment conforms to the requirements of Regulatory Guide 1.11, Revision 0,
e. Isolation valves, actuators, and controls are protected against loss of safety function by missiles,
f. The design of the containment isolat ion valves and associated piping and penetrations is to Seismi c Category I requirements,
g. Containment isolation va lves and associated piping and penetrations meet the requirements of the ASME Boiler and Pressure Vessel Code,Section III, Classes 1 or 2, as applicable, and C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-44
h. Containment isolation valve closure lim its radiological effects from exceeding established require ments (10 CFR 50.67), incl uding the effects of sudden isolation valve closure.

The primary objective of the containment isolat ion system is to provide protection against releases of radioactive material s to the environment as a result of accide nts occurring to the nuclear boiler system, auxiliary systems, and support systems. This objective is accomplished by automatic isolation of appropria te lines that penetrate the cont ainment system. Actuation of the containment isolation systems is au tomatically initiated at specific limits.

The containment isolation systems, in general, close those fluid lines pene trating containment that support systems not required for emergenc y operation. Those fl uid lines penetrating containment which support ESF systems have re mote manual isolation valves which may be closed from the control room.

Redundancy and physical se paration are required in the electr ical and mechanical design to ensure that no single failure in the containment isolation system prevents the system from performing its in tended functions.

The isolation system is desi gned to Seismic Category I. Cl assification of equipment and systems is shown in Table 3.2-1.

Actuation of the containment isolation systems is initiated by the signals listed in Table 6.2-16.

The criteria for the design of the containment and reactor vessel isolation control system are listed in Section 7.3.1 and Table 7.3-5. The bases for assigning certain signals for containment isolation ar e contained in Section 7.3.1.

On signals of high drywell pressure or low-low water level in the reactor vessel, isolation valves that are part of systems not required for emergency shutdown of the plant are closed.

The same signals will initiate the operation of systems associated with the ECCS. The isolation valves which are part of the ECCS may be closed remote manually from the control

room or can clos e automatically.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-45 6.2.4.2 System Design

The general criteria governing the design of the containment isolation sy stems is provided in Sections 3.1.2 and 6.2.4.1. Table 6.2-16 summarizes the contai nment penetrations and contains information pertaining to:

a. Open or closed status under normal operating conditions and accident situations, b. Primary and secondary modes of actuation provided for isolation valves,
c. Parameters sensed to initiate isolation valve closure, d. Closure time for principal isolation valves to secure containment isolation, and e. Applicable GDC.

Protection is provided for isola tion valves, actuators, and c ontrols against damage from missiles. All potential sources of missiles are evaluated. Where possible hazards exist, protection is afforded by separation, missile shields, or by location. See Section 3.5 for a discussion of eval uation techniques.

Isolation valves are designed to be operable under the most adverse environmental conditions (see Section 3.11) such as operation under maximum diffe rential pressures, extreme seismic occurrences, steam laden atmosphere, high te mperature, and high humidity. Electrical redundancy is provided fo r power-operated valves. Power for the actuation of two isolation valves in line (inside and outside of containm ent) is supplied by two redundant, independent power sources without cross ties. In general, outboard isolation valves receive power from a

Division 1 power supply while is olation valves within containment receive power from a Division 2 power supply. In ge neral, the supply is ac for Di vision 2 valves and dc for Division 1 valves depending on the system under consideration. The ability to provide

appropriate containment inte grity during a station blackout is discussed in Section 1.5.2.

The main steam line isolation valves are pneuma tic spring-loaded, pist on-operated globe valves designed to fail closed. The valves are held open by air pressure against spring force that will close or help close the valve in case of loss of power or air supply. Each main steam line isolation valve has an air accumulator to assist in its closure on loss of the air supply to the solenoid pilot valve. The separa te and independent acti on of either air pressure or spring force will close the outboard MSIV. The inboard MSIV will close on air or springs and air.

Air-operated valves (not applicable to air-testable check valves) close on loss of air, except the butterfly valves on the RB-WW vacuum breaker lines.

The design of the isolation valve system include s consideration of the possible adverse effects of sudden isolation valve closure when the plant systems are functioning under normal

operation.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-46 6.2.4.3 Design Evaluation

6.2.4.3.1 Introduction

The main objective of the containment isolation system is to provide protection by preventing releases of radioactive materi als to the environment. This is accomplished by complete isolation of system lines pene trating the primary containmen

t. Redundancy is provided to satisfy the design requirement th at any active failure of a sing le valve or component does not prevent containment isolation.

Mechanical components in process lines, such as isolation valve arrangements or extraordinary ex-containment system quality, are redundant and provide back-up in th e event of accident conditions. Instrument lines, in many cases, rely on a single mech anical barrier in the event of accident conditions. These isolation valve arrangements satisfy the requirements specified in GDC 54, 55, 56, and 57, and Regul atory Guide 1.11, Revision 0.

The arrangements with appropriate instrumentation are described in Table 6.2-16 and Figures 6.2-36 through 6.2-59. The isolation valves have redundancy in the mode initiation.

Generally, the primary mode is automatic a nd the secondary mode is remote manual.

A program of testing, described in Section 6.2.4.4, is maintained to ensure valve operability and leaktightness.

The design specifications require each isolation valve to be ope rable under the most severe operating conditions. Each isola tion valve is protected by separa tion and/or adequate barriers from the consequences of potential missiles.

Electrical redundancy is provide d in isolation valve arrangement s which eliminates dependency on one power source to attain isolation. Electrica l cables for isolation va lves in the same line have been routed separately.

Provisions are in place to control the position of nonpowered process line, vent, drain, and test connection valves that are containment isolation valves. These provisions meet the applicable requirements of GDC 55 and 56.

For power-operated valves, the position is indicated in the main control room. Discussion of instrumentation and controls for the isolation valves is included in Chapter 7.

6.2.4.3.2 Evaluation Agains t General Design Criteria

6.2.4.3.2.1 Evaluati on Against Criterion 55. The reactor coolant pressure boundary (RCPB) consists of the RPV, pressure retaining appurtenances attached to the vessel, and valves and pipes which extend from the RPV up to and includi ng the outermost isolation valve. The lines of the RCPB which penetrate the containmen t include provisions for isolation of the containment, thereby precluding a ny significant release of radioac tivity. Similarly, for lines C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-47 which do not penetrate the containment but wh ich form a portion of the RCPB, the design ensures that isolation of the reacto r coolant pressure can be achieved.

6.2.4.3.2.1.1 Influent Lines. Influent lines which penetrate the primary containment and connect directly to the RCPB are equipped with at least two is olation valves, one inside the drywell and the other as close to the external side of the containment as practical.

Table 6.2-16 contains those influent pipes that comprise the RCPB and penetrate the containment.

6.2.4.3.2.1.1.1 Feedwater Lines. The feedwater lines are part of the RCPB as they penetrate the drywell to connect with the RPV. The isol ation valve inside the drywell is a swing check valve, located as close as practicable to the containment wall. Outside the containment another swing check valve is located as close as practicable to the containment wall and farther away from the containment is a motor-operated gate valve. Should a break occur in the feedwater line, the check valves prevent significant loss of reactor coolant inventory and offer immediate isolation. The design allows the condensate and condensate booste r pumps to supply feedwater to the vessel through a bypass line around the reactor feed pumps (which are tripped on a loss of steam supply) as soon as th e vessel is partially depressu rized. For this reason, the outermost gate valve does not automatically is olate upon signal from the protection system. The gate valve meets the same environmental a nd seismic qualifications as the outside check valve. The valve is capable of being remotely closed from the control room to provide long-term leakage protection in the event that feedwater makeup is unavailable or unnecessary. In the control room, the operator can determine if makeup from the feedwater system is unavailable by the use of the feedwater flow indicator which will show high flow for a feedwater pipe break, or no flow for a feedwater pump trip.

The operator can also determine if makeup from the feedwater system is unnecessary by verifying that the ECCS is functioning properly and the reactor wa ter level is being adequately maintained. The ECCS operation signals and reactor vessel water level indication are provided in the control room.

There is no need to spec ifically alert the operator to isolate the feedwater lines other than as described above since the lines both have check valves. Howe ver, for long-term isolation purposes, the operator may close the motor-operated gate valves at any time.

Emergency procedures require the operator to close reactor feedwater block valves within 20 minutes following cessation of fe edwater flow. No credit is taken for feedwater flow in assessing core and contai nment response to a LOCA.

The applicable generic anticip ated transients without scra m (ATWS) studies (References 6.2-23 and 6.2-24) assumed the use of turbine driven feed pumps and simu lated the loss of steam to the turbine and feedwater flow in the most limiting case in which all main steam lines were

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-48 isolated. In the ATWS situati on, the loss of feedwater flow (o r limiting of the flow to near zero) causes a decrease in core flow and inlet subcooling which results in a power reduction.

This leads to a benefit in mitigating the peak vessel pressure, containment pressure and suppression pool temperature.

6.2.4.3.2.1.1.2 High-Pressure Core Spray Line. The HPCS line penetrates the drywell to inject directly into the RPV.

Isolation is provided by a check valve located inside the drywell, and a remote-manually actuated gate valve located as close as practicable to the exterior wall of the containment. Long-term leakage control is maintained by this gate valve. If a LOCA occurred, the gate valve would receive an automatic signal to open.

6.2.4.3.2.1.1.3 Low-Pressu re Coolant Injection Lines. Satisfaction of isolation criteria for the three LPCI injecti on lines of the RHR syst em is accomplished by use of remote-manually operated gate valves and check valves. Both types of valves are normally closed with the gate valves receiving an automatic signal to open at the appropriate time to ensure that acceptable fuel design limits are not exceeded in the event of a LOCA. The check valves are located as close as practicable to the RPV. The normally closed check valves protect against overpressurization in the reactor coolant pressure boundary (RCPB) by preventing high-pressure reactor water from entering the RHR system low pressure piping. When the reactor pressure is lower than the RHR system pre ssure, the low energy of the influent fluid (220°F maximum) can open the check valve and inject water into the reactor.

6.2.4.3.2.1.1.4 Control Rod Drive Lines. The CRD system insert and withdraw lines penetrate the drywell. The classification of these lines is Code Group B and they are designed in accordance with ASME Section III, Class 2. The basis to which the CRD insert and withdraw lines are designed is commensurate with the safety importance of maintaining pressure integrity of these lin es. The Hydraulic Control Unit s (HCUs) and scram discharge headers as well as the hydraulic lines are Seismic I, and are qualified to the appropriate accident environment. The fa ilure and scram position of all power operated valves are compatible with system isolation and, at the same time, rod insertion on a scram.

The inboard isolation of insert and withdraw lines for the primary containment is provided by the double seals in the control rod drives and the outboard isolation for the primary containment is provided by valves within th e HCUs. The HCU manua l isolation valves 101 and 102 are provided for positive isolation in th e unlikely event of a pipe break within the HCU. Additional isolation is provided by normally closed, fail-closed, solenoid operated Directional Control Valves (DCV) in the HCUs (see Figure 4.6-5

). The DCVs open only during routine movement of their associated control rod and during a reactor scram. In addition, a ball check valve loca ted in the CRD flange housing au tomatically seals the insert line in the event of a break.

Insert and withdraw lines that extend outside the primary containment are small and terminate in the Reactor building which is served by the SGT system.

Containment overpressurization

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-49 will not result from a line break in containment since these lines contain small volumes at low energy levels. External leak detection of CRD piping outside of primary containment is provided by operations during routing routine inspections.

Two Quality Class I check valves in series (C RD-V-524/525) are located at the discharge of the CRD pumps to prevent signifi cant bypass leakage through the Quality Class II CRD piping to the condensate storage tank that could result if any leakage past the HCU were to exist. If the Quality Class II CRD piping breaks between the check va lves and the CRD HCUs, the SGT system will process the effluent prior to release from sec ondary containment. Thus, the potential bypass path by means of this CRD path is minimized to prevent any significant offsite consequence.

The NRC staff concluded in NUREG-0803, "Safety Evaluation Re port Regarding Integrity of BWR Scram Systems," that although the CRD system represents a departure from GDC 55, the CRD containment isolation provision st ated above is considered acceptable.

6.2.4.3.2.1.1.5 Residual Heat Removal and Reactor Core Isolation Cooling Head Spray Lines. The RHR head spray and RCIC lines meet outside the containment to form a common line which penetrates the drywell and discharges directly into the RPV. The check valve inside the drywell is normally closed. Th e check valve is located as close as practicable to the RPV. Two remote-manual block valves are utilized as isolation valves located outside the containment. The check valve ensures immediate isolation of the containment in the event of a

line break. The block valve on the RHR line receives an automatic isolation signal while the block valve on the RCIC line is remote manua lly actuated to provid e long-term leakage control.

6.2.4.3.2.1.1.6 Standby Liquid Control System Lines. The standby liquid control system line penetrates the drywell and connects to the HPCS system injection line. In addition to a check valve inside the drywell, a parallel pair of explosive actuated valves are located outside the drywell. Since the standby liquid control line is a normally closed, nonflowing line, rupture of this line is extremely remote.

The explosive actuated valves function as outboard isolation valves. These valves provide a seal for long-term leakage control as well as preventing leakage of sodium pentaborate into the RPV during SLC system testing.

6.2.4.3.2.1.1.7 React or Water Cleanup System. The RWCU pumps, heat exchangers, and filter demineralizers are locat ed outside the drywell. The return line from the filter demineralizers connects to the feedwater line outside the contai nment between the block valve and the outside containment feed water check valve.

Isolation of this line is provided by the feedwater system check valve inside the containment, the feedwater syst em check valve outside the containment, and an RWCU motor-operated gate valve outside the containment. The motor-operated gate va lve functions as a th ird isolation valve.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-50 During the postulated LOCA, it may be desirable to restore reactor coolant cleanup. For this reason, the motor-operated gate valve in the RWCU return line does not automatically isolate upon a containment isolation signa

l. If reactor coolant cleanup is not required, the return isolation valve RWCU-V-40 can be shut remotely from the cont rol room when the motor-operated feedwater block valves are closed 20 minutes or more after the beginning of a LOCA. Should a break occur in the reactor wate r cleanup return line, the check valves would prevent significant loss of inventory and o ffer immediate isolation, while the outermost isolation valve would provide long-term leakage control.

6.2.4.3.2.1.1.8 Recirculati on Pump Seal Water Supply Line. The recirculation pump seal water line extends from the r ecirculation pump through the dr ywell and connects to the CRD supply line outside the primary containment. The seal water lin e forms a part of the RCPB.

The recirculation pump se al water line is Code Group B from the recirculation pump through the outboard motor operated isolation valve. From this valve to the CRD connection the line is Code Group D. Should this line fail, the flow rate thr ough the broken line has been calculated to be substantially less than that experienced by a broken instrument line.

6.2.4.3.2.1.1.9 Low-Pr essure Core Spray Line. The LPCS line penetr ates the drywell to inject directly into the RPV.

Isolation is provided by a check valve located inside the drywell and a remote-manually actuated gate valve located as close as practicable to the exterior wall of the containment. Long-term leakage control is maintained by this gate valve. If a LOCA occurs, this gate valve will receive an automatic signal to open, delayed only by control circuitry that ensures that the fluid pressure in side the RPV is less than the design pressure of the piping.

6.2.4.3.2.1.1.10 Residual Heat Removal Shutdo wn Cooling Return Lines. The two shutdown cooling return lines inject in to the RRC lines downstream of the RRC pumps. Isolation is accomplished by a normally-closed, motor-operated gate valve outside containment and the parallel arrangement of a full-flow check valve and a normally closed, partial-flow, motor-operated gate valve inside the containment. Both motor-operated valves receive signals to close if RHR system water is needed to support the ECCS mode of the RHR system.

6.2.4.3.2.1.2 Effluent Lines. Effluent lines which form pa rt of the RCPB and penetrate containment are equipped with at least two isol ation valves; one inside the drywell and the other outside, located as close to the containment as practicable.

Table 6.2-16 also contains those effluent lines that comprise the RCPB and which penetrate the containment.

6.2.4.3.2.1.2.1 Main Steam, Main Steam Drain Lines, and Residual Heat Removal/Reactor Core Isolation Cooli ng Steam Supply Lines. The main steam lines ex tend from the RPV to the main turbine and condenser syst em, and penetrate the primary containment. Isolation is afforded inside by a normally-open, fail-close, automa tic, air-operated, y-pattern globe valve

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-51 and outside by a similar in-line globe valve paralleled by smaller au tomatic motor-operated gate valves, one each in the between-MSIV drain line and in the MSLC system tap (isolated - MSLC system is deactivated). The main steam drain line, whic h comes off a common manifold tapping off each main steam line just upstream of each inside MSIV, also penetrates the containment and is isolated by automatic motor-operated gate valves, one inside the containment and one outside th e containment. The RHR steam supply line and RCIC turbine steam line connect to the main steam line inside the drywe ll and penetrate the primary containment. For these lines, isolation is pr ovided by automatically actuated block valves, two parallel valves inside the containment co mmon to both the RHR steam supply line and the RCIC turbine steam line, and one for each line just outside the containment. The outside RHR steam supply line isolation valve has been deac tivated and locked in the closed position.

6.2.4.3.2.1.2.2 Recircula tion System Sample Lines. A 0.75-in. diameter sample line from the recirculation system penetrates the drywell a nd is designed to ASME,Section III, Class l.

A sample probe with a 1/8-in. diameter hole is located inside the recirculation line inside the drywell. In the event of a line break, the probe acts as a restricting orifice and limits the

escaping fluid. Two automatic valves which fail close are provide d; one inside and one outside the containment.

6.2.4.3.2.1.2.3 React or Water Cleanup System. The RWCU pumps, heat exchangers, and filter demineralizers ar e located outside the drywell. Th e supply line to the RWCU system connects to the reactor recircula tion system lines on the suction si de of the reactor recirculation pumps and to the RPV by means of the RPV drai n line. Isolation of the RWCU lines is provided by two automatically ac tuated motor-operated gate valves. One valve is located inside containment and the other is located outsi de containment. Both valves are capable of remote manual operation from the control room.

6.2.4.3.2.1.2.4 Residual Heat Removal Shutdown Cooling Line. This line is common to the two trains of RHR shutdown cooling and is located on the A train RRC line just upstream of the pump. The inside motor-opera ted isolation gate valve, located as close as practical to the RPV, is paralleled by a small check valve. The valve is oriented to relieve a pressure build-up in the long section of line between the inside isolation valve and the outside isolation valve during those times when both valves are closed and the trapped line fluid heats and expands. The outside motor-operated containment isolation gate valve is located as close as practical to the containment. Both motor-operated valves automatically isolate on Level 3 to prevent further inventory loss in the event of a line break.

6.2.4.3.2.1.3 Conc lusion on Criterion 55. To ensure protection ag ainst the consequences of accidents involving the release of radioactive ma terial, pipes which form the RCPB have been shown to provide adequate isolation capabilities.

A minimum of two ba rriers were shown to protect against the release of radioactive materials.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-52 In addition to meeting the isola tion requirements stated in Criteri on 55, the pressure retaining components which comprise the RCPB are desi gned to meet other appropriate requirements which minimize the probability or consequences of an accidental pipe rupture. The quality requirements for these components ensure that they are designed, fabricated, and tested to the highest quality standards of all reactor plant components. The classification of components which comprise the RCPB are designed in accor dance with the ASME,Section III, Class l.

Therefore, design of piping system which comprises the RCPB and penetrates containment satisfies Criterion 55.

6.2.4.3.2.2 Evaluati on Against Criterion 56. Criterion 56 requires that lines which penetrate the containment and communicate with the cont ainment interior must have two isolation valves, one inside the containment and one outside, unless it can be demonstrated that the containment isolation provisions for a specific class of lines are acceptable on some other basis.

Table 6.2-16 includes those lines that penetrate the primary containment and connect to the drywell and suppression chamber.

For the lines wherein only a single isol ation valve exists, the discussion in Section 6.2.4.3.2.2.1.1 is germane. Also see Table 6.2-16 for further information on specific lines.

For those lines wherein both isolation valves ar e located outside contai nment, the discussions in Sections 6.2.4.3.2.2.3.2 , 6.2.4.3.2.2.3.10 and 6.2.4.3.2.2.3.11 apply. Also see Table 6.2-16 for further information on specific lines.

6.2.4.3.2.2.1 Influent Lines to Suppression Pool.

6.2.4.3.2.2.1.1 Low-Pr essure Core Spray, Hi gh-Pressure Core Spra y, and Residual Heat Removal Test and Mini mum Flow Bypass Lines. The LPCS, HPCS, and RHR test lines have test isolation capabilities commensurate with the importance to safe ty of isolating these lines. Each line has a normally closed, motor-operate d valve located outside the containment.

Containment isolation requirements are met on the basis that the test lines are closed, low pressure lines constructed to the same quality standards as the contai nment. Furthermore, these lines are connected to ESF systems for which a single isolation valve is acceptable [as stated in NRC Standard Review Plan (SRP) 6.2.4,Section II, paragr aph 6.e] based on the following prerequisites:

a. System reliability is improved with only one isolation valve in the line,
b. The system is closed outside containment and a single active failure can be accommodated with only one isolation valve, C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-53 c. The closed system is protected from missiles,
d. The closed system is designed to Seismic Category I, Safety Class 2, requirements and a minimum temperature a nd pressure rating at least equal to that for the containment, and
e. The piping between the isolation valve and containment is enclosed in the leak-tight housing, or co nservative design of the pi ping and valve, conforming to SRP 3.6.2, precludes a breach of piping integrity.

The test return lines are also used for suppre ssion chamber return flow during other modes of

operation. In this manner th e number of penetrations is reduced, minimizing the potential pathways for radioactive material release.

Typically, pump minimum flow bypass lines join the respective test return lines downstream of th e test return isolation valve. The bypass lines are isolated by motor-operated valves with a restricting orifice downstream of the motor-operated valve.

6.2.4.3.2.2.1.2 Reactor Core Isolation Cooling Turbine Exhaus t, Vacuum Pump Discharge, and RCIC Pump Minimum Flow Bypass Lines. These lines, which penetrate the containment and discharge to the suppression pool, are equipped with a motor-operated, remote manually actuated gate valve located as close to the containment as possibl

e. In addition, there is a simple check valve upstream of the gate valv e which provides positive actuation for immediate isolation in the event of a break upstream of the check valve. The gate valve in the RCIC turbine exhaust is key-locked open in the control room and inte rlocked to preclude opening of the inlet steam valve to the turbine while the turbine exhaust valve is not in a full open position. The RCIC vacuum pump discharge line is also norma lly open but has no requirement for interlocking with steam inlet to the turbine. The RCIC pump minimum flow bypass line is isolated by a normally closed valve. The single valve is allowable because the water side of the RCIC system is a clos ed system analogous to the lines discussed in Section 6.2.4.3.2.2.1.1. 6.2.4.3.2.2.1.3 Residual Heat Removal Heat Exchanger Vent Lines. The RHR heat exchanger vent lines discharge through the RHR h eat exchanger relief valv e discharge lines to the suppression pool. Two globe valves in e ach vent line provide the system pressure boundary and are used to control venting during the RHR heat exchanger filling and draining operations. The outboard globe valve in each line is and meets the criteria for a containment system isolation valve. Both valves are normally closed, re motely controlled motor-operated globe valves. Each vent line is also equipped with a ma nual block valve and the test connections necessary for Type C testing of the isolation valve.

6.2.4.3.2.2.1.4 Low-Pr essure Core Spray, Hi gh-Pressure Core Spra y, and Residual Heat Removal Relief Valve Discharge Lines. These relief valves disc harge to the suppression pool

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-039 6.2-54 directly. They will not normally lift during opera tion and, therefore, can be considered as normally closed.

6.2.4.3.2.2.1.5 Fuel Pool C ooling and Cleanup Return Lines. Line is isolated by two normally-closed automatically actuated motor-operated gate valves, which are located outside the containment per NRC SRP 6.2.4,Section II, paragraph 6.d.

6.2.4.3.2.2.1.6 Deactivated Residual Heat Removal Steam Condensing Mode Steam Line Relief and Drain Lines. The four steam line relief valves (two per train) ha ve been removed and the line flanges are blanke d by "structural connections."

The two parallel-installed drain pot motor-operated globe valves (per train) are deactivated electrically and locked closed to maintain compliance with Criterion 56. Single isolation barriers are warranted on the basis that the RHR system is a closed system.

The RHR heat exchanger vents and relief valves along with the disabled CAC hydrogen recombiner drains and the discharge from RHR-RV-30 return to the wetwell through the deactivated steam c ondensing mode lines.

6.2.4.3.2.2.1.7 Proces s Sampling Suppression Pool Sample Return Line. Dual normally closed remote manual solenoid va lves offer containment isolation. The valves are located outside the containment based on NRC SR P 6.2.4,Section II, paragraph 6.d.

6.2.4.3.2.2.2 Effluent Li nes From Suppression Pool.

6.2.4.3.2.2.2.1 High-Pressure Core Spray, Low-Pressure Core Spray, Reactor Core Isolation Cooling, and Residual Heat Removal Suction Lines. These lines contain motor-operated, remote manually actuated, gate va lves which provide assurance of isolating these lines in the event of a break. These valves also provide long-term leakage contro

l. In addition, the suction piping from the suppressi on chamber is considered an ex tension of containment since it must be available for long-term usage following a design basis LO CA and, as such, is designed to the same quality standards as the containment. Thus, the need for isolation is conditional. The ECCS and RCIC fill systems (ECCS wate rleg pumps) take suction from ECCS pump suppression pool suctions downstream of the isolati on valve. This system is isolated from the containment by the respective ECCS pump suction valve from suppression pool as listed in Table 6.2-16.

6.2.4.3.2.2.2.2 Fuel P ool Cooling Suction Line. Two normally closed automatic motor-operated gate valves, lo cated outside the containmen t (based on NRC SRP 6.2.4,Section II, paragraph 6.d), pr ovide containmen t isolation.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-55 6.2.4.3.2.2.2.3 PSR Suppr ession Pool Sample Line. Dual normally-clo sed remote manual solenoid valves offer containmen t isolation. The valves are located outside the containment (based on NRC SRP 6.2.4,Section II, paragraph 6.d).

6.2.4.3.2.2.3 Influent and Effluent Lines From Drywell and Suppression Chamber Free Volume.

6.2.4.3.2.2.3.1 Containment Atmosphere Control Lines (Deactivated). The containment atmosphere control system lines which penetrate the containment are equipped with two power-operated valves in series, normally closed. Since the CAC system has been deactivated, these valves have b een de-energized. The motor ope rated gate valv es have been locked closed, and the electrohydraulic operated valves are de-ene rgized spring-closed. These valves provide assurance of isolating these lines in the event of a break and also provide long-term leakage control. In addition, the pi ping is considered an extension of containment boundary since it must remain intact following a design basis LOCA and, as such, is designed to the same quality standards as the primary containment.

6.2.4.3.2.2.3.2 C ontainment Purge Supply, Exhaus t, and Inerti ng Makeup Lines. The drywell and suppression chamber purge lines have isolation cap abilities commensur ate with the importance to safety of isolating these lines.

Each line has two air-operated spring closing isolation valves located outside the primary containment that ar e fully qualified to close under accident conditions. Containment isolation requirements are met on the basis that the purge lines are low pressure lines constructed to th e same quality standards as the containment. Valve operability and reliability are enhanced by placement of both valves outside of the containment. The isolation valves for the purge lines are interlocked to preclude their being opened while a containment isolat ion signal exists as noted in Table 6.2-16.

Stainless-steel grills are inst alled across both purge supply line openings (one low in the drywell and the other low in the suppression chamber) and across the purge exhaust line opening high in the drywell. These prohibit debris from entering the purge lines, thus preventing the isolation valves from seating. The two remaining line openings (one purge exhaust and the single vacuum relief line that is not tied into a purge line, both of which are high in the suppression chamber) do not require debris screens because there is no probability of airborne debris during an accident (pipe insulation is not used in the suppression chamber) and the maximum anticipated suppression pool swell elevation is not sufficient to bring the surface of the water to either of these two openings.

There is a small branch line, which provides a makeup supply of n itrogen to inert containment, connected to the purge supply lines for both the drywell and suppression chamber. Each nitrogen makeup taps into its associated purge supply line inboard of the air-operated, spring-closing isolation valves. Therefore, each of these ni trogen lines is equipped with two automatic containment isolation valves, located as close as possible to primary containment.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-56 6.2.4.3.2.2.3.3 Drywell and Suppression Chamber Air Sampling Lines. The radiation monitor lines penetrate the primary containm ent and are used for continuously sampling containment air during normal opera tion as part of the leak dete ction system. The supply lines are equipped with two automatic solenoid-operated isolat ion valves located out side and as close as possible to the containment. The return lines are equipped with a remotely operated

solenoid isolation valve outside of containment and a check valve inside the containment.

The PSR system sample and return lines are normally isolated by dual solenoid valves. These do not receive automatic isolation signals since they may be used to sample the drywell and suppression chamber atmosphere in a post-LOCA situation.

6.2.4.3.2.2.3.4 Suppression Chamber Spray Lines. The suppression chamber spray lines penetrate the containment to remove energy by condensing steam and cooling noncondensable gases in the suppression chamber. Each line is equipped with a normally closed motor-operated valve located outside a nd as close as possible to the primary containment. This normally closed valve receives an automatic isolation signa

l. Containment isolation requirements are met on the basis that the spray header injection lines are normally closed, low pressure lines constructed to the same quality standards as the containment.

6.2.4.3.2.2.3.5 Reactor Building to Wetwell Vacuum Relief Lines. The three RB-WW vacuum relief lines are each equipped with a positive closing swing check valve in series with an air-operated, fail-open, butte rfly valve. The air operator on the swing check valve is used only for testing. The air-operated butterfly valve is contro lled by a differential pressure indicating switch which senses the pressure difference between the suppression chamber and the reactor building.

When the negative pr essure in the suppre ssion chamber exceeds the instrument setpoint, the butterfly valve opens. The valves are not susceptible to fouling by ingested debris during such an event because they are not targets of missiles and are adequately protected from pipe break dama ge. The arrangement of valves and instruments is shown in Figure 9.4-8.

6.2.4.3.2.2.3.6 Dr ywell Spray Lines. The drywell spray lines are equipped with two normally closed, motor-operate d gate valves located outside and as close as possible to primary containment. The drywell spray must be manually initiated. The piping from the outermost isolation valve to th e spray ring header is construc ted to withstand containment design conditions.

6.2.4.3.2.2.3.7 Reactor Closed C ooling Water Supply and Return Lines. Dual motor-operated automatic gate va lves isolate each line, the fo rmer having both outside the containment and the latter having one inside and one outside the containment. In response to the concerns addressed in Generic Letter 96-06, Energy Northwest installed a bypass line around the inboard isolation valve on the return line. This bypass line is equipped with a check valve oriented against nor mal system flow. Thus, the check valve functions as an

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-57 isolation valve in parallel with the main inboard isolation valve and as a means to dissipate pressure built up between the inboard and outboard isolation valves.

6.2.4.3.2.2.3.8 Air Supply Lines.

6.2.4.3.2.2.3.8.1 Check Valve Air Supply Lines. All lines are isolated by two locked-closed manual globe valves lo cated outside the containment and as close as practical to the containment. The air test func tion is not used. Therefore, the valves are normally closed all of the time.

6.2.4.3.2.2.3.8.2 Primary Containment Instrument Air System Nitrogen Supply Lines. These lines consist of a check valve inside the containment and a motor-operated remote-manual globe valve outside the containm ent. The globe valves are unde r the control of the operator who can isolate the single nonsafety-related header should th e containment nitrogen (CN) supply be unavailable. The ope rator can also isolate either or both safety-related headers should either, or both, experience nitrogen supply problems or ot herwise require isolation.

See Table 6.2-16 for further information.

6.2.4.3.2.2.3.8.3 Service Air System Maintenance Supply Line to the Drywell. This single line is capped with a th readed pipe cap inside the cont ainment and isolated outside the containment by a locked-clo sed manual globe valve.

6.2.4.3.2.2.3.9 De mineralized Water Maintenance Supply Line to the Drywell. Dual manual gate valves, one inside and one outside the containment, isolate this line at all times except when high purity water is requi red inside the drywell for maintenance-related activities.

6.2.4.3.2.2.3.10 Drywell Equipment and Floor Drain Lines. Containment isolation is provided by two normally open, ai r-operated, fail-close automatic valves located outside and as close as practical to the containment.

6.2.4.3.2.2.3.11 Traversing In-Core Probe (TIP) System Guide Tubes. The TIP system consists of five guide tubes which penetrate the containment and interface with the containment atmosphere because of indexer leakage and built-in relief valv es that prevent the indexers from collapsing on high pressure. The isolation design basis for these TIP lines is a "specific class of line" considered acceptable under General Design Criterion 56.

Isolation is accomplished by a seismically qualified solenoid-operated ball valve, which is normally closed. To ensure isolation capability, an explosive shear valve is installed in each line. Upon receipt of a signal (manually initiated by the operat or) this explosive valve will shear the TIP cable and seal the guide tube.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-58 When the TIP system is inserted, the ball valve of the se lected tube opens automatically so that the probe and cable may advance. A maximum of five valves may be opened at any one time to conduct calibration and any one guide tube is used, at most, a few hours per year.

If closure of the line is required during calibration, a signal causes a cabl e to be retracted and the ball valve to close automatica lly after completion of cable withdrawal. If a TIP cable fails to withdraw or a ball valve fails to close, the explosive shear valve is actuated. The ball valve position is indicated in the control room.

The ball valve and shear valve are located outside the drywell and as close as practical to the containment. These valves are designed to Code Group B requirements, therefore they are of the same quality class as the containment.

6.2.4.3.2.2.4 Conc lusion on Criterion 56. To ensure protection ag ainst the consequences of accidents involving release of significant amounts of radioactive materials, pipes that penetrate the containment have been demonstrated to pr ovide isolation capabilitie s in accordance with Criterion 56 or other defined bases.

In addition to meeting the above isolation requirements, the pressure retain ing components of most of these systems are designed to the same quality standard s as the containment. For exceptions, see Section 6.2.4.3.2.4.

6.2.4.3.2.3 Evaluati on Against Criterion 57. Lines forming a closed system inside the primary reactor containment must have one isolation valve outside if the system boundary penetrates the containment.

Columbia Generating Station does not have any systems qualifying under this criterion.

6.2.4.3.2.4 Evaluati on Against Regulatory Guide 1.11, Revision 0. Instrument lines which penetrate the containment from the RCPB are equipped with a restricting orifice located inside the drywell and an excess flow check (EFC) valve located outside and as close as practicable to the containment. Those instrument lines whic h do not connect to the RCPB are equipped with single solenoid-operated or EFC isolation check valves. Valve position indication is available in the control room.

The EFC valves have no active safety function requirements. Ho wever, the RCPB instrument line EFC valves close to limit the flow in the respective instrume nt lines in th e event of an instrument line break downstream of the EFC valve outside containment. The instrument lines are Seismic Category I and are assumed to mainta in integrity for all accidents except for the instrument line break accident (I LBA) as described in Section 15.6.2. Isolation of the instrument line by the EFC valve is not credited for mitigating the ILBA.

Each EFC valve has an integral manual bypass valve which ma y be used to reset an actuated disc. The bypass valves are periodi cally verified to be closed.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-59 The hydrogen/oxygen monitoring lines penetrat e primary containment and are used to continuously monitor the containment air during the post-LOCA accident period. These lines are equipped with single solenoi d-operated or EFC valves located outside and as close as possible to the containment. Containment isolation requirements are met on the basis that these are low pressure lines constructed to the same quality standards as the containment. The solenoid-operated valves are re quired to remain open during nor mal operation and postaccident for those DBAs for which contai nment isolation is required to limit offsite dose consequences to less than established requirements. Accordingly, they receive no automatic isolation signal or leak rate testing. No credit is taken for either the automa tic or remote manual closing of these valves for containment isolation for the DBAs. Therefore, position indication requirements do not apply to the solenoid-operated valves.

6.2.4.3.3 Failure Mode and Effects Analyses

In single failure analysis of electrical system s, no distinction is made between mechanically active or passive compon ents. All fluid system components such as valves are considered electrically active whether or not mechanical action is required.

Electrical as well as mechanical systems are designed to meet the single failure criterion for both mechanically active and passive fluid system components regardless of whether that component is required to perf orm a safety action. Even though a component such as an electrically operated valve is not designed to receive a signal to change state (open or closed) in a safety scheme, it is assumed as a single failure that the syst em component changes state or fails. Electrically operated valves include those that are electri cally piloted but air operated as well as those that are directly operated by an electrical device. In addi tion, all electrically operated valves that are automa tically actuated can also be ma nually actuated from the main control room. Therefore, a singl e failure in any electrical system is analyzed regardless of whether the loss of a safety f unction is caused by a component failing to perform a requisite mechanical motion or a co mponent performing an unneces sary mechanical motion.

6.2.4.3.4 Operator Actions

A trip of an isolation control system channel is annu nciated in the main control room. Most motor-operated and air-operated isolation valves have open-close status lights. The following general information is presented to the operator by the isolation system:

a. Annunciation of each process variable which has reached a trip point,
b. Computer readout of trips on main st eam line tunnel temperature or main steam line excess flow,
c. Control power failure annunc iation for each channel, and C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-60 d. Annunciation of steam leaks in each of the syst ems monitored (main steam, reactor water cleanup, and reactor heat removal).

If the primary containment and r eactor vessel isolation system doe s not automatically shut an isolation valve, the "iso lation signal" column of Table 6.2-16 references the applicable note which discusses the isolation criteria including operator action based on specific input available to the operator.

This information will enable the operator to de termine the need to ope rate a remote manual valve in the event of a LOCA.

6.2.4.4 Tests and Inspections

The containment isolation system is periodically tested during reactor operation and shutdown. The functional capabilities of pow er operated isolation valves are tested remote manually from the main control room. By observing position indi cators and/or changes in the affected system operation, the closing ability of a particular isol ation valve is demonstr ated. A discussion of testing and inspection pert aining to isolation valves is provided in Section

6.2.1. Table

6.2-16 lists the process line isolation valves.

The EFC valves used as single reactor instrument sensor line isolation valves are periodically tested to meet the requirements of Regulatory Guide 1.11 and the Technical Specifications

Surveillance Requirements. As these valves are outside th e containment and accessible, periodic visual inspection is performed in addition to the opera tional check. Sensor lines emanating from the suppression pool, the suppre ssion chamber, or the drywell free volume are periodically tested on a sampling basis in accordance with the plant maintenance program.

Preoperational testing is discussed in Section 14.2.12. Containment isolation valve leakage rate testing is discus sed in the notes in Figures 6.2-36 through 6.2-59.

6.2.5 COMBUSTIBLE

GAS CONTROL IN CONTAINMENT

Combustible gas control is provided to ensure containment integrity when hydrogen and oxygen gases are generated following a postula ted LOCA. The RHR system operating in containment spray mode and redundant reactor head area return fans augment the natural processes to mix the containmen t atmosphere. The oxyge n and hydrogen con centrations in the containment atmosphere are monitored by instrumentation disc ussed in Section 7.5.1.5. To supplement the combustible gas control system, the containmen t nitrogen inerting system provides a nitrogen atmosphere in primary containment.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-039 6.2-61 6.2.5.1 Design Bases

The design bases for the containment atmosphere control system are as follows:

a. The system is designed in accordance with 10 CFR 50.44;
b. Primary containment will be inerted to an oxygen concentration of less than or equal to 3.5% by volume during normal plant operation;
c. Containment sprays, natural turbulen ce resulting from diffusion and convection caused by the elevated temperatures, and operation of the containment head area return fans, if necessary, ensure that no local pocket with greater than 5%

oxygen can occur within containment; 6.2.5.2 System Design The system consists of the following:

a. An atmosphere mixing system which could operate if necessary to ensure a well mixed atmosphere in both the drywell and suppression chamber. This system consists of the containment spray system which can be actuated approximately 10 minutes after the postulated LOCA, and containment head area return fans which start on receipt of a reactor scram signal;
b. A monitoring system measures the concentration of hydrogen and oxygen in the drywell and suppression ch amber atmosphere; and
c. Two hydrogen-oxygen recombiners are de activated and isolated from primary containment. Attached piping and components are similarly deactivated, retaining solely their structural continu ity with the containment penetrations. The recombiners are Seismic Category I.

6.2.5.2.1 Atmosphere Mixing System

The function of the atmosphere mixing system is to provide a well mixed atmosphere in the drywell and suppression chamber.

Using experimental results (Reference 6.2-18) as a basis for hydrogen and oxygen mixing within the containment, hydrogen or oxygen distribution in the steam nitrogen-oxygen atmosphere would simulate that of the iodine fiss ion products (References 6.2-19 and 6.2-20) and it would be uniform througho ut the containment. Accordi ngly, it is extremely unlikely that an atmosphere mixing system would be required.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-039 6.2-62 However, the RHR system operating in containm ent spray mode and redundant reactor head area return fans are available to augment thes e natural processes.

The RHR system containment spray system is described in Section 5.4.7. It may be manually actuated from the main control room to provide mechanical mixing of the drywell atmosphere.

The two head area return fans are part of the primary containment cooli ng system, discussed in Section 9.4.11.2.

The redundant reactor head area return fans are available to exhaust atmospheric gases and vapors from the reactor head area above the refueling bulkhead plate to the main portion of the drywell. Both fans start au tomatically upon reactor scram and are powered from different Class 1E electrical divisions. Atmospheric gases and vapors exhausted from the reactor head area by the fan(s) are replaced by flow from the drywell area through the two vent paths through the bulkhead pl ate as portrayed in Figure 6.2-24. This recirculation prevents formation of pockets of combustible gases both in the reactor head area and in the drywell below the bulkhead plate.

6.2.5.2.2 Hydrogen and Oxygen Concentration Monitoring System

Both the oxygen and the hydrogen concentrations are continuo usly monitored during normal operation and following the postulate d LOCA, and are displayed in the control room. A visual and audible alarm initiates in the control room if the oxygen concentration reaches 3.5% by volume. This alarm alerts operators to take action to limit the pre-LOCA oxygen concentration to 3.5% or less to ensure that post-LOCA oxygen concentrations will not exceed the limit of 4.8%. If oxygen concentration approaches 4.4% by volume, a visual and audible high-high level alarm initiate s in the control room.

The hydrogen and oxygen gas analyzers, numbe r and location of sa mpling points, and instrumentation are discussed in Section 7.5.1.5.

Calibration tests are routinely performed to calib rate and verify instrument accuracy against known gas compositions.

Two redundant hydrogen and oxygen concentr ation monitoring systems are provided.

6.2.5.2.3 Containment Purge

Containment purge is discussed in Section 6.2.1.1.8.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-63 6.2.5.3 Design Evaluation The determination of the time-dependent oxygen and hydrogen c oncentrations in the drywell and suppression chamber atmos pheres is based on a two-re gion model of the primary containment: a drywell and s uppression chamber atmosphere. The rate of radiolytic hydrogen and oxygen generation varies linearly with power.

The released fission products, excluding noble ga ses, that are mixed with the coolant are assumed to be swept out of core as the core cooling waters ex it the break and flow by gravity by means of the downcomers to the suppression chamber.

Hydrogen generated from the metal-water reaction and both hydrogen and o xygen generated from core radiolysis are assumed released to the drywell atmosphere and mix homogeneously. Hydrogen as well as oxygen genera ted from suppression pool radi olysis are assumed released to the suppression chamber atmo sphere and mix homogeneously.

The hydrogen and oxygen monitors ar e accurate at the an ticipated concentration in the primary containment.

6.2.5.3.1 Hydrogen a nd Oxygen Generation

In the period immediately after the postulated LOCA, hydrogen can be gene rated by radiolysis, metal-water, and me tallic paint-water reacti ons. However, in evaluating short-term hydrogen generation, the contribution from radiolysis and metal lic paint-water reacti ons are insignificant in comparison with the hydrogen gene rated by the metal-water reaction.

During the same time period oxygen is generated by radiolysis onl

y. However, the contribution from radiolysis is small compared with the in itial 3.5% oxygen concentration within containment prior to the postulated LOCA.

The generation of hydrogen by metal-water reaction is dependent on the temperature of the cladding at the time the postulated LOCA occu rs. Based on LOCA calculations and ECCS performance in accordance with 10 CFR 50.46, the extent of metal-water reaction in the BWR/5 core is negligible. The design of the BWR/5 ECCS is such that the peak Zircaloy clad temperature is 2000

°F. At this temperature virtually no metal-water reaction occurs and, therefore, hydrogen production by this means is insignificant.

6.2.5.4 Testing and Inspections

The RHR drywell spray mode of operation is tested in accordance with Technical Specifications. The head area return fan testing is discussed in Section 9.4.11.4. Testing of the hydrogen and oxygen monitoring is discussed in Section 7.5.1.5.4.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-64 6.2.5.5 Instrumentation Requirements

See Sections 7.5.1.5.4 and 9.4.11.5.

6.2.5.6 Materials

See Section 6.2.5.2.

6.2.5.7 Containment Nitrogen Inerting System

The system is designed to esta blish and maintain a nitrogen atmosphere in which the oxygen concentration can be controlled at less than 3.5% by volume in both the drywell and suppression pool during normal opera tion. The system is designe d to comply with NRC staff position of April 2, 1981, requiri ng that "the GE pressure suppression containment systems identified by Mark I and Mark II, be inerted."

6.2.6 CONTAINMENT

LEAKAGE TESTING

General Design Crite ria 52, 53, and 54 have been met.

6.2.6.1 Containment Leakage Rate Tests

The primary containment system is a steel pres sure suppression system of the over and under configuration with a designed leakage rate of 0.5% by volume per day at 45 ps ig. A maximum allowable integrated vessel leak rate of 0.5% by wei ght per day at 38 psig has been established to limit leakage during and followi ng the postulated DBA to less than that which would result in offsite doses greater than those specified in 10 CFR 50.67. Leakage rate tests at reduced pressures may be established such that the measured l eakage rate does not exceed the maximum allowable at that reduced pressure.

A structural integrity test i nvolving pneumatic pre ssurization of the drywell and suppression chamber was performed at 51.8 psig, 1.15 times the containment vessel design pressure of 45 psig. This test was conducted in accordan ce with the ASME Boiler and Pressure Vessel Code,Section III, 1971 Edition through the Su mmer 1972 Addenda, Subarticle NE-6300.

See Section 3.8.2.7 for a description of the test.

Testing involves perfor ming periodic Type A, B, and C tests. These tests are conducted in accordance with the Technical Specifications and 10 CFR 50, Appendix J.

Table 6.2-14 lists the containment penetrations subject to Type B tests.

Table 6.2-16 lists the primary containment isolation valv es subject to Type C te sts unless otherwise noted.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009,06-039 6.2-65 6.2.6.2 Special Testing Requirements

The secondary containment is test ed at each refueling outage to ensure the maximum allowable leakage rate of 100% of secondary containment free volume per day at negative 0.25-in. water gauge pressure with respect to outside atmospheric pressure. Fu rther testing is summarized in Section 6.2.3.4. Other testing requirements are contained in the Technical Specifications.

6.

2.7 REFERENCES

6.2-1 James, A. J., "The GE Pressure Suppression Cont ainment Analytical Model,"

NEDO-10320, March 1971.

6.2-2 James, A. J., "The GE Pressure Suppression Cont ainment Analytical Model,"

Supplement 1, NEDO

-10320, May 1971.

6.2-3 Moody, F. J., "Maximum Two-Phase Vessel Blowdown fr om Pipes," Topical Report APED-4824, GE Company.

6.2-4 "MK II Containment Dynamic Fo rcing Functions Information Report (Revision 2)," GE and Sargeant and Lundy, NEDO-21061, September 1976.

6.2-5 "Plant Design Assessment Report fo r SRV and LOCA Load s (Revision 3),"

Washington Public Power Supply System, August 1979.

6.2-6 J. D. Duncan and J. E. Leonard, "Emergency Cooling in BWRs Under Simulated Loss-of-Coolant (BWR PLEC MP) Final Report," GEAP-13197, GE, June 1971.

6.2-7 WPPSS Report, "Drywell to We twell Leakage Study," WPPSS-74-2-R5, July 1974. (Supply System to NRC, Le tter G02-74-17, dated August 9, 1974).

6.2-8 Wheat, L. L., Wagner, R. J., Niederauer, G. F., Obenchain, C. F., CONTEMPT-LT-- A Computer Program For Predicting Containment Pressure-Temperature Response To A Loss-Of-Coolant Accident, ANCR-1219, Aeroject Nuclear Co mpany, June 1975.

6.2-9 Washington Public Power Supply System, Nuclear Project No. 2, Report No. WPPSS-74-2-R2-A, "Sacrificial Sh ield Wall Design Supplemental Information," February 11, 1975.

6.2-10 Washington Public Power Supply System, WPPSS Nuclear Project No. 2 Response to NRC Comments, Report No. WPPSS-74-2-R2-A, "Sacrificial Shield Wall Design Supplemental Information," June 26, 1975.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-66 6.2-11 Washington Public Power Supply System, Nuclear Project No. 2, Report No. WPPSS-74-2-R2-B, "Sacrificial Sh ield Wall Design Supplemental Information," August 19, 1975.

6.2-12 Letter from R. C. DeYoung, NR C, to J. J. Stein, WPPSS, dated August 13, 1975,

Subject:

Sacr ificial Shield Wall Design.

6.2-13 Letter from R. C. DeYoung, NR C, to J. J. Stein, WPPSS, dated October 15, 1975,

Subject:

Sacr ificial Shield Wall Design.

6.2-14 ANCR-NUREG-1335, "RELAP4/MOD5 - A Computer Progr am for Transient Thermal-Hydraulic Analysis of Nuclear Reactor and Related Systems Users Manual," 3 Volumes, September 1976.

6.2-15 AEC-TR-6630, "Handbook of Hydraulic Resistance, Coefficients of Local Resistance and of Fricti on," by I. E. Idel'Chick, 1960.

6.2-16 Bilanin, W. J., "The GE Mark III Pressure Suppression Containment System Analytical Model," NEDO-20533.

6.2-17 "Loss-of-Coolant A ccident and Emergency Core Cooling Models for GE Boiling Water Reactors," Licensing Topical Report, NEDO-10329, GE.

6.2-18 A. K. Post and B. M. Johnson, "Containment Systems Experiment Final Program Summary," BNWL-1592, Battelle Northwest, Rich land, Washington, July 1971.

6.2-19 J. G. Knudsen and R. K. Hillia rd, "Fission Product Transport by Natural Processes in Containment Vessels," BNWL-943, Battelle Northwest, Richland, Washington, January 1969.

6.2-20 R. K. Hilliard and L. F. Coleman, "Natural Transport Effects on Fission Product Behavior in the Containmen t Systems Experiment," BNWL-1457, Battelle Northwest, Richland, Washington, December 1970.

6.2-21 R. K. Hilliard, "Removal of Iodine and Particles from Containment Atmospheres by Sprays --

Containment Systems Expe riment Interim Report,"

BNWL-1244, Battelle Northwest, Rich land, Washington, February 1970.

6.2-22 D. K. Sharma, "Tec hnical Description Annulus Pressurization Load Adequacy Evaluation," January 1979 (NEDO 24548).

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-039 6.2-67 6.2-23 "Studies of BWR Design for Mitigation of Antic ipated Transients Without Scram," NEDO-20626, October 1974.

6.2-24 GE Response to NR C Status Report, "GE ATWS Report," and Appendices, June and September, 1976 (Proprietary).

6.2-26 "Flow of Fluids Through Valves, Fi ttings, and Pipe," Tec hnical Paper No. 410, Crane Company, 1980.

6.2-27 NEDE-21544-P, "Mark II Pressure Suppression Containment Systems: An Analytical Model of the Pool Swell Phenomenon."

6.2-28 Response to NRC Question 020.071, transmitted by Letter MFN-275-78 to J. F. Stolz, Chief Light Water Reactor Branch No. 1, NRC, from L. J. Sobon, Manager BWR Containment Licensing, GE Company on "Responses to NRC Request for Additional Information (Round 3 Questions)," da ted June 30, 1978.

6.2-29 Burns and Roe Calculation Number 5.07.10.1, "Blowdown of 6 inch RCIC (1)-4 at RPV - Constant Blowdown Model."

6.2-30 Burns and Roe Calculation Number 5.07.10.2, "Blowdown of 6 inch RCIC (1)-4 at RPV - Relap 4 Model."

6.2-31 Letter from GE to Washington Public Power Supply System, GEWP 2-77-533, Transmittal of the Mass/E nergy Report Entitled, "Ma ss and Energy Release for Suppression Pool Temperature Analys is During Relief Valve and LOCA Transients."

6.2-32 Request for Amendment to the Facility Operating License and Technical Specifications to Increase Licensed Power Level From 3323 MWt to 3486 MWt with Extended Load Line Limit and a Change in Safety Relief Valve Setpoint Tolerance, Supply System to NRC Lett er G02-93-180, date d July 9, 1983.

6.2-33 Deleted 6.2-34 Engineering Evaluation of the Sacrificial Shield Wall, Supply System to NRC Letter GO2-80-172, August 8, 1980.

6.2-35 GE Nuclear Energy, "WNP-2 Po wer Uprate Project NSSS Engineering Report," GE-NE-208-17-0993, Re vision 1, December 1994.

6.2-36 Advanced Nuclear Fuels Corpor ation, "WNP-2 Single Loop Operation Analysis," ANF-87-11 9, September 1987 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-68 6.2-37 GE Nuclear Energy, "Washington Public Power Supply System Nuclear Project 2, SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis,"

NEDC-32115P, Class III (Proprieta ry), DRF A00-05078, Revision 2.

6.2-38 GE Nuclear Energy, "Washington Public Power Supply System Nuclear Project 2, SRV Setpoint Tolerance and Out-of-Service Analysis,"

GE-NE-187-24-0992, Revision 2.

6.2-39 Numerical Applications, Inc., "GOTHIC Containment Analysis Package Users Manual," Version 7.

1, January 2003.

6.2-40 NRC Branch Technical Position CS B 6-3, "Determination of Bypass Leakage Paths in Dual Containment Plants."

6.2-41 Calculation NE-02-01-05, "Secondary Containment Drawdown."

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-69 Table 6.2-1 Containment Design Parameters Drywell Suppression Chamber A. Drywell and Suppression Chamber 1. Internal design pressure, psig 45 45 2. External design pressure, psig 2 2 3. Drywell deck design differential pressure, psid 25 (downward)

6.4 (upward)

4. Design temperature, °F 340 275 5. Net free volume, ft 3 (drywell includes vents) 200,540 144,184 maximum 6. Maximum allowable leak rate, %/day 0.5 0.5 7. Suppression chamber free volume, minimum, ft 3 142,500 8. Suppression chamber water volume minimum, a ft 3 112,197 9. Pool cross section area, ft 2 5,770 10. Pool free surface cross section area, ft 2 4,520 11. Pool depth (normal), ft 31 B. Vent System
1. Number of downcomers 99 2. Downcomer inside diameter, ft 1.9375 3. Total vent area, ft 2 309 4. Downcomer maximum submergence, ft 12 5. Downcomer loss factor 2.77 a This volume does not include the water within the pe destal (10,065 ft
3) nor the water 12 ft below the downcomer exits (15,000 ft
3)

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-70 Table 6.2-2

Engineered Safety Systems Information for Containment Response Analyses Value Used in Containment Analysis Full Capacity Case A Case B Case C A. Drywell Spray System

1. Number of pumps 2 2 1 N/A 2. Number of lines 2 2 1 N/A 3. Number of headers/line 1 1 1 N/A 4. Spray flow rate, gpm/pump 7450 6713 b,d 6713 b N/A 5. Spray thermal efficiency, % 100 100 100 N/A B. Suppression Pool Spray
1. Number of pumps 2 2 1 N/A
2. Number of lines 2 2 1 N/A
3. Number of headers/line 1 1 1 N/A 4. Spray flow rate, gpm/pump 450 353 b 353 b N/A 5. Spray thermal efficiency, % 100 100 100 N/A C. Containment Cooling System
1. Number of pumps 2 2 1 1 a 2. Pump capacity, gpm/pump 7900 7067 b 7067 b 7067 b 3. Heat Exchangers RHR system-inverted U-tube, single pass shell, multi-pass tubes, vertical mounting a. Number 2 2 1 1 a b. Heat transfer area, ft 2/Unit 7641 7641 7641 7641 c. Overall heat transfer coefficient, Btu/hr ft 2 °F 195(fouled)

400(clean) 195 195 195 d. Standby service water flow rate per exchanger, gpm 7400 7400 7400 N/A e. RHR heat exchanger K value Btu/sec-°F 414(fouled)

849(clean) N/A N/A 289 f. Design service water minimum, °Ftemperature maximum, °F 32°F 85°F 95 b 95 b 90 g. Containment heat removal capability per loop, using 85°F service water and 165°F pool temperature; Btu/hr 83.23 x 10 6

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-71 Table 6.2-2 Engineered Safety Systems Information for Containment Respons e Analyses (Continued)

Used in Containment Analysis Value Full CapacityCase A Case B Case C D. ECCS Systems

1. High pressure core spray (HPCS) a. Number of pumps 1 1 1 1 a b. Number of lines 1 1 1 1 a c. Flow rate, gpm 6250 6250 6250 6250 a 2. Low pressure core spray (LPCS)
a. Number of pumps 1 1 0 0 a b. Number of lines 1 1 0 0 a c. Flow rate, gpm 6250 6250 0 0 a 3. Low-pressure coolant injection (LPCI)
a. Number of pumps 3 1 e 1 1 a b. Number of lines 3 1 e 1 1 a c. Flow rate, gpm 1 pump 7450 c 7067 b 7067 b 7067 a,b 4. Residual heat removal (RHR)
a. Pump flow rate: shell side 7450 0 0 0 tube-side 7400 0 0 0
b. Source of cooling water Standby service water E. Automatic Depressurization System
1. Total number of safety/relief valves 18 a 2. Number actuated on ADS 7 a a No change due to uprate.

b Represents conservative value used in analysis.

c Increase to 7900 gpm with zero differential pressure between RPV and wetwell.

d Only 2 of 3 LPCI pumps available fo r spray, and only after 600 seconds.

e Three LPCI pumps available; 2 pumps directed to drywell sprays after 600 seconds, with third pump continuing in LPCI mode.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-72 Table 6.2-3

Accident Assumptions and Initial Conditions for Recirculation Line Break

A. Effective accident break area (total), ft 2 3.106 a B. Components of ef fective break area: 1. Recirculation line suction nozzle area, ft 2 2.508 a 2. RWCU cross tie line ft 2 0.078 a 3. Jet pump nozzles, ft 2 0.520 a C. Break area/vent area ratio 0.0105 a D. Primary system energy distribution b 1. Steam and liquid energy, 10 6 Btu 414/361 d 2. Sensible energy, 10 6 Btu a. Reactor vessel 106.1/220 d b. React or internals (less core) 58.6 e c. Primary system piping 34.6 e d. Fuel (c) E. Assumptions used in pressure transient analysis 1. Feedwater flow coastdown time 39.6 2. MSIV closure time (sec) 3.5

3. Scram time (sec) <1 a 4. Liquid carryover, % 100 a 5. Turbine throttle valve closure (sec) 0.2 a No change due to uprate.

b All energy values except fuel are based on a 32°F datum.

c Fuel energy is based on a 285°F datum.

d Original rated power/uprated power analysis.

e Reactor vessel sensible ener gy includes reactor internals (l ess core) and primary system piping.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-73 Table 6.2-4 Initial Conditions Employed in Containment Response Analyses OriginalRated Power Cases Uprated Power A. Reactor coolant system (at 105% of rated steam flow and at normal liquid levels)

1. Reactor power level, MWt 3462 3702 2. Average coolant pressure, psig 1020 1020 Peak coolant pre ssure, psia 1055 1055 3. Average coolant temperature, °F 547 551 4. Mass of reactor coolant sy stem liquid, lb 676,700 634,300
5. Mass of reactor coolant system steam, lb 24,900 24,740 6. Volume of water in vessel, a ft 3 12,743 13,282 7. Volume of steam in vessel, b ft 3 10,167 10,397 8. Volume of water in recirculation loops, ft 3 670 (a) 9a. Volume of water in feedwater line, c ft 3 543 9b. Mass of water in feedwater line, lb 693,034 10. Volume of water in miscellaneous lines, c ft 3 121 (a) 11. Total reactor coolant volume, ft 3 23,580 23,679
12. Stored water a. Condensate storage tanks, gal (min) 135,000 N/A b. Fuel storage pool, gal 350,000 N/A C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-74 Table 6.2-4 Initial Conditions Employed in Containment Respons e Analyses (Continued)

OriginalRated Power Cases Uprated Power Drywell/Suppression Chamber Drywell/Suppression Chamber B. Containment

1. Pressure, psig 0.7/0.7 2.0/2.0 2. Inside temperature, °F 135/90 135/90 d 3. Outside temperature, °F NA/NA NA/NA 4. Relative humidity, % 50/100 50/100 5. Service water temperature, °F 95/95 90/90
6. Water volume, ft 3 NA/107,850 NA/107,850
7. Vent submergence, ft NA/12 NA/12 a Item 6 includes items 8 and 10.

b Item 7 includes the main steam lines up to the inboard MSIV.

c Up to inboard isolation valve.

d Analysis was performed assuming an initial wetwell air space temperature of 150

°F and suppression pool temperature of 90

°F.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-75 Table 6.2-5

Summary of Accident Results for Containment Response to Limiting Line Breaks

Original Rated Power Uprated Power Accident Parameters Recirculation Line Break a Steam Line Break b Recirculation Line Break

1. Peak drywell pressure, psig 34.69 34.0 37.4 c,d 2. Peak drywell diaphragm floor differential pressure, psid 19.39 19.1 21.7 3. Time (S) of Peak Pressures, Sec. 19.0 12.0 11.9 4. Peak drywell temperature, °F 280.2 328 283 c 5. Peak suppression chamber pressure, psig 27.3 31.3 6. Time of peak suppression chamber pressure, sec. 55 55 139 7. Peak suppression pool temperature during blowdown, °F (~100 sec.) 140 140 146
8. Peak suppression pool temperature, long term, °F 220 220 204.5
9. Calculated drywell margin, %

e 22.9 24.5 16.9

10. Calculated suppression chamber margin, %e 38.6 38.0 30.4 11. Calculated deck differential pressure margin, % 22.44 23.6 13.2
12. Energy released to containment at time of peak pressure, 10 6 Btu 260 204 174
13. Energy absorbed by passive heat sinks at time of peak pressure, 10 6 Btu 0 0 0 a See Figures 6.2-3 and 6.2-7 for plots of pressures versus time and Figures 6.2-4 and 6.2-9 for plots of temperature versus time.

b See Figures 6.2-15 and 6.2-16 for plots of pressure and temperature versus time respectively.

c For initial containment pressure of 2.0 psig.

d The value of P a to be used for 10 CFR 50 Appendix J te sting was conservatively chosen to be 38 psig. e (Design Pressure - Maximum Calculated Pressure)

Design Pressure

C OLUMBIA G ENERATING S TATION Amendment59 F INAL S AFETY A NALYSIS R EPORTDecember2007 6.2-76 Table 6.2-6 Loss-of-Coolant Accident Long-Term Primary Containment Response Summary Case LPCI and LPCS Pumps Service Water Pumps Containment Spray (gal/min)

HPCS (gal/min)

LPCI and LPCS (gal/min)

Peak Pool Temp (°F)Secondary Peak Pressure (psig) A Original rated power 3462 MWt Before 600 seconds After 600 seconds 3/1 3/1 3 3 0 14,134 6250 6250 21,200/6250 7067/6250 180 7.3 B Original rated power 3462 MWt Before 600 seconds After 600 seconds 2/0 1/0 2 2 0 7067 6250 6250 14,134/0 7067/0 220 13.5 C Original rated power 3462 MWt Before 600 seconds After 600 seconds 2/0 1/0 2 2 0 0 6250 6250 14,134/0 7067/0 220 18.3 C Uprated power 3702 MWt Before 600 seconds After 600 seconds 2/0 1/0 2 2 0 0 6250 6250 14,134/0 7067/0 204.5 14.3 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-77 Table 6.2-7

Energy Balance for Design Basis Recirculation Line Break Accident

Prior to DBA (0 sec) Time of Peak Pressure Difference Across Drywell Deck

End of Blowdown Time of Peak a Containment Pressure

Unit 1) Reactor coolant (vessel & pipe

inventory) 414.0 x 10 6 400 x 10 6 12.2 x 10 6 49.4 x 10 6/44.8 x 10 6 Btu 2) Fuel and cladding Fuel Cladding

34.5 x 10 6 3.05 x 10 6 32.3 x 10 6 3.05 x 10 6 12.3 x 10 6 2.99 x 10 6 4.42 x 10 6/4.0 x 10 6 1.07 x 10 6/0.972 x 10 6

Btu Btu 3) Core internals, also reactor coolant piping, pumps, and

valves 91.2 x 10 6 91.2 x 10 6 91.2 x 10 6 34.0 x 10 6/57.4 x 10 6 Btu 4) Reactor vessel metal 107 x 10 6 107 x 10 6 107 x 10 6 40 x 10 6/66.6 x 10 6 Btu 5) Reactor coolant piping, pumps, and

valves Included in item 3 6) Blowdown enthalpy NA 551 NA NA Btu/lbm 7) Decay heat 0 0.463 x 10 6 8.8 x 10 6 1020 x 10 6/222 x 10 6 Btu 8) Metal-water reaction heat 0 0 0.01 x 10 6 0.471 x 10 6/0.471 x 10 6 Btu 9) Drywell structures 0 0 0 0

10) Drywell air 1.3 x 10 6 1.6 x 10 6 0 1.61 x 10 6/1.41 x 10 6 11) Drywell steam 0.759 x 10 6 7.75 x 10 6 24.8 x 10 6 8.43 x 10 6/6.06 x 10 6 12) Containment air 0.951 x 10 6 0.951 x 10 6 2.35 x 10 6 1.13 x 10 6/1.24 x 10 6 13) Containment steam 0.365 x 10 6 0.365 x 10 6 1.18 x 10 6 6.04 x 10 6/2.9 x 10 6 14) Suppression pool water 639 x 10 6 629 x 10 6 1040 x 10 6 1450 x 10 6/1200 x 10 6 15) Heat transferred by heat exchangers 0 0 0 818 x 10 6/289 x 10 6 a Values given are for minimum ECCS available and for all ECCS available. The information presented in this table is based on the origin al design basis conditions and represents the general characteristics of the recirculation line break analysis results.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-78 Table 6.2-8

Accident Chronology Design Basis Recirculation Line Break Accident Minimum ECCS Time (sec) OriginalRated Power Uprated Power

1. Vents cleared 0.776 0.709 2. Drywell reaches peak pressure 19.08 11.9
3. Maximum positive differential pressure occurs 0.749 0.600 4. ECCS initiation sequence completed 30 30 5. End of blowdown 53.24 131
6. Vessel reflooded 160 153
7. Introduction of RHR heat exchanger 600 600
8. Containment reaches peak secondary pressure 29,463 25,382 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-79 Table 6.2-9a

Reactor Blowdown Data for Recirculation Line Break

Original Rated Power Time (sec) Steam Flow (lb/sec) Liquid Flow (lb/sec) Steam Enthalpy (Btu/lb) Liquid Enthalpy (Btu/lb) 0 0 25,690 ---- 550.73 10.33 0 26,020 ---- 555.9 19.08 0 25,570 ---- 548.79

19.12 3679 13,320 1190 550 25.33 3213 8,493 1200.6 502 32.02 2420 4,974 1205.4 446.68

39.05 1494 2,423 1203.13 396.1 45.02 729.2 2,003 1193.79 325.16

53.37 0 0 ---- ----

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-80 Table 6.2-9b

Reactor Blowdown Data for Recirculation Line Break

Uprated Power Time (sec) Pressure (psia) a Liquid Flow (lbm) Steam Flow (lbm) 1.01 1018 3.246E+04 0 5.04 1027 2.625E+04 0 10.23 1039 2.485E+04 31.07 15.04 919 1.161E+04 3112 20.04 774.3 1.180E+04 2404 25.04 641.1 1.076E+04 1985 30.04 533.1 8.849E+03 1759 34.42 433.9 7.179E+03 1559 49.76 205.4 1.162E+04 0 62.26 147.0 9708 0 71.63 122.0 8858 0 81.01 105.6 8306 0 90.38 88.42 7560 0 102.88 71.76 6752 0

112.26 62.71 6369 0

121.63 50.97 5976 0

131.01 42.81 741.6 0 a Containment codes assume sa turated conditions in vessel.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-81 Table 6.2-10

Reactor Blowdown Data for Main Steam Line Break

Time (sec) Steam Flow (lb/sec) Liquid Flow (lb/sec) Steam Enthalpy (Btu/lb) Liquid Enthalpy (Btu/lb) 0 8646 0 1190.16 ----

4.3 1308 27,480 1190.45 549.66 10.43 2084 24,220 1192.72 540.93 20.43 2843 15,730 1201.0 499.0 30.12 2380 7386 1205.6 432.78 40.21 1110 2734 1197.45 344.32 54.65 0 0 ---- ----

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.2-82 Table 6.2-11

Core Decay Heat Following Loss-of-Coolant Accident for Containment Analyses

Time (sec)

Original Rated Power Normalized Core Heat a Uprated Power Normalized Core Heat b 0.0 1.0 1.0029 0.9 0.9330 0.7053 2.1 0.7662 0.5468

5.0 0.5005 0.5533

6.93 0.3850 0.4975

9.03 0.2955 0.4119 15.93 0.1491 0.2182

30.0 0.0471 0.07730 10 2 0.0381 0.03436 10 3 0.0223 0.01956 10 4 0.0119 0.01012 10 5 0.00668 0.00546 10 6 0.00267 3 x 10 6 0.00190 a A normalized power level of 3462 MWt was used for analyses of original rated power and includes fuel relaxation energy.

b A normalized power level of 3702 MWt was used for analyses at uprated power. Uprated power case includes metal water reac tion and fuel relaxation energy.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.2-83 Table 6.2-12

Secondary Containment De sign and Performance Data

I. Secondary Containment Design A. Free volume:

3.5 x 10 6 ft 3; the entire secondary containment is considered as one volume.

B. Pressure

1. Normal operation:

Vacuum greater than or equal to 0.25 in. of vacuum water gauge as indicated at the reac tor building el. 572 ft

2. Postaccident:

Vacuum greater than or equal to 0.

25 in. of vacuum water gauge on all building surfaces C. Infiltration rate duri ng postaccident period:

100% of free volume in a 24-hr period.

D. Exhaust fans (SGT system):

Two independent and redundant filter trains each with two full capacity exhaust fans (see Section 6.5.1) E. The secondary containment model afte r a design basis LOCA is discussed in Section 6.2.3.3.1.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-08-028 6.2-84 Table 6.2-14

Containment Penetrations Subject to Type B Tests Penetration Number Type Service Comments I. Electrical Penetrations X-100 A, B, C, and D X-101 A, B, C, and D X-102 A and B X-103 A, B, C, and D X-104 A, B, C, and D

X-105 A, B, C, and D

X-106 C and D

X-107 A and B Neutron monitoring Control rod position indicator

Thermocouple and RTD Medium voltage power Low voltage power

Control and indication neutron monitoring Low voltage power control

and indication Electrical penetrations are provided with double seals and are separately testable. The test taps and seals are located such that tests of

the primary can be

conducted without entry

into or pressurization of

containment II. Personnel And Equipment Access Penetrations X-15 Equipment hatch Separately testable without pressurization of the primary containment.

X-16 X-28 X-51 Personnel access lock

CRD removal hatch Suppression chamber access

hatch X-1A through 1H X27-A through 27F

N/A Inspection ports TIP drive flanges

Drywell head X-23 X-24 EDR-V-18 FDR-V-15 Inboard flange

Inboard flange X-77Aa RRC-V-19

RRC-V-20 Inboard & outboard

flanges Inboard flange X-77Ac PSR-V-X77A/1 PSR-V-X77A/2 Inboard & outboard flanges Inboard flange X-77Ad PSR-V-X77A/3 PSR-V-X77A/4 Inboard & outboard

flanges Inboard flange

Table 6.2-16 Primary Containment Isolation Valves Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011 6.2-85CRD 185 insert lines 9 4.6-5 55 B -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- Yes 5 4, 48a CRD 185 withdrawal lines 10 4.6-5 55 B -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- Yes 5 4, 48a Air line for maintenance 93 6.2-55 56 B -- Pipe cap I -- -- -- -- -- O/C LC -- 2 -- -- No A Cap SB No 5 54 All inst lines from pri cont -- -- 56 B -- EF check O Spring EF O O O -- 1/1.5 -- -- -- -- Vlv RB No 5 53 All inst lines from pri cont -- -- 56 B -- Globe O Manual Manual -- -- O O O -- 1/1.5 -- -- -- -- Vlv RB No 5 All inst lines from RPV -- -- 55 A -- EF check O Spring EF -- -- O O O -- .75/1 -- -- -- -- Vlv RB No 5 27 All inst lines from RPV -- -- 55 A -- Globe O Manual Manual -- -- O O O -- .75/1 -- -- -- -- Vlv -- No 5 Deacon soltn return

header 95 6.2-59 56 B -- Pipe cap O -- -- -- -- C C C -- .75 -- -- No W Cap RB No 4 Deacon soltn supply

header 94 6.2-59 56 B -- Pipe cap O -- -- -- -- C C C -- .75 -- -- No W Cap RB No 4

Air line WW-DW vac RVs 82e 6.2-41 56 B CAS-V-730 Globe O Manual Manual -- -- LC LC LC -- 1 -- 5 No A Vlv RB No 5 44, 54 Air line WW-DW vac RVs 82e 6.2-53 56 B CAS-VX-82e Globe O Manual Manual -- -- LC LC LC -- 1 -- -- No A Vlv RB No 5 44, 54 DW vent ex 3 6.2-45 56 B CEP-V-1A AO butfy O Air Spring F,A,Z RM C C C C 30 4 12 No A Vlv RB No 2 56 DW vent ex 3 6.2-45 56 B CEP-V-1B AO globe O Air Spring F,A,Z RM C C C C 2 4 12 No A Vlv RB No 5 56 DW vent ex 3 6.2-45 56 B CEP-V-2A AO butfy O Air Spring F,A,Z RM C C C C 30 4 8 No A Vlv RB No 2 56 DW vent ex 3 6.2-45 56 B CEP-V-2B AO globe O Air Spring F,A,Z RM C C C C 2 4 8 No A Vlv RB No 5 56 WW vent ex 67 6.2-45 56 B CEP-V-3A AO butfy O Air Spring F,A,Z RM C C C C 24 4 12 Yes A Vlv RB No 2 56 RB to WW vac bkrs 67 6.2-45 56 B CEP-V-3B AO globe O Air Spring F,A,Z RM C C C C 2 4 12 No A Vlv RB No 5 56 WW vent ex 67 6.2-45 56 B CEP-V-4A AO butfy O Air Spring F,A,Z RM C C C C 24 4 10 No A Vlv RB No 2 56 RB to WW vac bkrs 67 6.2-45 56 B CEP-V-4B AO globe O Air Spring F,A,Z RM C C C C 2 4 10 No A Vlv RB No 5 56 CIA for SRV accum 56 6.2-38 56 B CIA-V-20 MO globe I ac ac 41 RM O O O As is .75 No 10 No A Vlv RB Yes 5 56, 52 CIA for SRV accum 56 6.2-38 56 B CIA-V-21 Check I Process Process -- -- C C C -- .75 No A Vlv RB Yes 5 52 CIA line A for ADS accum 89B 6.2-38 56 B CIA-V-30A MO globe I ac ac 42 RM O O O As is .5 No 15 No A Vlv RB No 5 56 Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-10-028 6.2-86 CIA line B for ADS accum 91 6.2-38 56 B CIA-V-30B MO globe I ac ac 42 RM O O O As is .5 No 15 No A Vlv RB No 5 56 CIA line A for ADS accum 89B 6.2-38 56 B CIA-V-31A Check I Process Process -- -- C C C -- .5 -- -- No A Vlv RB No 5 CIA line B for ADS accum 91 6.2-38 56 B CIA-V-31B Check I Process Process -- -- C C C -- .5 -- -- No A Vlv RB No 5 DW vent supply 53 6.2-37 56 B CSP-V-1 AO butfy O Air Spring F,A,Z RM C C C C 30 4 4 No A Vlv RB Yes 2 56, 52 RB to WW vac bkrs 119 6.2-52 56 B CSP-V-10 PC check O Process Process -- RM C C C -- 24 -- 4 Yes A Vlv RB No 3 26, 56 DW vent supply 53 6.2-37 56 B CSP-V-2 AO butfy O Air Spring F,A,Z RM C C C C 30 4 1 No A Vlv RB Yes 2 56, 52 WW vent supply 66 6.2-37 56 B CSP-V-3 AO butfy O Air Spring F,A,Z RM C C C C 24 4 17 No A Vlv RB Yes 2 56, 52 WW vent supply 66 6.2-37 56 B CSP-V-4 AO butfy O Air Spring F,A,Z RM C C C C 24 4 14 No A Vlv RB Yes 2 56, 52 RB to WW vac bkrs 66 6.2-52 56 B CSP-V-5 AO butfy O Spring Air 40 RM C C C O 24 No 7 Yes A Vlv RB No C 56 RB to WW vac bkrs 67 6.2-45 6.2-52 56 B CSP-V-6 AO butfy O Spring Air 40 RM C C C O 24 No 9 Yes A Vlv RB No C 56 RB to WW vac bkrs 66 6.2-52 56 B CSP-V-7 PC check O Process Process -- RM C C C -- 24 -- 10 Yes A Vlv RB No 3 26, 56 RB to WW vac bkrs 67 6.2-45 6.2-52 56 B CSP-V-8 PC check O Process Process -- RM C C C -- 24 -- 16 Yes A Vlv RB No 3 26, 56 RB to WW vac bkrs 119 6.2-52 56 B CSP-V-9 AO butfy O Spring Air 40 RM C C C O 24 No 1 Yes A Vlv RB No C 56 RB to WW vac bkrs and vent supply 66 6.2-37 56 B CSP-V-93 SO globe O ac Spring F,A,Z RM C C C C 1 4 4 No A Vlv RW Yes 5 52, 56 DW vent supply 53 6.2-37 56 B CSP-V-96 SO globe O ac Spring F,A,Z RM C C C C 1 4 3 No A Vlv RW Yes 5 52, 56 DW vent supply 53 6.2-37 56 B CSP-V-97 SO globe O ac Spring F,A,Z RM C C C C 1 4 5 No A Vlv RB Yes 5 52, 56 RB to WW vac bkrs and vent supply 66 6.2-37 56 B CSP-V-98 SO globe O ac Spring F,A,Z RM C C C C 1 4 6 No A Vlv RB Yes 5 52, 56 DW service line 92 6.2-47 56 B DW-V-156 Gate O Manual Manual -- -- LC LC LC -- 2 -- 5 No W Vlv SB Yes 5 DW service line 92 6.2-47 56 B DW-V-157 Gate I Manual Manual -- -- LC LC LC -- 2 -- -- No W Vlv SB Yes 5 Drywell equip drain 23 6.2-39 56 B EDR-V-19 AO gate O Air Spring F,A RM O O C C 3 Std 2 No W Vlv RB No 2 56 Drywell equip drain 23 6.2-39 56 B EDR-V-20 AO gate O Air Spring F,A RM O O C C 3 Std 4 No W Vlv RB No 2 56 Drywell floor drain 24 6.2-46 56 B FDR-V-3 AO butfy O Air Spring F,A RM O O C C 3 Std 2 No W Vlv RB No 2 56 Drywell floor drain 24 6.2-46 56 B FDR-V-4 AO butfy O Air Spring F,A RM O O C C 3 Std 3 No W Vlv RB No 2 56 SP pool cleanup return 101 6.2-50 56 B FPC-V-149 MO gate O ac ac F,A RM C C C As is 6 35 41 No W Vlv RB Yes P 48a, 56SP pool cleanup suction 100 6.2-44 56 B FPC-V-153 MO gate O ac ac F,A RM C C C As is 6 35 2 No W Vlv RB Yes P 48a, 56

Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-08-028,09-007 6.2-87SP pool cleanup suction 100 6.2-44 56 B FPC-V-154 MO gate O ac ac F,A RM C C C As is 6 35 7 No W Vlv RB Yes M 48a, 56SP pool cleanup return 101 6.2-50 56 B FPC-V-156 MO gate O ac ac F,A RM C C C As is 6 35 3 No W Vlv RB Yes M 56, 48aHPCS suction relief 49 6.2-41 56 B HPCS-RV-14 Relief O pp Spring -- -- C C C -- 1 -- 65 Yes W Vlv RB No 5 19, 18, 48a HPCS discharge 49 6.2-41 56 B HPCS-RV-35 Relief O pp Spring -- -- C C C -- 2 -- 70 Yes W Vlv RB No 5 19, 18, 48a HPCS min flow 49 6.2-41 56 B HPCS-V-12 MO gate O ac ac 38 RM C C O/C As is 4 20 53 Yes W Vlv RB No H 56, 18, 66 HPCS suction from SP 31 6.2-49 56 B HPCS-V-15 MO gate O ac ac 46 ManualC C O/C As is 18 18 3 Yes W Vlv RB No H 48a, 56, 18 HPCS test line 49 6.2-41 56 B HPCS-V-23 MO globe O ac ac F,A RM C C C As is 12 Std 6 Yes W Vlv RB No H 56, 18, 66 HPCS to RPV 6 6.2-47 55 A HPCS-V-4 MO gate O ac ac 46 ManualC C O/C As is 12 17 9 Yes W Vlv RB No C 56, 48b, 18HPCS to RPV 6 6.2-47 55 A HPCS-V-5 Check I Process Process -- -- C C O/C -- 12 -- -- Yes W Vlv RB No 3 3, 48b, 18 Air line for HPCS-V-5 78e 6.2-53 56 B HPCS-V-65 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for HPCS-V-5 78e 6.2-53 56 B HPCS-V-68 Globe O Manual Manual -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 LPCS min flow 63 6.2-41 56 B LPCS-FCV-11 MO globe O ac ac 38 RM C C O/C As is 3 No 87 Yes W Vlv RB No N 56, 66, 18 LPCS discharge RV 63 6.2-41 56 B LPCS-RV-18 Relief O pp Spring -- -- C C C -- 2 -- 50 Yes W Vlv RB No 5 19, 18, 48a LPCS suction RV 63 6.2-41 56 B LPCS-RV-31 Relief O pp Spring -- -- C C C -- 1 -- 25 Yes W Vlv RB No 5 19, 18, 48a LPCS pump suction 34 6.2-49 56 B LPCS-V-1 MO gate O ac ac 46 ManualO O O/C As is 24 No 2 Yes W Vlv RB No L 48a, 56, 18 LPCS test line 63 6.2-41 56 B LPCS-V-12 MO globe O ac ac F,V RM C C C As is 12 Std 4 Yes W Vlv RB No N 18, 56, 58, 66 LPCS to RPV 8 6.2-47 55 A LPCS-V-5 MO gate O ac ac 46 ManualC C O/C As is 12 27 22 Yes W Vlv RB No C 56,48b, 18, 58 LPCS to RPV 8 6.2-47 55 A LPCS-V-6 Check I Process Process -- -- C C O/C -- 12 -- -- Yes W Vlv RB No 3 3, 48b, 18, 58 Air line for LPCS-V-6 78d 6.2-53 56 B LPCS-V-66 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for LPCS-V-6 78d 6.2-53 56 B LPCS-V-67 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 MS lines drain inboard 22 6.2-41 55 A MS-V-16 MO gate I ac ac V,G, D,P RM C C C As is 3 25 -- No S Vlv TB Yes M 52, 56, 15 Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-09-007 6.2-88MS lines drain outboard 22 6.2-41 55 A MS-V-19 MO gate O dc dc V,G, D,P RM C C C As is 3 25 6 No S Vlv TB Yes N 52, 56, 15 MS line A inboard MSIV 18A 6.2-45 55 A MS-V-22A AO globe I Air Air/sp V,G, D,P RM O O/C C C 26 3-5 -- No S Vlv TB Yes 2 1, 15, 56, 63 MS line B inboard MSIV 18B 6.2-45 55 A MS-V-22B AO globe I Air Air/sp V,G, D,P RM O O/C C C 26 3-5 -- No S Vlv TB Yes 2 1, 15, 56, 63 MS line C inboard MSIV 18C 6.2-45 55 A MS-V-22C AO globe I Air Air/sp V,G, D,P RM O O/C C C 26 3-5 -- No S Vlv TB Yes 2 1, 15, 56, 63 MS line D inboard MSIV 18D 6.2-45 55 A MS-V-22D AO globe I Air Air/sp V,G, D,P RM O O/C C C 26 3-5 -- No S Vlv TB Yes 2 1, 15, 56, 63 MS line A outboard MSIV 18A 6.2-45 55 A MS-V-28A AO globe O Air Air/sp V,G, D,P RM O O/C C C 26 3-5 4 No S Vlv TB Yes 2 1, 15, 56, 63 MS line B outboard MSIV 18B 6.2-45 55 A MS-V-28B AO globe O Air Air/sp V,G, D,P RM O O/C C C 26 3-5 4 No S Vlv TB Yes 2 1, 15, 56, 63 MS line C outboard MSIV 18C 6.2-45 55 A MS-V-28C AO globe O Air Air/sp V,G, D,P RM O O/C C C 26 3-5 4 No S Vlv TB Yes 2 1, 15, 56, 63 MS line D outboard MSIV 18D 6.2-45 55 A MS-V-28D AO globe O Air Air/sp V,G, D,P RM O O/C C C 26 3-5 4 No S Vlv TB Yes 2 1, 15, 56, 63 MS line A drain isolation 18A 6.2-45 55 A MS-V-67A MO gate O ac ac V,G, D,P RM C C C As is 1.5 15 5 No S Vlv TB Yes 5 15, 56, 63 MS line B drain isolation 18B 6.2-45 55 A MS-V-67B MO gate O ac ac V,G, D,P RM C C C As is 1.5 15 5 No S Vlv TB Yes 5 15, 56, 63 MS line C drain isolation 18C 6.2-45 55 A MS-V-67C MO gate O ac ac V,G, D,P RM C C C As is 1.5 15 5 No S Vlv TB Yes 5 15, 56, 63 MS line D drain isolation 18D 6.2-45 55 A MS-V-67D MO gate O ac ac V,G, D,P RM C C C As is 1.5 15 5 No S Vlv TB Yes 5 15, 56, 63 MS line A loop isolation 18A 6.2-45 55 A MSLC-V-3A Gate O Manual Manual -- -- C C C -- 1.5 -- 10 No S Vlv RB Yes 5 63 MS line B loop isolation 18B 6.2-45 55 A MSLC-V-3B Gate O Manual Manual -- -- C C C -- 1.5 -- 10 No S Vlv RB Yes 5 63 MS line C loop isolation 18C 6.2-45 55 A MSLC-V-3C Gate O Manual Manual -- -- C C C -- 1.5 -- 10 No S Vlv RB Yes 5 63 MS line D loop isolation 18D 6.2-45 55 A MSLC-V-3D Gate O Manual Manual -- -- C C C -- 1.5 -- 10 No S Vlv RB Yes 5 63 Decon soltn supply

header 94 6.2-59 56 B MWR-V-124 Globe O Manual Manual -- -- LC LC LC -- .75 -- -- No W Cap RB No 5 Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011 6.2-89Decon soltn return

header 95 6.2-59 56 B MWR-V-125 Globe O Manual Manual -- -- LC LC LC -- .75 -- -- No W Cap RB No 5 Rad mon return (S-SR-20) 72f 6.2-54 56 B PI-V-X72f/l Check I Process Process -- -- O O C -- 1 -- -- No A Vlv RB No 5 Rad mon return (S-SS-21) 73e 6.2-54 56 B PI-V-X72e/l Check I Process Process -- -- O O C -- 1 -- -- No A Vlv RB No 5 Inst lines - H2 to cont 42c 9.4-8 56 B PI-EFC-X42C EF check O Spring EF -- -- O O O -- 1 -- -- Yes A, S Vlv RB No 5 53 Inst lines - H2 to cont 78a 9.4-8 56 B PI-EFC-X78A EF check O Spring EF -- -- O O O -- 1 -- -- Yes A, S Vlv RB No 5 53 Inst lines - H2 to cont 42c 9.4-8 56 B PI-V-X42C Globe O Manual Manual -- -- O O O -- 1 -- -- Yes A, S Vlv RB No 5 53 Inst lines - H2 fm cont 72c 9.4-8 56 B PI-V-X72C Globe O Manual Manual -- -- O O O -- 1 Vlv No 5 Inst lines - H2 fm cont 72d 9.4-8 56 B PI-V-X72D Globe O Manual Manual -- -- O O O -- 1 Vlv No 5 Inst lines - H2 fm cont 72e 9.4-8 56 B PI-V-X72E Globe O Manual Manual -- -- O O O -- 1 Vlv No 5 Inst lines - H2 fm cont 73c 9.4-8 56 B PI-V-X73C Globe O Manual Manual -- -- O O O -- 1 Vlv No 5 Inst lines - H2 fm cont 73d 9.4-8 56 B PI-V-X73D Globe O Manual Manual -- -- O O O -- 1 Vlv No 5 Inst lines - H2 to cont 78a 9.4-8 56 B PI-V-X78A Globe O Manual Manual -- -- O O O -- 1 -- -- Yes A, S Vlv RB No 5 53 Inst lines - H2 fm cont 82c 9.4-8 56 B PI-V-X82C Globe O Manual Manual -- -- O O O -- 1 Vlv No 5 Inst lines - H2 fm cont 84b 9.4-8 56 B PI-V-X84B Globe O Manual Manual -- -- O O O -- 1 Vlv No 5 Air line for RHR-V-50A 42d 6.2-53 56 B PI-VX-216 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for RHR-V-41B 54Bf 6.2-53 56 B PI-VX-218 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for RHR-V-41A 61f 6.2-53 56 B PI-VX-219 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for RHR-V-41C 62f 6.2-53 56 B PI-VX-220 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for RHR-V-50B 69c 6.2-53 56 B PI-VX-221 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Rad mon supply (S-SR-20) 85a/c 6.2-54 56 B PI-VX-250 SO globe O ac Spring F,A RM O O C C 1 5 -- No A Vlv RB No 5 56 Rad mon supply (S-SR-20) 85a/c 6.2-54 56 B PI-VX-251 SO globe O ac Spring F,A RM O O C C 1 5 -- No A Vlv RB No 5 56 Rad mon return (S-SR-20) 72f 6.2-54 56 B PI-VX-253 SO globe O ac Spring F,A RM O O C C 1 5 -- No A Vlv RB No 5 56 Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011 6.2-90Rad mon return (S-SR-21) 29a/c 6.2-54 56 B PI-VX-256 SO globe O ac Spring F,A RM O O C C 1 5 -- No A Vlv RB No 5 56 Rad mon return (S-SR-21) 29a/c 6.2-54 56 B PI-VX-257 SO globe O ac Spring F,A RM O O C C 1 5 -- No A Vlv RB No 5 56 Rad mon return (S-SR-21) 73e 6.2-54 56 B PI-VX-259 SO globe O ac Spring F,A RM O O C C 1 5 -- No A Vlv RB No 5 56 Inst lines - H2 fm cont 72c 9.4-8 56 B PI-VX-262 SO globe O ac Spring -- RM O O O C 1 NA -- Yes A, S Vlv RB No 5 53 Inst lines - H2 fm cont 72d 9.4-8 56 B PI-VX-263 SO globe O ac Spring -- RM O O O C 1 NA -- Yes A, S Vlv RB No 5 53 Inst lines - H2 fm cont 72e 9.4-8 56 B PI-VX-264 SO globe O ac Spring -- RM O O O C 1 NA -- Yes A, S Vlv RB No 5 53 Inst lines - H2 fm cont 82c 9.4-8 56 B PI-VX-265 SO globe O ac Spring -- RM O O O C 1 NA -- Yes A, S Vlv RB No 5 53 Inst lines - H2 fm cont 73c 9.4-8 56 B PI-VX-266 SO globe O ac Spring -- RM O O O C 1 NA -- Yes A, S Vlv RB No 5 53 Inst lines - H2 fm cont 73d 9.4-8 56 B PI-VX-268 SO globe O ac Spring -- RM O O O C 1 NA -- Yes A, S Vlv RB No 5 53 Inst lines - H2 fm cont 84b 9.4-8 56 B PI-VX-269 SO globe O ac Spring -- RM O O O C 1 NA -- Yes A, S Vlv RB No 5 53 Air line for RHR-V-50A 42d 6.2-53 56 B PI-VX-42d Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for RHR-V-41B 54Bf 6.2-53 56 B PI-VX-54Bf Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for RHR-V-41A 61f 6.2-53 56 B PI-VX-61f Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for RHR-V-41C 62f 6.2-53 56 B PI-VX-62f Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Air line for RHR-V-50B 69c 6.2-53 56 B PI-VX-69c Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 PASS DW atm 73f 6.2-57 56 B PSR-V-X73-1 SO gate I ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS DW atm 73f 6.2-57 56 B PSR-V-X73-2 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS jet pump #10 77Ac 6.2-57 55 A PSR-V-X77A1 SO globe I ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 50, 56, 48a PASS jet pump #10 77Ac 6.2-57 55 A PSR-V-X77A2 SO globe O ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 50, 56, 48a PASS jet pump #20 77Ad 6.2-57 55 A PSR-V-X77A3 SO globe I ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 50, 56, 48a PASS jet pump #20 77Ad 6.2-57 55 A PSR-V-X77A4 SO globe O ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 50, 56, 48a Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-08-028 6.2-91PASS DW atm 80b 6.2-57 56 B PSR-V-X80-1 SO gate I ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS DW atm 80b 6.2-57 56 B PSR-V-X80-2 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS SP return 82d 6.2-58 56 B PSR-V-X82-1 SO gate O ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 50, 48a 56 PASS SP return 82d 6.2-58 56 B PSR-V-X82-2 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 48a PASS WW atm return 82f 6.2-58 56 B PSR-V-X82-7 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS WW atm return 82f 6.2-58 56 B PSR-V-X82-8 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS WW atm 83a 6.2-58 56 B PSR-V-X83-1 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS WW atm 83a 6.2-58 56 B PSR-V-X83-2 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS WW atm 84f 6.2-58 56 B PSR-V-X84-1 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS WW atm 84f 6.2-58 56 B PSR-V-X84-2 SO gate O ac Spring -- RM C C O C 1 No -- No A Vlv RW Yes 5 50, 56, 52 PASS line SP 88 6.2-58 56 B PSR-V-X88-1 SO gate O ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 48a, 50, 56, 64 PASS line SP 88 6.2-58 56 B PSR-V-X88-2 SO gate O ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 50, 56, 64, 48aRCC inlet header 5 6.2-55 56 B RCC-V-104 MO gate O ac ac F,A -- O O C As is 10 60 5 No W Vlv RB Yes 4 56 RCC outlet header 46 6.2-50 56 B RCC-V-21 MO gate O ac ac F,A -- O O C As is 10 60 3 No W Vlv RB No 4 56 RCC outlet header 46 6.2-50 56 B RCC-V-40 MO gate I ac ac F,A -- O O C As is 10 60 -- No W Vlv RB No 4 56 RCC outlet header 46 6.2-50 56 B RCC-V-219 Check I Process Process -- -- C C C -- 0.5 -- -- No W Vlv RB No 3 RCC inlet header 5 6.2-55 56 B RCC-V-5 MO gate O ac ac F,A -- O O C As is 10 60 3 No W Vlv RB Yes 4 56 RPV head spray 2 6.2-40 55 A RCIC-V-13 MO gate O dc dc 34 RM C O/C O/C As is 6 15 21 No W Vlv RB No C 56, 48b, 18 Air line - spare 54Aa 6.2-53 56 B RCIC-V-184 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No W Vlv RB No 5 RCIC min flow 65 6.2-43 56 B RCIC-V-19 MO globeO dc dc 33 RM C C O/C As is 2 22 7 No W Vlv RB No 5 22, 56, 18, 66 Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-08-028 6.2-92RCIC vac pump dis 64 6.2-52 56 B RCIC-V-28 Check O Process Process -- -- C O O/C -- 1.5 -- 5 No W Vlv RB No 5 18, 66 RCIC suct from SP 33 6.2-49 56 B RCIC-V-31 MO gate O dc dc 32 RM C O O/C As is 8 No 2 No W Vlv RB No N 48a, 56, 18 RCIC turb ex and ex vacuum breaker 4/116 6.2-58 56 B RCIC-V-40 Check O Process Process -- -- O C O/C -- 10 -- 17 No S Vlv RB No 3 49 RCIC turb steam supply 21/45 6.2-40 55 A RCIC-V-63 MO gate I ac ac K RM O O/C O/C As is 10 16 -- Yes S Vlv RB Yes M 51, 56, 52 RHR cond mode steam supply 21 6.2-40 55 A RCIC-V-64 MO gate O Manual Manual -- -- LC LC LC As is 10 -- 2 Yes S Vlv RB No 1 39 RPV head spray 2 6.2-40 55 A RCIC-V-66 Check I Process Process -- -- C O O/C -- 6 -- -- No W Vlv RB No 3 48b, 18RCIC turb ex and ex vacuum breaker 4/116 6.2-58 56 B RCIC-V-68 MO gate O dc dc 35 RM O O O/C As is 10 No 10 No S Vlv RB No C 22, 56 RCIC vacuum pump dis 64 6.2-52 56 B RCIC-V-69 MO gate O dc dc 36 RM O O O/C As is 1.5 No 3 No W Vlv RB No 5 22, 56, 18, 66 Air line - spare 54Aa 6.2-53 56 B RCIC-V-740 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RPV head spray 2 6.2-40 55 A RCIC-V-742 Globe O Manual Manual -- -- LC LC LC -- 0.75 -- 3 No W Vlv RB No 5 48b RCIC steam supply bypass 21/45 6.2-40 55 A RCIC-V-76 MO globe I ac ac K RM C C C As is 1 22 -- No S Vlv RB Yes 5 56, 52 RCIC turbine steam supply 45 6.2-40 55 A RCIC-V-8 MO gate O dc dc K RM O O/C O/C As is 4 26 2 No S Vlv RB Yes P 51, 56, 52 RFW line A 17A 6.2-37 55 A RFW-V-10A Check I Process Process -- -- O O/C O/C -- 24 -- -- No W Vlv TB Yes 3 16, 52, 31 RFW line B 17B 6.2-37 55 A RFW-V-10B Check I Process Process -- -- O O/C O/C -- 24 -- -- No W Vlv TB Yes 3 16, 52, 31 RFW line A 17A 6.2-37 55 A RFW-V-32A PC check O Process Process/spring -- -- O O/C O/C -- 24 -- 2 No W Vlv TB Yes 3 52, 31 RFW line B 17B 6.2-37 55 A RFW-V-32B PC check O Process Process/spring -- -- O O/C O/C -- 24 -- 2 No W Vlv TB Yes 3 52, 31 RFW line A 17A 6.2-37 55 A RFW-V-65A MO gate O ac ac 31 ManualO O/C O/C As is 24 No 8 No W Vlv TB Yes C 56, 52, 31 RFW line B 17B 6.2-37 55 A RFW-V-65B MO gate O ac ac 31 ManualO O/C O/C As is 24 No 8 No W Vlv TB Yes C 56, 52, 31 Pump min flow 47 6.2-51 56 B RHR-FCV-64A MO globe O ac ac 38 RM C C O/C As is 3 20 22 Yes W Vlv RB No L 18, 56, 66 Pump min flow 48 6.2-51 56 B RHR-FCV-64B MO globe O ac ac 38 RM C C O/C As is 3 20 22 Yes W Vlv RB No L 18, 56, 66 Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 62 F INAL S AFETY A NALYSIS R EPORT December 2013 LDCN-12-020 6.2-93 Pump min flow 26 6.2-41 56 B RHR-FCV-64C MO globe O ac ac 38 RM C C O/C As is 3 20 30 Yes W Vlv RB No L 18, 56, 66 Heat exch thermal RV 117 6.2-39 56 B RHR-RV-1A Relief O pp Spring -- -- C C C -- .75 -- 188 No W Vlv RB No 5 18, 19, 48a Heat exch thermal RV 118 6.2-39 56 B RHR-RV-1B Relief O pp Spring -- -- C C C -- .75 -- 189 No W Vlv RB No 5 18, 19, 48a Discharge header RV 47 6.2-51 56 B RHR-RV-25A Relief O pp Spring -- -- C C C -- 1 -- 33 Yes W Vlv RB No 5 18, 19, 48a Discharge header RV 48 6.2-51 56 B RHR-RV-25B Relief O pp Spring -- -- C C C -- 1 -- 30 Yes W Vlv RB No 5 18, 19, 48a Discharge header RV 26 6.2-41 56 B RHR-RV-25C Relief O pp Spring -- -- C C C -- 1 -- 30 Yes W Vlv RB No 5 18, 19, 48a Flush line RV 118 6.2-39 56 B RHR-RV-30 Relief O pp Spring -- -- C C C -- .75 -- 34 No W Vlv RB No 5 18, 19, 48a Pump A and B suction

RV 48 6.2-51 56 B RHR-RV-5 Relief O pp Spring -- -- C C C -- 1 -- 20 Yes W Vlv RB No 5 18, 19, 48a Pump A suction RV 47 6.2-51 56 B RHR-RV-88A Relief O pp Spring -- -- C C C -- .75 -- 30 Yes W Vlv RB No 5 18, 48a Pump B suction RV 48 6.2-51 56 B RHR-RV-88B Relief O pp Spring -- -- C C C -- .75 -- 30 Yes W Vlv RB No 5 18, 48a Pump C suction RV 26 6.2-41 56 B RHR-RV-88C Relief O pp Spring -- -- C C C -- .75 -- 37 Yes W Vlv RB No 5 18, 19, 48a Heat exch cond 47 6.2-51 56 B RHR-V-11A MO gate O Manual Manual -- -- LC LC LC As is 4 -- 18 Yes W Vlv RB No 1 18, 39, 66 Heat exch cond 48 6.2-51 56 B RHR-V-11B MO gate O Manual Manual -- -- LC LC LC As is 4 -- No Yes W Vlv RB No 1 18, 39, 66 FDR system intertie 47 6.2-51 56 B RHR-V-120 Gate O Manual Manual -- -- LC LC LC -- 3 -- 7 No W Vlv RB No 1 54, 18, 66 FDR system intertie 47 6.2-51 56 B RHR-V-121 Gate O Manual Manual -- -- LC LC LC -- 3 -- 6 No W Vlv RB No 1 54, 18, 66 SDC return A 19A 6.2-48 55 A RHR-V-123A MO gate I ac ac F,L RM C O/C -- As is 1 15 -- Yes W Vlv RB No 5 56, 48b, 18 SDC return B 19B 6.2-48 55 A RHR-V-123B MO gate I ac ac F,L RM C O/C -- As is 1 15 -- Yes W Vlv RB No 5 56, 48b, 18 RHR cond pot drain A 117 6.2-39 56 B RHR-V-124A MO globe O Manual Manual 39 RM LC LC LC As is 1.5 Std 11 Yes W Vlv RB No 5 38, 18, 66 RHR cond pot drain A 117 6.2-39 56 B RHR-V-124B MO globe O Manual Manual 39 RM LC LC LC As is 1.5 Std 12 Yes W Vlv RB No 5 39, 18, 66 Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-08-028 6.2-94RHR cond pot drain B 118 6.2-39 56 B RHR-V-125A MO globe O Manual Manual 39 RM LC LC LC As is 1.5 Std 17 Yes W Vlv RB No 5 39, 18, 66 RHR cond pot drain B 118 6.2-39 56 B RHR-V-125B MO globe O Manual Manual 39 RM LC LC LC As is 1.5 Std 14 Yes W Vlv RB No 5 39, 18, 66 CAC drain A 117 6.2-39 56 B RHR-V-134A MO globe O Manual Manual -- -- LC LC LC LC 2 No 44 No W Vlv RB No 5 18, 65, 66 CAC drain B 118 6.2-39 56 B RHR-V-134B MO globe O Manual Manual -- -- LC LC LC LC 2 No 44 No W Vlv RB No 5 18, 65, 66 Drywell spray A 11A 6.2-42 56 B RHR-V-16A MO gate O ac ac 46 RM C C O/C As is 16 Std 26 Yes W Vlv RB No I 56, 18 Drywell spray B 11B 6.2-42 56 B RHR-V-16B MO gate O ac ac 46 RM C C O/C As is 16 Std 12 Yes W Vlv RB No I 56, 18 Drywell spray A 11A 6.2-42 56 B RHR-V-17A MO gate O ac ac 46 RM C C O/C As is 16 Std 24 Yes W Vlv RB No I 56, 18 Drywell spray B 11B 6.2-42 56 B RHR-V-17B MO gate O ac ac 46 RM C O O/C As is 16 Std 2 Yes W Vlv RB No I 56, 18 SDC 20 6.2-46 55 A RHR-V-209 Check I Process Process -- -- C C -- -- .75 -- -- No W Vlv RB No 5 48b, 18RHR test line C 26 6.2-41 56 B RHR-V-21 MO globe O ac ac F,V RM C C C As is 18 Std 34 Yes W Vlv RB No L 18, 56, 60, 66 RPV head spray 2 6.2-40 55 A RHR-V-23 MO globe O ac dc L, U,M, R RM C O/C C As is 6 Std 28 Yes W Vlv RB No C 56, 57, 59,48b, 18 RHR test A 47 6.2-51 56 B RHR-V-24A MO globe O ac ac F,V RM C C C As is 18 Std 12 Yes W Vlv RB No N 2, 18, 66, 28, 56 RHR test B 48 6.2-51 56 B RHR-V-24B MO globe O ac ac F,V RM C C C As is 18 Std 12 Yes W Vlv RB No N 2, 18, 66, 56, 57, 59 SP spray A 25A 6.2-43 56 B RHR-V-27A MO gate O ac ac F,V RM C C O/C As is 6 36 5 Yes W Vlv RB No N 2, 18, 56 SP spray B 25B 6.2-43 56 B RHR-V-27B MO gate O ac ac F,V RM C C O/C As is 6 36 6 Yes W Vlv RB No N 2, 18, 56 LPCI A 12A 6.2-47 55 A RHR-V-41A Check I Process Process -- -- C C O/C -- 14 -- -- Yes W Vlv RB No 3 3, 28, 48b, 18LPCI B 12B 6.2-47 55 A RHR-V-41B Check I Process Process -- -- C C O/C -- 14 -- -- Yes W Vlv RB No 3 3, 48b, 18, 57, 59 LPCI C 12C 6.2-47 55 A RHR-V-41C Check I Process Process -- -- C C O/C -- 14 -- -- Yes W Vlv RB No 3 3, 48b, 18, 60 Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-08-028 6.2-95LPCI A 12A 6.2-47 55 A RHR-V-42A MO gate O ac ac 46 RM C C O/C As is 14 27 21 Yes W Vlv RB No C 48b,56, 18, 28 LPCI B 12B 6.2-47 55 A RHR-V-42B MO gate O ac ac 46 RM C C O/C As is 14 27 20 Yes W Vlv RB No C 48b, 56, 18, 57, 59 LPCI C 12C 6.2-47 55 A RHR-V-42C MO gate O ac ac 46 RM C C O/C As is 14 27 20 Yes W Vlv RB No C 48b,56, 18, 60 RHR SP suction A 35 6.2-49 56 B RHR-V-4A MO gate O ac ac 46 RM O O/C O As is 24 No 2 Yes W Vlv RB No L 48a, 56, 61, 18, 20 RHR SP suction B 32 6.2-49 56 B RHR-V-4B MO gate O ac ac 46 RM O O/C O As is 24 No 2 Yes W Vlv RB No L 48a, 56, 61, 18, 20 RHR SP suction C 36 6.2-49 56 B RHR-V-4C MO gate O ac ac 46 RM O O/C O As is 24 No 2 Yes W Vlv RB No L 48a, 56, 61, 18, 20 SDC return A 19A 6.2-48 55 A RHR-V-50A Check I Process Process -- -- C O -- -- 12 -- -- Yes W Vlv RB No 3 3, 48b, 18, 28 SDC return B 19B 6.2-48 55 A RHR-V-50B Check I Process Process -- -- C O -- -- 12 -- -- Yes W Vlv RB No 3 3, 48b, 18, 57, 59 SDC return A 19A 6.2-48 55 A RHR-V-53A MO gate O ac ac M, L, U, R RM C O -- As is 12 40 5 Yes W Vlv RB No C 56,48b, 18, 28 SDC return B 19B 6.2-48 55 A RHR-V-53B MO gate O ac ac M, L, U, R RM C O -- As is 12 40 5 Yes W Vlv RB No C 56, 57, 59, 48b, 18Heat exch vent 117 6.2-51 56 B RHR-V-73A MO globeO ac ac 39 RM C O/C C As is 2 No 175 No A/W Vlv RB No 5 18, 56, 66 Heat exch vent 118 6.2-51 56 B RHR-V-73B MO globeO ac ac 39 ManualC O/C C As is 2 No 190 No A/W Vlv RB No 5 18, 56, 66 SDC 20 6.2-46 55 A RHR-V-8 MO gate O dc dc L, U, M, R RM C O -- As is 20 40 14 Yes W Vlv RB No N 56, 20, 48b, 61, 18 SDC 20 6.2-46 55 A RHR-V-9 MO gate I ac ac L, U, M, R RM C O -- As is 20 40 -- Yes W Vlv RB No N 48b, 56, 61, 18, 20 RRC pump A seal 43A 6.2-38 56 B RRC-V-13A Check I Process Process -- -- O O O -- .75 No -- No W Vlv RB No 5 -- RRC pump B seal 43B 6.2-38 56 B RRC-V-13B Check I Process Process -- -- O O O -- .75 No -- No W Vlv RB No 5 --

Table 6.2-16 Primary Containment Isola tion Valves (Continued)

Line Description Pent Figure GDC Code Gp (12)

Valve EPN Valve Type Loc Pwr to Open (5) Pwr to Close (5) Iso sig (9) Back Up Norm Pos (10)

SD Pos Post LOCA Fail Pos (6) Valve Size (14) Close Time (7,11) Dist to Pent Leads to ESF Proc Fld Leak Bar (13) Term Zone (13) Pot Bypass Leak SBO (62)

Notes C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011 6.2-96RRC pump A seal 43A 6.2-38 56 B RRC-V-16A MO gate O ac ac 45 RM O O O As is .75 No 2 No W Vlv RB No 5 56 RRC pump B seal 43B 6.2-38 56 B RRC-V-16B MO gate O ac ac 45 RM O O O As is .75 No 2 No W Vlv RB No 5 56 RRC sample line 77Aa 6.2-39 55 A RRC-V-19 SO globe I ac Spring A,C RM O C C/O C .75 5 -- No W Vlv TB Yes 5 56, 48aRRC sample line 77Aa 6.2-39 55 A RRC-V-20 SO globe O ac Spring A,C RM O C C/O C .75 5 -- No W Vlv TB Yes 5 56, 48aRWCU from reactor 14 6.2-46 55 A RWCU-V-1 MO gate I ac ac A,J,E RM O O C As is 6 16, 25 -- No W Vlv RW Yes M 51, 48a, 56RWCU from reactor 14 6.2-46 55 A RWCU-V-4 MO gate O dc dc A,J,E,Y, W RM O O C As is 6 16, 25 4 No W Vlv RW Yes 2 51, 48a, 56RFW line A 17A/ 17B 6.2-37 55 A RWCU-V-40 MO gate O ac ac 47 ManualO O O/C As is 6 No 24 No W Vlv TB Yes C 56, 52 Air line for maintenance 93 6.2-55 56 B SA-V-109 Gate O Manual Manual -- -- LC LC LC -- 2 -- 1 No A Cap SB No 5 54 SLC to RPV 13 6.2-48 55 A SLC-V-4A Explosive O -- -- -- -- C C C -- 1.5 -- 136 No W Vlv RB No 5 21 SLC to RPV 13 6.2-48 55 A SLC-V-4B Explosive O -- -- -- -- C C C -- 1.5 -- 136 No W Vlv RB No 5 21 SLC to RPV 13 6.2-48 55 A SLC-V-7 Check I Process Process -- C C C -- 1.5 -- -- No W Vlv RB No 5 TIP lines 27A -- 56 B TIP-V-1 SO ball O ac Spring A,F RM C C C C .375 5 2 No A Vlv RB No 5 29, 56 TIP lines 27D -- 56 B TIP-V-10 Exp shear O -- Exp 43 -- O O O O .375 -- 2 No A Vlv RB No 5 29 TIP lines 27E -- 56 B TIP-V-11 Exp shear O -- Exp 43 -- O O O O .375 -- 2 No A Vlv RB No 5 29 TIP lines 27F -- 56 B TIP-V-15 SO globe O ac Spring A,F -- O O C C 1 -- 2 No A Vlv RB Yes 5 52, 56 TIP lines 27B -- 56 B TIP-V-2 SO ball O ac Spring A,F RM C C C C .375 5 2 No A Vlv RB No 5 29, 56 TIP lines 27C -- 56 B TIP-V-3 SO ball O ac Spring A,F RM C C C C .375 5 2 No A Vlv RB No 5 29, 56 TIP lines 27D -- 56 B TIP-V-4 SO ball O ac Spring A,F RM C C C C .375 5 2 No A Vlv RB No 5 29, 56 TIP lines 27E -- 56 B TIP-V-5 SO ball O ac Spring A,F RM C C C C .375 5 2 No A Vlv RB No 5 29, 56 TIP lines 27F -- 56 B TIP-V-6 Check I Process Process -- -- O C C -- .5 -- 1 No A Vlv RB Yes 5 52 TIP lines 27A -- 56 B TIP-V-7 Exp ShearO -- Exp 43 -- O O O O .375 -- 2 No A Vlv RB No 5 29 TIP lines 27B -- 56 B TIP-V-8 Exp ShearO -- Exp 43 -- O O O O .375 -- 2 No A Vlv RB No 5 29 TIP lines 27C -- 56 B TIP-V-9 Exp ShearO -- Exp 43 -- O O O O .375 -- 2 No A Vlv RB No 5 29

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-09-007 6.2-97 Table 6.2-16

Primary Containment Isol ation Valves (Continued)

ISOLATION SIGNAL CODES a

Signal Description A b Reactor vessel low-low water level (Trip level 2)

C b High radiation - main steam line D b Line break - main steam line (ste am line tunnel high temperature, high differential temperature or steam line high flow)

E b Reactor water cleanup system high diffe rential flow or hi gh blowdown flow F b High drywell pressure G b Low condenser vacuum J b Line break in RWCU system - area high temperature or high differential temperature K b Line break in RCIC system (RCIC area high temperature, high differential temperature, or high steam flow), [Low steam pressure or turbine exhaust diaphragm high pressure are other signals not part of PCRVICS]

L b Reactor vessel low water level (Trip level 3) (A scram occurs at this level. This is the higher of the thre e low water level signals)

M b Line break in RHR shutdown cooling (high suction flow)

P b Low main steam line pressure at turbine inlet (RUN mode only)

R b RHR equipment area high temperature or high differential temperature RM Remote manual switch located in main control room U High reactor vessel pressure

V c Reactor vessel low-low-low water level (Trip level 1) W High temperature at outlet of RWCU system nonregenerative heat

exchanger Y Standby liquid control system actuated

Z b Reactor building ventilation e xhaust plenum hi gh radiation

a See notes 30 through 46 for is olation signals generated by th e individual system process control signals or for remote-manual closure based on information available to the operators. These notes are referenced in the "isolation signal" column.

b These are the isolation functions of the pr imary containment and reactor vessel isolation control system (PCRVICS). Other functions are provided for information only.

c Reactor vessel low-low-low water level (Trip level 1) is an isolation function of the primary containment and reactor vessel isolation control system (PCRVICS) for Group 1 valves only.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-98 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

ABBREVIATIONS/LEGEND Valve Type AO air-operatedEHO electrohydraulic operatedMO motor-operated PC p ositive closingSO Solenoid operated Location I inside containment O outside containment Power to Open/Close AC ac electrical power DC dc electrical powerEF excess flow p p p rocess fluid overpressurization p ro process, process flow spr spring Normal Position C closed LC locked closed LO locked open

O open SC sealed closed (lead)

Process Fluid A air H hydraulic fluid

S steam W water Termination Zone CS condensate storage tan k RR reactor building RW radwaste building SB service building TB turbine building C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-99 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

NOTES Type C testing is discussed in Figures 6.2-36 through 6.2-59 which shows the isolation valve arrangement. Unless otherwise noted all valves listed in Table 6.2-16 are Type C tested.

1. Main steam isolation valves require that both solenoid pilots be deenergized to close valves. Accumulator air pressu re plus spring set act together to close valves when both pilots are deenergized.

Voltage failure at only one pilot does not cause valve closure. The valves are designed to fully close in less than 10 sec.

2. Suppression cooling valves have interlocks th at allow them to be manually reopened after automatic closure. Th is setup permits suppression pool spray, for high drywell pressure conditions and/or suppression water cooling. When automatic signals are not present, these valves may be opene d for test or operating convenience.
3. The air test f unction is not used.
4. The CRD insert and withdraw lines are not subject to Type A testing since these pathways are not open to the Primary Containment atmosphere under post-DBA conditions (ANSI/ANS-56.8-1994, Section 3.2.5). These li nes would always remain filled with water and provide a water seal following a design basis accident (DBA) and therefore do not represent a gaseous fission product release pathway.

The CRD insert and withdraw lines are not subject to Type C testing, since these Primary Containment boundaries do not c onstitute potential Primary Containment

Atmospheric pathways during and following a design basis accident (NEI 94-01, Section 6.0, and ANSI/ANS-56.

8-1994, Section 3.3.1(1)).

The above positions are in compliance with NRC Regulatory Guide 1.163.

See Section 6.2.4.3.2.1.1.4 for additional design information.

5. Alternating current motor-operated valves required for is olation functions are powered from the ac standby power buses. Direct curre nt operated isolation valves are powered from station batteries.
6. All motor-operated isolation valves remain in the last position upon failure of valve power. All air-operated valves close in the safest position on motive air failure.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-09-007 6.2-100 Table 6.2-16

Primary Containment Isol ation Valves (Continued)

NOTES 7. STD - The close limit is base d on a standard minimum closing rate of 12 in. of nominal valve diameter per minute for ga te valves and 4 in. of valve stem travel per minute for globe valves. No - No limiting value of full stroke closure time is specified. The close limit is based on results from testing performed in accordance with ASME/ANSI OM Part 10 Section 3 Testi ng Requirements. 8. Reactor building ventilation exhaust plenum high radiation signal (Z) is generated by two trip units in each safety division. This requires a trip from both units in a division (fail-safe design) to initiate isolation. 9. Primary containment and reactor vessel isolation signals (PCRVIS) are indicated by letters. Isolation signals ge nerated by the individual system process control signals or for remote manual closure based on informati on available to the operator are discussed in the referenced notes in the "isolation signal" column.

10. Normal status position of valve (open or closed) is the position during normal power operation of the reactor (see Normal Pos ition column). Valves, blind flanges, and deactivated automatic valves that are within the primary containment or other areas administratively controlled to prohibit access for reasons of personne l safety ar e locked, sealed, or otherwise secured in the clos ed position. Valves 1.5 in. and smaller connected to vents, drains, or test connecti ons must be closed but need not be sealed. 11. The specified closure rates are as requi red for containment isolation or system operation, whichever is less.

Reported times are in seconds. 12. All isolation valves are Seismic Category I. 13. Used to evaluate primary containm ent leakage which ma y bypass the secondary containment emergency filtration system. 14. Reported sizes are the valve nominal diameters in inches. Size indicated is containment side of relief valve when relief valve size is not equal on both sides. 15. Reactor vessel low-low-low water level (Trip level 1) is an isolation function of the primary containment and reactor vessel isolation control system (PCRVICS) for Group 1 valves only.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-101 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

NOTES

16. Not Used.
17. Not Used.
18. These lines connect to systems outside of the primary containment which meet the requirements for a closed system. These systems are considered an extension of the primary containment. Any external leakage out of these systems, within the Reactor Building, is processed by the SGT system.
19. Relief valve setpoint greater than 77.5 ps ig (1.5 times containm ent design pressure).
20. The condensate system can be used to flush ECCS when connected by a spool piece.

The connection creates a potential secondary containment bypass leak path. This penetration is isolated from a potential s econdary containment bypa ss leak path through the condensate system by a blind flange in stalled on the RHR piping flange. The spool piece, COND-RSP-1, is connected to the conde nsate system with a blind flange on the other end.

21. Cannot be reshut after opening without disassembly.
22. See 6.2.4.3.2.2.1.2.
23. See 6.2.4.3.2.2.2.
24. Not Used.
25. DELETED.
26. The disc on the check valve is maintained in the close position during normal operation by means of a spring actuated lever arm and magnets embedded in the periphery of the disc. The magnetic and spring forces maintain the disc s hut until the differential force to open the valve exceeds approximately 0.

2 psid. The check valves have position indication lights which can alert the operators to the fact that the check valve is not fully closed. The operator can then remote ly shut the valve by means of a pneumatic operator. The operating switch is spring-return to neut ral so the vacuum breaker function will not be impaired.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-102 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

NOTES

27. Instrument lines that penetrate primary c ontainment conform to Re gulatory Guide 1.11. The lines that connect to the reactor pre ssure boundary include a restricting orifice inside containment, are Se ismic Category I and terminate in instruments that are Seismic Category I. The instrument lines also include manual is olation valves and excess flow check (EFC) valves. Manual and EFC valves have no active safety (containment isolation) function requirements. These penetrations will not be Type C

tested since the inte grity of the lines are continuous ly demonstrated during plant operations where subject to reac tor operating pressure. In addition, all lines are subject to the Type A test pressure on a regular inte rval. Leaktight integr ity is also verified with completion of functional and calibration surveillance activities as well as by visual inspection.

28. The condensate system can be used to flush ECCS when connected by a spool piece.

The connection creates a potential secondary containment bypass leak path. This penetration is isolated from a potential s econdary containment bypa ss leak path through the condensate system by a blind flange in stalled on the RHR piping flange. The spool piece, COND-RSP-2, is connected to the conde nsate system with a blind flange on the other end.

29. The ball valves are Type C tested in accordance with Appendix J of 10 CFR 50.

Because the shear valves have explosive squibs and require te sting to destruction, they are not Type C tested. Technical Specifica tions surveillance requi rements ensure shear valve operability.

See subsection 6.2.4.3.2.2.3.11 for a TIP system isolati on evaluation against General Design Criterion 56.

30. Deleted.
31. PCRVIS is not desirable since the feedwa ter system, although not an ESF system, could be a significant source of makeup after a LOCA which is not concurrent with a seismic event. Feedwater check valves on either side of the containment can provide immediate leak isolation. The feedwater block valves can, however, be remote-manually closed if there is no indication of feedwater flow.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-103 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

NOTES

32. The RCIC suppression pool suction valve is normally closed and does not receive an automatic isolation signal.

Operator action can be taken to remote-ma nually shut isolation valve RCIC-V-31. The system would be manually isolated on a react or building sump high level alarm if RCIC is determined to be the source of leakage in the r eactor building.

33. The RCIC minimum flow va lve is open only between the time of system initiation and the time at which the system flow to the RPV exceeds the pump minimum flow requirement. The valve is shut at all other times. Valve RCIC-V-19 auto closes when the turbine throttle valve is closed following a turbine trip. Should a leak occur when the valve is open, it will be detected by a high level alarm in the appropriate reactor building sump.
34. The RCIC injection valve is open only during RC IC turbine operation. Injection line check valves on either side of the containment can provide immediate leak isolation.

Valve RCIC-V-13 auto closes when the tu rbine throttle valve is closed following a turbine trip.

35. The RCIC steam exhaust va lve, RCIC-V-68, is normally open at all times. Should a leak occur, it would be detected and alarmed by the RCIC room high temperature leak detection system.
36. The RCIC vacuum pump discharge valve, RCIC-V-69, is normally open at all times. The valve could be remote-manually closed by the operator upon control room indication that vacuum can no longer be maintained in the ba rometric condenser.
37. DELETED
38. The minimum flow valve for an ECCS pump is open whenever the pump is running and the flow in the pump discharge line is belo w the trip setpoint. The valve is shut at all other times. Should a leak occur when the valve is open, it will be detected by a high level alarm in the approp riate reactor building sump.
39. These valves are deactivated. The valves are shown as motor operated, however, the power leads to the motors have been di sconnected and the handwheels have been chained and padlocked in the closed position.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-104 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

NOTES

40. Normally closed. Signaled to open if reactor building pressu re exceeds wetwell pressure by 0.5 psid (analytical limit). Valves automatically reshut when the above condition no longer exists. Operators use valve position indicator as confirmation of valve status.
41. Indication of containment instrument air main header pressure and a low pressure alarm exist in the main control room. The operator can remote-manually shut valve CIA-V-20 should the supply from the CN system or from the CAS cross-tie becomes

unavailable. Isolation check valve CI A-V-21 provides immediate isolation.

42. Indication of nitrogen bottle header pressure and a low pressure alarm exist in the main control room. The operator can remote-m anually shut valve CIA-V-30(A, B) should the nitrogen bottle bank pressure decrease be low the alarm setpoint. Isolation check valves CIA-V-31(A, B) provi de immediate isolation.
43. The TIP shear valves are remote-manually closed followi ng control room indication of the failure of the TIP ball valves to close.
44. Normally closed. Opened only when testing wetwell-to-drywell (WW-DW) vacuum breakers. Test connection upstream of outer isolation valve is nor mally open. Closed during testing.
45. The isolation valve can be remote-manually closed upon i ndication that the CRD or the RRC pumps have tripped. Isolation check valves RRC-V-13 (A, B) provide immediate isolation.
46. These valves are the ECCS and drywell spray suction and discharge isolation valves. There are no automatic isolat ion signals. The valve closur e requirement is indicated by a high level alarm in the appr opriate reactor building sump.
47. The isolation valve can be remote-manually closed upon indication that the RWCU pumps have tripped. The reactor feedwater isolation check valv es provide immediate isolation.

48a. Not subject to Type C l eak testing, per Primary Containment Leakage Rate Testing Program. Prepared per Option B of 10 CFR 50 Appendix J.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-105 Table 6.2-16

Primary Containment Isol ation Valves (Continued)

NOTES 48b. The isolation valve is test ed with water. The maximu m allowable leakage rate is included in the Technical Specifications.

49. Isolation for the RCIC turbine exhaust vacuum breaker lines (X-116) is provided by containment isolation valves in the RCIC turbine exhaust line (X-4) and the RHR combined return line (X-47, X-48) to th e suppression pool. Va lves RCIC-V-110 and RCIC-V-113 serve as an exte nsion of containment but do not function as containment isolation valves and will not require Type C testing.
50. System isolation valves are normally closed. The system is placed in operation following a LOCA for post accident sampling.

Valve position indication is provided in the main control room.

51. The limiting times for valve closure are base d on the pipe break isolation times used in the Environmental Equipment Qualification Program to establish the environmental

profiles for qualifying safety-related equipment within the reactor building.

52. The sum of the Type C leak rate tests fo r the potential bypass leak paths will not exceed 0.04 percent of primary containment volume per day.
53. Instrument lines that penetrate primary c ontainment conform to Re gulatory Guide 1.11.

These lines include manual is olation valves and excess flow check (EFC) valves, or solenoid-operated valves capable of remote operation from the control room. These lines are Seismic Category I and terminate at instrument racks that are Seismic Category I. Manual and EFC valves have no active safety (containment isolation) function requirements. These penetrations will not be Type C tested since the communicating lines are extens ions of primary containm ent and the valves do not receive automatic isolation signals. In addition, all lines are subject to the Type A test on a regular interval (excluding some local pressure instruments which are over-ranged or initiate RPS actuations by Type A test pressure). Section 6.2.4.4 discusses periodic actuation testing requirements.

54. These paths are not poten tial secondary containment bypass leakage paths and are not required to meet the require ments for secondary contai nment design. The piping system outside of the outermost containment isolation valve is aligned such that leakage past these valves will be released to secondary containment and be processed by standby gas treatment.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-106 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

NOTES

55. Not Used.
56. A channel check and channel calibration is required of the remote valve position indication.
57. The condensate system can be used to flush ECCS when connected by a spool piece.

The connection creates a potential secondary containment bypass leak path. This penetration is isolated from a potential s econdary containment bypa ss leak path through the condensate system by a blind flange in stalled on the RHR piping flange. The spool piece, COND-RSP-3, is connected to the conde nsate system with a blind flange on the other end.

58. The condensate system can be used to flush ECCS when connected by a spool piece.

The connection creates a potential secondary containment bypass leak path. This penetration is isolated from a potential s econdary containment bypa ss leak path through the condensate system by a blind flange inst alled on the LPCS piping flange. The spool piece, COND-RSP-5, is connected to the conde nsate system with a blind flange on the other end.

59. The condensate system can be used to flush ECCS when connected by a spool piece.

The connection creates a potential secondary containment bypass leak path. This penetration is isolated from a potential s econdary containment bypa ss leak path through the condensate system by a blind flange in stalled on the RHR piping flange. The spool piece, COND-RSP-6, is connected to the conde nsate system with a blind flange on the other end.

60. The condensate system can be used to flush LPCI C through a spool piece. The connection creates a potential secondary containment bypass leak path. This penetration is isolated from a potential s econdary containment bypa ss leak path through the condensate system by a blind flange installed on the RHR piping flange of COND-RSP-4.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-107 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

NOTES

61. A blind flange is installed downstream of valves RHR-V-108 and RHR-V-109. This blind is located in the RHR pump room C and ensures that ther e is no by-pass leakage from the RHR pump suction line to the condensate storage ta nks. The condensate system can be used to flush RHR shutdown cooling thro ugh a spool piece. The connection creates a potential secondary containment bypass leak path. This penetration is isolated from a potential s econdary containment bypa ss leak path through the condensate system by a blind flange installed on RHR-RSP-1.
62. This column provides the station blackout (SBO) criterion that was used for each primary containment isolation va lve to establish whether or not the valve needed to be assessed for closure capability in the event of an extended SBO.

The values provided in this column are defined as follows:

Criterion Basis for Exclusion

1 Valve is normally locked closed during operation.

2 Valve auto closes or fails cl osed on loss of ac power or air.

3 Valve is a check valve.

4 Valve is in nonradioactive closed-loop systems not expected to be breached during a SBO (the valv e cannot be in a line that communicates directly with th e containment atmosphere).

5 Valve is less than 3 in. nominal diameter.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-108 Table 6.2-16 Primary Containment Isol ation Valves (Continued)

NOTES Valves that did not meet one of these exclusion criteria were considered as "valves of concern." The alphabetic data provided in this column iden tifies how this set of valves was addressed:

Criterion Additional Basis for Exclusion

C Valve has an in-ser ies check valve that will provide for isolation of the penetration.

D Valve has an in-series valve that fails closed on an SBO.

M Valve has an in-series valve with SBO closure capability.

I The penetration is provided with an interlock that ensures closure of at least one of the contai nment isolation valves during operation.

H Valve is required to pr ovide for HPCS operation.

L For the associated penetration, GDC 56 is satisfied by a single isolation valve, connected to th e suppression pool with the line submerged and a high integrity closed loop system outside containment.

N Valve is required to be clos ed during power ope ration (open for brief periods for the purpose of performing a surveillance is acceptable) and the piping outs ide containment being a high integrity closed loop system.

P Valve is included in the table as being associated with a potential secondary containment bypass leakage path. It is not a primary containment isolation valve.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-08-028 6.2-109 Table 6.2-16

Primary Containment Isol ation Valves (Continued)

NOTES

63. Leakage rate not included in sum of Type B and C test.
64. These are potential seconda ry containment bypass leakage paths whenever the railroad bay doors are open. The valves are tested for leakage to ensure requirements for limiting secondary containment byp ass leakage are satisfied.
65. Valves RHR-V-134A and RHR-V-134B have been deac tivated. Blind flanges CAC-BF-3A and CAC-BF-3B provide containm ent pressure boundaries in the lines outboard of valves.
66. These valves are in lines that are below the minimum water level in the suppression pool and are part of closed systems outside of the primar y containment. Therefore, 10 CFR 50 Appendix J Type C and hydraulic local leak rate testing is not required.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-110 Table 6.2-17 Hydrogen Recombiner (Historical Information Only - System Has Been Deactivated In-Place)

1. Tag number CAC-HR-1A & 1B 2. Number of units 2 3. Type Skid-mounted package 4. Nominal flow 200 acfm at blower 5. Canned blower Rotary l obe, positive displacement pump enclosed within an ASME vessel 6. Drive Direct (15 hp motor) 7. Motor type Totally encl osed fan-cooled, Class H insulation, with maxi mum temperature rise of 125°C above 40°C ambient 8. Nominal pressure 7 psi across blower
9. Scrubber a. Type Stainless steel, ring packed tower b. Water flow 10 gpm (maximum) 10. Heater/Recombiner
a. Heater type Electri c, 27 U-tube elements b. Heater capacity 37 kW c. Recombiner type Catalytic d. Recombiner catalyst Houdry HSC-931, 0.5% Platinum on alumina 11. Aftercooler
a. Type Shell and tube heat exchanger b. Water flow 50 gpm (maximum) 12. Moisture Separator
a. Type Vertical vessel with demister at top 13. Seismic Category I

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-111 Table 6.2-19 Assumptions and Initial Conditions for Negative Pressure Design Evaluation A. Containment preincident conditions used for sizing internal vacuum breakers (wetwell to drywell) Drywell (DW) Suppression Chamber (WW) 1. Pressure, psig 0 0

2. Temperature, °F 150 50
3. Relative humidity, % 100 100

B. Containment preincident conditions used for sizing external vacuum breakers (reactor building to wetwell). Drywell (DW) Suppression Chamber (WW) 1. Pressure, psig -1.0 -0.5 2. Airspace temperature, °F 135 150

Pool temperature, F N/A 35 3. Relative humidity, % 100 100

Spray temperature is equivalent to suppression pool temperature.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-112 Table 6.2-19a Limiting Conditions for Maximum Negative Pressure Differentials Applied to Columbia Generating Station Specifications Maximum Negative Pressure Differential (psid)

Hypothetical Event DW-WW VBs RB-WW VBs DW Sprays WW-DW RB-WW DW-RB Remarks (1) Inadvertent spray activation 7 3 NA - - - Not possible due to containment high pressure interlock (2) Small pipe break liquid steam 7

7 2 2 1 a 1 a 0.5 0.5 0.66 0.51 1.16 1.01 (3) DBA 7 7 2 3 1 2 0.84 0.94 0.79 0.94 1.11 1.39 1 RB-WW VB failure Use of two sprays No VB failure VBs adequate (4) Vented drywell with a small steam leak 7 3 NA - - - Included in small pipe break event (2) (5) Normal heating and cooling

cycles 7 3 NA - - - Controlled with the primary containment cooling system a Drywell and wetwell sprays used in event mitigation from one RHR loop only.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-113 Table 6.2-20 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 6-in. RCIC Line* Steam Time (sec) Mass Rate (lb/sec) Energy Rate (Btu/sec x 10

3) 0.0 398.2 474.694 3.0 398.2 474.694
  • Original rated power - Reference 6.2-29.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-114 Table 6.2-21 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 6-in. RCIC Line* Water Time (sec) Mass Rate (lb/sec) Energy Rate (Btu/sec x 10

3) 0.0 0.0 0.0 0.001 331.1 388.347 0.004 205.6 195.094 0.010 398.3 231.811 0.015 598.8 329.639 0.020 700.0 381.430 0.025 724.4 392.915 0.050 580.0 311.576 0.10 394.2 198.953 0.20 144.6 59.387 0.30 52.4 18.555 0.40 35.1 8.884 0.50 46.1 11.046 1.00 45.9 10.585 1.50 36.0 7.639 1.90 30.4 6.314
  • Original rated power - Reference 6.2-30.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-115 Table 6.2-21 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 6-in. RCIC Line*

Water (Continued)

Time (sec) Mass Rate (lb/sec) Energy Rate (Btu/sec x 10

3) 2.00 21.1 4.378 2.50 23.3 4.523 3.00 3.2 0.611
  • Original rated power - Reference 6.2-30.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-116 Table 6.2-22 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 24-in. Recirculation Line* Steam Time (sec) Mass Rate (lb/sec x 10

3) Energy Rate (Btu/sec x 10
6) 0.0 0.0 0.0 21.0 0.0 0.0 21.01 3.2 3.815 30.00 2.4 2.861 40.00 1.3 1.550 47.00 2.0 2.384 47.01 4.0 4.768 48.00 0.0 0.0 50.00 0.0 0.0
  • Original rated power - Reference 6.2-31.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-117 Table 6.2-23 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 24-in. Recirculation Line* Water Time (sec) Mass Rate (lb/sec x 10

3) Energy Rate (Btu/sec x 10
6) 0.00 22.72 12.393 0.00159 22.72 12.393 0.00171 34.07 18.585 1.537 34.07 18.585 1.568 27.56 15.033 2.037 27.56 15.033 2.040 25.00 13.637 21.00 25.00 13.637 21.01 11.80 6.437 30.00 7.00 3.818 40.00 3.50 1.909 45.00 3.80 2.073 47.00 3.70 2.018 47.01 0.0 0.0 50.00 0.0 0.0
  • Original rated power - Reference 6.2-31.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-118 Table 6.2-24 Nodal Volume Data for the Case of a 6-in. RCIC Line Break and the Case of a 24-in. Recirculation Line Break*

Node Number Description Net Volume (ft 3) Elevation (Bottom, ft)

Height (ft) 1 Drywell above Bulkhead Plate 4,789.5 582.6 15.98 2 Drywell below Bulkhead Plate 195,759.5 499.6 83.1

  • Original rated power.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-119 Table 6.2-25 Flow Path Data for the Case of a 6-in. RCIC Line Break*

From Node To Node Flow Area (ft 2) Inertia (L/A, ft-1) Form Loss Coefficient Friction Factor f K F* K R** 1 2 4.926 0.4107 1.6 1.6 (See Note)1 2 4.666 1.60 4.090 4.102 (See Note)

Note: The fanning friction factor is automatically included by an internal calculation in the computer program and is variable with reynolds number.

K F* = K Forward K R** = KReverse

  • Original rated power.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-120 Table 6.2-26 Flow Path Data for the Case of a 24-in.

Recirculation Line Break*

From Node To Node Flow Area (ft 2) Inertia (L/A, ft-1) Form Loss Coefficient Friction Factor f K F* K R** 2 1 4.926 0.4107 1.6 1.6 (See Note)2 1 4.666 1.60 4.102 4.090 (See Note)

Note: The fanning friction factor is automatically included by an internal calculation in the computer program and is variable with reynolds number.

K F* = K Forward K R** = KReverse

  • Original rated power.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-121 Table 6.2-27 Peak Differential Pressure and Time of Peak*

Case Peak Differential Pressure, psi Time of Peak Differential Pressure, sec 6 in. RCIC Line Break In Upper Head Region 11.46 0.75 24 in. Recirculation Line In Lower Region 11.17 1.10

  • Original rated power.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-020 6.2-122 Table 6.2-28

Analytical Sequence of Even ts in Secondary Containment Post-LOCA Time Events in Secondary Containment 0 - Reactor building differential pressure is 0.0-in. w.g. between inside and outside of building

- Loss of offsite power

- All normal operating equi pment ceases to function 0.1 sec a - Emergency building lighting on (automatic) 15 sec - Emergency power on (automatic) 120 sec - Standby gas treatment system on (automatic) 300 sec - Full service water flow to ECCS pump room coolers 20 min - Building pressure reduced to -0.25-in. w.g.

1 hr b - Normal lighting off (manual) 12 hr - One fuel pool c ooling loop on (manual) a Analysis conservatively assume s emergency lighting is on afte r 0.1 sec even though diesels take 15 sec to restore power.

b Normal lighting terminates on FAZ. Analysis conservatively assumes failure to terminate for 1 hr.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-020 6.2-123 Table 6.2-30

Post-LOCA Transient Heat Input Rates to Secondary Containment

Heat Source Heat Input, Btu/hr Remarks Primary containment walls (PCW) q 1 = 33,161 (t pcw-t air), for t air< t pcw q 1 = 0, for t air > t pcw t pcw = 105°F constant tair, r = reactor building air temperature Normal equipment decay heat Electrical equipment (combined) q 2 = 1475 (150e-T-t air), for t air < 150e-T q 2 = 0, for t air > 150e-T Max. eq. surface

Temperature = 150°F

for T < 0 Piping (combined) q 3 = 664 (182e-T -t air ), for t air < 182 e-T q 3 = 0, for t air > 182e-T Max. eq. surface Surface temp= 182°F for t < 0 Emergency equipment Emergency lighting (t > 0 sec) q 4 = 203,700 Standby gas treatment system (T > 34 sec) q 5 = 8800 Emergency core cooli ng system (T > 30 sec) q 6 = 4476 (t cw - t air), for t air < t cw q 6 = 0, for t air > t cw T,hr tcw,*

o F 0 95 2 180 50 143 100 132 *cw = cooling water C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 6.2-124 Table 6.2-30 Post-LOCA Transient Heat Input Rates to Secondary Containment (Continued)

Heat Source Heat Input, Btu/hr Remarks Fuel pool

sensible heat q 7 = 299.2 (t pw-t air)4/3 t pw= pool water temp.

o F Pool evaporation heat q 8 = 1385.19 (t pw - t air)1/3 (W ps- W air) p t pw = pool water temp. °F W ps = humidity ratio Saturated moist air Evaluated at t pw of wet surface (1bw/1ba)

W ps = humidity ratio of moisture air (1bw/1ba) p = heat of vaporization (1bw/1ba)

Infiltration air heat-up q 9 = -0.24945 (t air - 100)> Structural steel heat-up q 10 = - 11400 (t air - t steel)4/3 t steel = steel temp (°F) Total Q = q 1 + q 2 + q 3 + q 4 + q 5 + q 6 + q 7 +q 8+ q 9 +q 10 Q q110 10 1 Typical 24 in. Downcomer Vent with Jet Deflector 900547.40 6.2-1 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Top View Of Jet Deflector Drywell Floor Downcomer1" Deflector Web Plates 3 1/2" Grating Jet Deflector El. 499'-6" El. 497'-6" W12 1'-2" 4" El. 501'-0" Saddle Clamps Downcomer Open End 1'-1/4" 1 1/4" 1/2" Columbia Generating StationFinal Safety Analysis Report Diagram of the Recirculation Line Break Location 900547.36 6.2-2 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.C A B Recirculation ReactorVessel Point Of Critical Flow A. Recirculation Line B. Cleanup Line C. Combined Area of All Jet Pump Nozzles Associated with the

Broken Loop Recirculation Loop PumpTo Reactor Water

Cleanup System Columbia Generating StationFinal Safety Analysis Report Pressure Response for Recirculation Line Break(Initial Containment Pressure 2 psig) 900547.37 6.2-3 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.75 50 25 0 0 10 20 30 40 Drywell PressureWetwell PressureTime (Seconds)

Pressure (Pisa)

Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Temperature Response for Recirculation LineBreak (Initial Containment Pressure 2 psig) 960222.02 6.2-4 0 10 20 30 40 50 150 250 350Time (Seconds)Drywell Temperature Temperature (degrees F)Wetwell Temperature Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev. Drywell Floor P Response for Recirculation Line Break (Initial Containment Pressure 2 psig) 960222.03 6.2-5 0 10 20 30 40 0 15 30 45 Time (Seconds)

Pressure Difference (psid)

Drywell-Wetwell Columbia Generating Station Final Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Containment Vent System Flow Rate for Recirculation (Initial Containment Pressure 2 psig) 960222.04 6.2-6 0 10 20 30 40 0 1 2 3 x10 4 Time (Seconds)

Vent Flow Rate (lb/seconds)

Air Vapor Liquid Columbia Generating Station Final Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Containment Pressure Response Cases A, B, and C - Original Rated Power 960222.67 6.2-7 Time (Seconds)

Containment Pressure (psig) 40 20 0 10 2 10 3 10 4 10 5 10 6 a) 3 LPCI, 1 HPCS, 1 LPCS, 2 HX, KHX = 578 b) 1 LPCI, 1 HPCS, 1 HX, KHX = 289

c) 1 LPCI, 1 HPCS, 1 HX, KHX = 289, No Containment Spray 30 10 c b a Columbia Generating Station Final Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Drywell Temperature Response Cases A, B, and C - Original Rated Power 960222.26 6.2-8 a) 3 LPCI, 1 HPCS, 1 LPCS, 2 HX, KHX = 578 b) 1 LPCI, 1 HPCS, 1 HX, KHX = 289

c) 1 LPCI, 1 HPCS, 1 HX, KHX = 289, No Containment Spray a b c 400 300 200 100 0 10 1 10 2 10 3 10 4 10 5 Time (Seconds) 10 6 Columbia Generating Station Final Safety Analysis Report Drywell Temperature (°F)

Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Suppression Pool Temperature Response, Long-Term Response - Original Rated Power 960222.27 6.2-9 a b.c 400 300 200 100 0 10 1 10 3 10 4 10 5 10 6 Time (Seconds) a) 2 HX, 3 LPCI, 1 HPCS, 1 LPCS, KHX = 589 W/Spray b) 1 HX, 1 LPCI, 1 HPCS, KHX = 289, W/Spray

c) 1 HX, 1 LPCI, 1 HPCS, KHX = 289, No Containment Spray Columbia Generating Station Final Safety Analysis Report Suppression Pool Temperature (°F)

Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Containment Pressure Response - Case C Uprated Power 960222.05 6.2-10 0 20 40 60 Pressure (psia)

Time (Seconds)

Drywell Pressure Wetwell Pressure Drywell Pressure Wetwell Pressure 10 1 10 2 10 3 10 4 10 5 Columbia Generating Station Final Safety Analysis Report Figure Amendment 57 December 2003 Form No. 960690 Draw. No.Rev.Drywell Temperature Response - Case C Uprated Power 960222.06 6.2-11 10 1 100 200 300 400 Time (Seconds)

Drywell Airspace Temperature Temperature (Degrees F) 10 2 10 3 10 4 10 5 Columbia Generating Station Final Safety Analysis Report LDCN-02-000 Figure Form No. 960690 Draw. No.Rev.Suppression Pool Temperature Response - Case C Uprated Power 960222.07 6.2-12 0 100 200 300 Time (Seconds)

Temperature (Degrees F)

Suppression Pool Temperature 10 1 10 2 10 3 10 4 10 5 Columbia Generating Station Final Safety Analysis Report Amendment 57 December 2003 LDCN-02-000 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Residual Heat Removal Rate 960222.15 6.2-13 0 50 100Time (hour) 125 25 750248101216182022242628303234363840424448 6 150 175 200 2 RHR Original Rated Power 1 RHR with Spray Original Rated Power 1 RHR Uprated Power Columbia Generating StationFinal Safety Analysis Report Heat Rate (BTU/hr x 1E6)

Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Effective Blowdown Area Main Steam Line Break 960222.28 6.2-14 4 3 2

1 0 Time (Seconds)

Flow Area (Ft 2)100 300 500 600 400 200 0 5 Columbia Generating Station Final Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Bounding Pressure Response - Main Steam Line Break Original Rated Power 960222.30 6.2-15 Pressure (psig)

Wetwell 30 20 10 0 0.1 1 10 10 2 10 3 Time (Seconds)

Drywell 40 Columbia Generating Station Final Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Bounding Temperature Response - Main Steam Line Break Original Rated Power 960222.29 6.2-16 Wetwell 300 200 100 0 0.1 1 10 10 2 10 3 Time (Seconds)

Temperature (°F)

Drywell Columbia Generating Station Final Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Pressure Response - Recirculation Line Break (0.1 ft 2) Original Rated Power 960222.31 6.2-17 Pressure (psig)Wetwell 30 20 10 0 0.1 1 10 10 2 10 3Time (Seconds)

Drywell 40 Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Temperature Response - Recirculation Line Break (0.1 ft 2) Original Rated Power 960222.32 6.2-18 Temperature (Degrees F)Wetwell 300 200 100 0 0.1 1 10 10 2 10 3Time (Seconds)

Drywell 400 Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Schematic of ECCS Loop 900547.39 6.2-19 ReactorVessel Suppression Pool M W s h s m D o h D m s o RHR Heat Exchanger hc, m eccs q H x Pump= Enthalpy Of Water Leaving Reactor, Btu/Lb= Flow Rate Out Of Reactor, Lb/Sec

= Enthalpy Of Water In Suppresion Pool, Btu/Lb

= Flow Out Of Suppression Pool, Lb/Sec

= Heat Removal Rate Of Heat Exchanger, Btu/Sec= Mass Of Water In Suppression Pool

= Core Decay Heat Rate, Btu/Sec

= Stored Energy Release Rate, Btu/Sec

= Enthalpy Of ECCS Flow To Reactor, Btu/Lb

= ECCS Flow Rate, Lb/Sec m D o h D m s o m eccs q H x h c M W s h s q D q e Columbia Generating StationFinal Safety Analysis Report Allowable Leakage Capacity (A/ K ft 2)Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Allowable Leakage Capacity 960222.39 6.2-20 ( )A DBA 2 A DBA 0.40 0.35 0.30 0.25 0.20 0.15 0.10 0.05 00.41.0 2.0 3.0 4.0 Primary System Break Area (ft 2)A K S Columbia Generating Station Final Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Containment Transient for Maximum Allowable Bypass Capacity A x = 0.050 960222.38 6.2-21 100 1000 10,000 500 400 300 200 100 0 70 (45)60 (35)50 (25)40 (15)30 (15)20 Time (seconds) a b d c a Drywell Pressure b Wetwell Pressure

c Drywell Temperature

d Wetwell Temperature Temperature (Degrees F)

Pressure psia (psig)

Significant portion

of transient has

ended; reactor

pressure has

been reduced to

containment

pressure.Time during which drywell sprays must be activated (41 min).Operator realizes that a leakage path exists.

These pressure decay curves are

approximations.

Containment Vessel Design Pressure, 60 psia Drywell Spray Actuation Pressure - 54 psia Columbia Generating Station Final Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Containment Transient for A/ K = 0.0045 ft 2 960222.37 6.2-22 100 1000 10,000 500 400 300 200 100 0 70 60 50 40 30 20Time (seconds)

Pressure (psia)Containment Vessel Design Pressure a b d c a Drywell Pressureb Wetwell Pressure c Wetwell Temperatured Suppression Pool TemperatureTemperature (Degrees F)

Significant portion

of transient has

ended; reactor

pressure has

been reduced to

containment

pressure.Columbia Generating StationFinal Safety Analysis Report Figure Not Available For Public Viewing 20.5"Venting Through Bulkhead Plate 920843.15 6.2-24 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.21.25" All Drawings not to Scale Blind Flange 20.5" FanVent PathVent PathVentilation Supply Duct Azimuth 195 , 3153" W.G.Relief Point9" W.G.Relief Point 20.5"Typ.Hot Air*Exhaust Vent Azimuth 75 , 255Open Vent Azimuth 15 , 135Plan View of Bulkhead Plate*Not Used in Compartment Pressure Analysis of Upper Head RegionUpper/Lower Bulkhead Plate Venting 0 315 255 195 180Vent 135 75 15 14.29'1.36'Columbia Generating StationFinal Safety Analysis Report Absolute Pressure in Upper Head Region andLower Region from 6 in. RCIC Line Break920843.11 6.2-25 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.28 24 20 16 12 8 4 0Absolute Pressure in the Drywell Above and Below the Bulkhead Plate from a 6 Inch RCIC Line Break Above Bulkhead Plate (Upper Head Region)

Below Bulkhead Plate (Lower Head Region) 0 0.5 1.0 1.5 2.0Time, Seconds Absolute Pressure, psia Columbia Generating StationFinal Safety Analysis Report Absolute Pressure in Lower Region andUpper Head Region from 24 in. RecirculationLine Break 920843.12 6.2-26 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.70 60 50 40 30 20 10 0Absolute Pressure in the Drywell Above and Below the Bulkhead Plate from a 24 Inch Recirculation Line Break Above Bulkhead Plate (Upper Head Region)

Below Bulkhead Plate (Lower Region) 0 0.5 1.0 1.5 2.0Time, Seconds Absolute Pressure, psia Columbia Generating StationFinal Safety Analysis Report Downward Pressure Differential Across BulkheadPlate from 6 In. Line Break 920843.13 6.2-27 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.14 12 10 8 6 4 2 0 0 0.5 1.0 1.5 2.0Time, Seconds Differential Pressure, psiDownward Pressure Differential Across Bulkhead Plate from 6 Inch RCIC Line Break Columbia Generating StationFinal Safety Analysis Report Upward Pressure Differential Across BulkheadPlate from 24 In. Recirculation Line Break 920843.14 6.2-28 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.14 12 10 8 6 4 2 0 0 0.5 1.0 1.5 2.0Time, Seconds Differential Pressure, psiUpward Pressure Differential Across Bulkhead Plate from a 24 Inch Recirculation Line Break Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Recirculation Break Blowdown Flow Rates Liquid Flow - Short-Term Original Rated Power 960222.10 6.2-29 0 20 40120140 0 10 20 35 Time (Seconds)

Vessel Liquid Blowdown Flow Rate (lb/sec x 1E3) 6080100 30 25 5 15 Columbia Generating Station Final Safety Analysis Report Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Recirculation Break Blowdown Flow Rates Steam Flow - Short-Term Original Rated Power 960222.11 6.2-30 0 20 40120140 0 1.0 2.0 3.5 Time (Seconds)

Vessel Steam Blowdown Flow Rate (lb/sec x 1E3) 6080100 3.0 2.5 0.5 1.5 Columbia Generating Station Final Safety Analysis Report Main Steam Line Break Blowdown Flow Rates Figure Amendment 53November 1998 Form No. 960690 Draw. No.Rev.960222.36 6.2-31051015202530354045505560 0 1 2

3 4 Liquid Flow Steam Flow Time (Seconds)

Vessel Flow Rates (lb/sec x 10 4)Columbia Generating Station Final Safety Analysis Report Figure Not Available For Public Viewing Figure Not Available For Public Viewing Post-LOCA Time (sec) 6.2-34 920843.17Long-Term Post-LOCA Secondary ContainmentTemperature Transient Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.Figure Amendment 59 December 2007 Form No. 960690FH LDCN-05-009 150 140 130 120 100 90 80 70 10 2 10 3 10 4 10 5 10 6 10 7 10 1 ECCS Pump Rooms Bulk Reactor Bldg Refuel Floor110Temperature ( F) 6.2-35 920843.16Short-Term Post-LOCA Secondary ContainmentPressure Transient Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.Figure Amendment 59 December 2007 Form No. 960690FH LDCN-05-009 14.74 14.72 14.70 14.68 14.66 14.64 14.62 14.60 14.58 14.56 14.54 1 ECCS Pump Rooms Atmospheric Pressure Bulk Reactor Bldg Refuel FloorPost-LOCA Time (sec) 10 2 10 3 10 4 10 5 10 6 10 1 Pressure (psia)

Notes on Type C Testing 920843.20 6.2-36 Figure Form No. 960690FH LDCN-08-028Draw. No.Rev.Notes on Type C Testing (Isolation Valve Leakage Testing)1. Type C testing is performed by applying a differential pressure in the same direction as seen by the valves during containment isolation.2. Type C testing is performed by pressurizing between the two-piece disk gate valve.3. Type C testing is performed by pressurizing between the isolation valves. The test yields conservative results since the inboard, globe valve is pressurized under the seat during the test; whereas, during containment isolation, it is pressurized above the seat.4. Type C testing is performed by pressurizing between the isolation valves. The test yields equivalent results for the inboard gate or butterfly valve. *

5. Type C testing is not required since a water seal is provided by the supression pool.6. Type C testing is performed by pressurizing between the isolation valves. The test yields equivalent results for the inboard gate valve.
  • The one-inch globe valve will have test pressure applied under the seat; however, the difference between testing a one-inch globe valve over or

under the seat is considered negligible.7. Type C testing is performed by pressurizing between the isolation valves. The one-inch globe valve will have test pressure applied over the seat for the inboard isolation valve and under the seat for the outboard isolation valve. The difference between testing under and over the seat

for a one-inch globe valve is considered negligible.8. Type C testing is performed by pressurizing between the isolation valves. The one-inch globe valve will have test pressure applied under the seat; however, the difference between testing a one-inch globe valve over or under the seat is considered negligible.* The gate and butterfly valves are because of symmetry of design and because of construction equally leak tight in either direction. This fact has been confirmed by review of leakage test data and other information supplied by the valve manufacturers.

Columbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 Isolation Valve Arrangement for PenetrationsX-53, X-66, X-17A and X-17B 920843.18 6.2-37 Figure Form No. 960690Draw. No.Rev.Note: See Note 1 on Figure 6.2-36 Reactor Feedwater Lines X-53 Drywell Purge and Inerting MakeupX-66 Wetwell Purge and Inerting Makeup Note: See Note 4 on Figure 6.2-36 AO AO MO MO MOCSP-V-1CSP-V-3CSP-V-2 CSP-V-4For X-66 Only See Fig. 6.2-52 X-53 (Drywell)X-66 (Wetwell)

Purge Supply TC N 2 SupplyCSP-V-97 CSP-V-98CSP-V-96 CSP-V-93 SO SORFW-V-65BRFW-V-32BRWCU-V-40RFW-V-65ARFW-V-32A X-17BRFW-V-10B TC X-17ARFW-V-10A TC TC TC Columbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 LDCN-10-028 Isolation Valve Arrangement for Penetrations X-89B, X-91, X-56, X-43A, and X-43B 920843.19 6.2-38 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 1 on Figure 6.2-36 RRC Pump Seal PurgeContainment Instrument Air MO Note: See Note 1 on Figure 6.2-36 MOCIA-V-30ACIA-V-30BCIA-V-20CIA-V-31A CIA-V-31BCIA-V-21 TC TC X-89B X-91 X-56 DrywellRRC-V-16A,B TC TCRRC-V-13A,B X-43A,B Drywell Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-117, X-118 and X-77Aa 920843.21 6.2-39 Note: See Note 1 on Figure 6.2-36 Note: See Note 5 on Figure 6.2-36 X-77AaRRC-V-19 TC TC Sample PointRRC-V-20Wetwell MO Structural Section TC TCX-117X-118RHR-RV-1A,BRHR-RV-30(X-118 Only)

MO MO MORHR-V-124A RHR-V-125A LCRHR-V-124B RHR-V-125B LCRHR-V-134A,B Deactivated LCRHR-V-73A,BRHR-V-176A,B Deactivated 2" Flanged Joint See Figure 6.2-51RHR-V-73A,B Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.Figure Form No. 960690FH LDCN-08-028 RCC Sample Line RHR Steam Lines LC Deactivated Deactivated CAC-BF-3A CAC-BF-3B Amendment 61 December 2011 Isolation Valve Arrangement for Penetrations X-21, X-45 and X-2 920843.22 6.2-40 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 6 on Figure 6.2-36Steam to RCIC Turbine and RHR Heat Exchanger MORCIC-V-64 X-21 TC X-45 Notes:RCIC-V-66 will be "bench tested" once the line is removed for refueling.RHR-V-23 and RCIC-V-13 can be tested once the flanged connection is blanked off as per note 1 on figure 6.2-36 RCIC/RHR Head Spray AO MORCIC-V-13RCIC-V-65 X-2RCIC-V-66 TC MORCIC-V-63 LC MORCIC-V-8To MS Line MORCIC-V-76RCIC-V-742 LC Sample Point TC TC MORHR-V-23 RPV TC Drywell Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-49, X-63, X-26 and X-22 950021.13 6.2-41 Figure Form No. 960690FH LDCN-08-028Draw. No.Rev.MO Note: See Note 4 on Figure. 6.2-36 MS Drain Line MO MO MOMS-V-19MS-V-16 X-22 TCX-49 HPCS Test LineX-63 LPCS Test Line X-26 RHR Loop C Test Line Note: See Note 5 on Figure 6.2-36Valve Disk Removed from RHR-V-46CHPCS-V-12 Gate LPCS-FCV-11 Globe RHR-FCV-64C Globe TC X-49 X-63 X-26WetwellHPCS-RV-14 LPCS-RV-18RHR-RV-25CHPCS-RV-35 LPCS-RV-31RHR-RV-88C RHR Loop C OnlyHPCS-V-23LPCS-V-12RHR-V-21 Columbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 6.2-42 920843.08 Isolation Valve Arrangement for Penetrations X-11A and X-11B Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.Figure Amendment 59 December 2007 Form No. 960690FH LDCN-06-039 RHR Drywell Spray Note: See Note 4 on Figure 6.2-36 MORHR-V-16A,BX-11A,B MORHR-V-17A,B TC Isolation Valve Arrangement for PenetrationsX-65, X-25A and X-25B 920843.09 6.2-43 Figure Form No. 960690FH LDCN-08-028Draw. No.Rev.Note: See Note 2 on Figure 6.2-36RHR Wetwell SprayWetwell RCIC Pump Min. Flow MO Note: See Note 5 on Figure 6.2-36RCIC-V-19 TC X-65 MORHR-V-27A, B X-25A X-25B TC Loop A Only TC Columbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 Isolation Valve Arrangement for Penetration X-100 920843.10 6.2-44 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Wetwell Suppression Pool Cleanup Suction Line MO Note: See Note 4 on Figure 6.2-36FPC-V-154 TC X-100 MOFPC-V-153 Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-18A, X-18B, X-18C, X18D, X-3 and X-67 920843.23 6.2-45 Figure Amendment 59 December 2007 Draw. No.Rev.Note: See Note 3 on Figure 6.2-36 TCCEP-V-2ACEP-V-4AX-67 (Wetwell)

AOMS-V-22A,B,C,D MOMSLC-V-3A,B,C,D Deenergized X-67 Only See 6.2-52 RPV X-3 (Drywell)

Note: See Note 4 on Figure 6.2-36 X-18A,B,C and D AOMS-V-28A,B,C,D MOMSLC-V-2,A,B,C,D Deenergized MOMS-V-67A,B,C,D Primary Containment AO AOCEP-V-1A CEP-V-3A AO AOCEP-V-2B CEP-V-4BCEP-V-1B CEP-V-3B TC Form No. 960690 LDCN-02-032 Columbia Generating Station Final Safety Analysis Report X-3 Drywell Purge ExhaustX-67 Wetwell Purge Exhaust Main Steamlines Isolation Valve Arrangement for Penetrations X-20, X-14, X-23 and X-24 920843.24 6.2-46 MO Note: See Note 1 on Figure 6.2-36 for X-23 And X-24 X-20 X-14 MORHR-V-8 (nc)RWCU-V-4 (no)

TCRHR-V-209 On X-14 there are three block valves in parallel EDRRHR-V-9 (nc)RWCU-V-1 (no)

For X-20 Only AOEDR-V-20 AO X-23Wetwell TC AOFDR-V-4 AO X-24Wetwell FDR-V-1 5 L.O.FDR-V-3EDR-V-19 TC TC Note: See Notes 1 (X-20 Only), and 4 (X-14 Only) on Figure 6.2-36 TC TC TC Drywell Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.Figure Amendment 58 December 2005 Form No. 960690FH LDCN-05-007 EDR-V-1 8 L.O.X-20 RHR Shutdown Cooling SupplyX-14 RWCU Suction X-24 FDR from Primary Containment X-23 EDR from Primary Containment Amendment 57December 2003 LDCN-02-010Isolation Valve Arrangement for Penetrations X-92, X-12A, X-12B, X-12C, X-6 and X-8 920843.25 6.2-47 Figure Form No. 960690Draw. No.Rev.Note: See Note 4 on Figure 6.2-36 DW System X-92X-12A RHR Loop A LPCI to RPV X-12B RHR Loop B LPCI to RPV X-12C RHR Loop C LPCI to RPV X-6 HPCS to RPV X-8 LPCS to RPV RPV MORHR-V-42 (A,B,C)HPCS-V-4LPCS-V-5RHR-V-41 (A,B,C)HPCS-V-5LPCS-V-6 X-12A,B,C X-6 X-8 TC TC Primary Containment "Drywell" TCDW-V-156 LCDW-V-157 LC Note: See Note 1 on Figure 6.2-36 Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-19A, X-19B and X-13 900547.31 6.2-48 Figure Amendment 57December 2003 Form No. 960690Draw. No.Rev.MORHR-V-53A,B Note: See Note 2 on Fig. 6.2-36 TC RHR SHUTDOWN COOLING RETURN X198B Only X-19A,B TC TC TC AO DrywellRHR-V-50A,BRHR-V-123A,B E*SLC-V-4B Note: See Note 2 on Fig. 6.2-36 SLC SYSTEM INJECTION LINE X-13 TC Drywell TCHPCS-V-76 RPVSLC-V-7 E*SLC-V-4A*Explosive Actuated Valve Columbia Generating StationFinal Safety Analysis Report LDCN-02-010 Isolation Valve Arrangement for Penetrations X-33, X-31, X-35, X-32, X-36 and X-34 920843.04 6.2-49 Figure Form No. 960690FH LDCN-08-028Draw. No.Rev.MORCIC-V-31 (nc)HPCS-V-15 (nc)

RHR-V-4A,B,C (no)

LPCS-V-1 (no)Wetwell Note: See Note 5 on Fig. 6.2-36 X-33 X-31 X-35 X-32 X-36 X-34 X-33 RCIC Pump Suction from Suppression Pool

X-31 HPCS Pump Suction from Suppression Pool

X-35 RHR"A" Pump Suction from Suppression Pool

X-32 RHR"B" Pump Suction from Suppression Pool

X-36 RHR"C" Pump Suction from Suppression Pool

X-34 LPCS Pump Suction from Suppression Pool TC Columbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 Isolation Valve Arrangement for Penetrations X-46 and X-101 920843.26 6.2-50 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 4 on Figure 6.2-36 RCC Return Line X-46 Suppression Pool Cleanup Return Line MOFPC-V-149 X-101 TC TC Note: See Note 4 on Figure 6.2-36 MORCC-V-40RCC-V-219RCC-V-220RCC-V-221 MOFPC-V-156 MORCC-V-21 Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-47 and X-48 950021.14 6.2-51 Figure Amendment 61 December 2011 Form No. 960690FH LDCN-08-028Draw. No.Rev.MO Note: See Note 5 on Figure 6.2-36 RHR Combined Return Line to Suppression Pool MO X-47, X48RHR-V-120 FDR System (X-47 Only) 2" Blind FlangeRHR-RV-88A,B MO See Figure 6.2-56 See Figure 6.2-39 Structural ConnectionRHR-RV-25A,BRHR-RV-5 (X-48 Only)RHR-V-121 LC LC LCRHR-V-11A,BRHR-V-24A,B LORHR-V-172A,B X47 OnlyRHR-FCV-64 A,BValve Disk RemoveRHR-V-46A,BRHR-V-18A,B LO Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-66, X-67, X-119, X-64 920843.27 6.2-52 Figure Form No. 960690FH LDCN-08-028Draw. No.Rev.Note: See Note 4 on Figure 6.2-36Reactor Building To Wetwell Vacuum ReliefRCIC Vacuum Pump Discharge MORCIC-V-69 AO X-64 TC TC TC Note: See Note 5 on Figure 6.2-36 AO X-66 X-67 X-119WetwellRCIC-V-28WetwellX-119 Only For X-66 Only See 6.2-37 For X-67 Only See 6.2-45CSP-V-5 CSP-V-6 CSP-V-9CSP-V-7 CSP-V-8CSP-V-10 Columbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 Isolation Valve Arrangement for PenetrationsX-42D, 54Aa, 54Bf, 61F, 62F, 69C, 78D, 78E and 82E, 920843.28 6.2-53 Amendment 56December 2001 Figure Form No. 960690Draw. No.Rev.Note: See Note 7 on Figure 6.2-36X-42D Air Line for RHR-V-50AX-54Aa Spare Air LineX-54Bf Air Line for RHR-V-41BX-61F Air Line for RHR-V-41AX-62F Air Line for RHR-V-41CX-69C Air Line for RHR-V-50BX-78D Air Line for LPCS-V-6X-78E Air Line for HPCS-V-5 N 2/Air Supply for Testing Wetwell to Drywell Vacuum Breakers TC Note: See Note 8 on Figure 6.2-36Wetwell Drywell LC NO NC LC LC X-82E CAS-VX-82ETo PneumaticTester on Check ValvesPI-V-X-216RCIC-V-184PI-V-X-218 PI-V-X-219 PI-V-X-220 PI-V-X-221LPCS-V-67HPCS-V-68PI-V-X-42DRCIC-V-740PI-V-X-54BfPI-V-X-61F PI-V-X-62FPI-V-X-69CLPCS-V-66HPCS-V-65CAS-V-730CAS-V-453 SOTo Pneumatic Testers LC LDCN-00-013 Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-85A, X-29A, X-85C, X-29C, X-72F, and X-73E 920843.29 6.2-54 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 1 on Figure 6.2-36Radiation Monitor Supply Line Division A Radiation Monitor Supply Line Division BRadiation Monitor Return Line Division A Radiation Monitor Return Line Division B TC Note: See Note 1 on Figure 6.2-36 Drywell PI-VX-250 PI-VX-256 SO PI-VX-251 PI-VX-257 SO X-85C X-29C X-85A X-29A PI-VX-253 PI-VX-259 SO PI-EFC-72F PI-EFC-73E X-72F X-73E Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-5 and X-93 920843.30 6.2-55 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 4 on Figure 6.2-36 RCC Supply Line Service Air for Maintenance Note: See Note 1 on Figure 6.2-36 DrywellRCC-V-104 X-5 X-93 MORCC-V-5 MO DrywellSA-V-109 Pipe Cap Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-4 and X-116 920843.31 6.2-56 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.RCIC Turbine Exhaust andTurbine Exhaust Vacuum Breaker Note: See Note 4 on Figure 6.2-36WetwellX-116 X-4RCIC-V-68 MOWetwell MO MO See Fig 6.2-51RCIC-V-40 TC TC Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-73F, X-77Ac, X-77Ad, X-80B 920843.32 6.2-57 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 1 on Figure 6.2-36X-80B Drywell Atmosphere Sample LineX-73F Drywell Atmosphere Sample Line Note: See Note 1 on Figure 6.2-36PSR-V-X73-2PSR-V-X80-2 SO Drywell X-73F X-80BPSR-V-X73-1 PSR-V-X80-1 SOPSR-V-X77A2 PSR-V-X77A4 SO X-77Ac X-77AdPSR-V-X77A1 PSR-V-X77A3 SO X-77Ac Jet Pump #10 Sample Line X-77Ad Jet Pump #20 Sample Line TC TC TC Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-82D, X-82F, X-83A, X-84F, X-88 920843.33 6.2-58 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 4 on Figure 6.2-36X-82F- Suppression Pool Atm. Sample ReturnX-83A- Suppression Pool Atm. Sample LineX-84F- Suppression Pool Atm. Sample Line Note: See Note 4 on Figure 6.2-36Wetwell X-83A X-84F X-82FPSR-V-X82-1 PSR-V-X88-1 SO X-82D X-88PSR-V-X82-2 PSR-V-X88-2 SO X-82D - Sample Return to Suppression Pool X Suppression Pool Sample Line TCPSR-V-X83-2 PSR-V-X84-2 PSR-V-X82-8 SOPSR-V-X83-1 PSR-V-X84-1 PSR-V-X82-7 SO TC (X-88 Only)Wetwell (X-88 Only)

Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-94 and X-95 920843.34 6.2-59 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.X-94 X-95MWR-V-124 MWR-V-125 X Decon Solution Supply Header X Decon Solution Return Header DrywellT.C.Columbia Generating StationFinal Safety Analysis Report Figure Amendment 54 April 2000 Form No. 960690Draw. No.Rev.960222.68 6.2-60 Columbia Generating StationFinal Safety Analysis Report DELETED(SHEETS 1 THROUGH 4)

Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.Figure Amendment 58 December 2005 Form No. 960690FH LDCN-05-002Sensible Energy Transient in the Reactor Vessel and Internal Metals - Original Rated Power 960222.66 6.2-61Time (Seconds)

Metal Sensible Energy (BTUx10 6)200 100 03010 2 10 3 10 4 10 5 10 6 10 7Service Water Temperature = 95 F Minimum ECCS C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDC N-0 3-0 0 3 6.3-1 6.3 EMERGENCY CORE COOLING SYSTEM

This section provides the design bases for the emergency core cooling systems (ECCS), the description of the systems, the postulated E CCS response to a spectrum of accidents, and a performance evaluation. Sub s ection 6.3.1 discusses the des i gn bases. Subsection

6.3.2 describes

the systems. Subse c tion 6.3.3 discusses the system responses and the evaluation of the system performance. Th e ECCS design and postulated re sponse are based on information developed by the original nuclear steam supply system (NSSS) vendor, General Electric. Subsequent reload analyses have been provided by fuel vendors for initial system performance (time from the event to core reflood) and General Electric for the long-term performance.

6.3.1 DESIGN

BASES AN D

SUMMARY

DESCRIPTION

Reload analysis performed by th e fuel vendor in support of th e current cycle of operation is performed in a manner that main tains the validity of the design analysis discussed in this section. The operational limits resulting from this cycle-specific analysis are reported in the cycle-specific Core Operating Limits Report (COLR).

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 (LOCAs) caused by ruptures in primary system piping. The functional requirements are such that the system performance unde r all postulated LOCA conditions satisfies the requirements of 10 CFR 50.46. The ECCS is designed to meet the following requirements:

a. Protection is provided for any primary line break up to and including the double-ended guillotine (DEG) br eak of the largest line,
b. Two independent and diverse cooling methods (flooding and spraying) are provided to cool the core,
c. One high-pressure cooling system is provided which is capa ble of maintaining water level above the top of the core and preventing automatic depressurization system (ADS) actuation for line breaks less than 1 in. nominal diameter,
d. No operator action is required until 10 minutes after an accident, and
e. 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.

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 6.3-2 6.3.1.1.2 Reliabil ity Requirements

The following reliability requirements apply:

a. The ECCS conforms to licensing requirements and desi gn practices of isolation, separation, and single fa ilure considerations.
b. The ECCS network has a built-in redunda ncy so that adequate cooling can be provided, even in the ev ent of specified failures.

The following equipment makes up the ECCS:

1. High-pressure core spray (HPCS),
2. Low-pressure core spray (LPCS),
3. Low-pressure coolant inj ection (LPCI), three loops, and 4. Automatic depressurization system (ADS).
c. The ADS is designed to remain operational following a single active or passive component failure, including power buses, electrical and mechanical parts, cabinets, and wiring.
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 can prevent automatic initiation and successful operation of less than the following combination of ECCS equipment:
1. Three LPCI loops, the LPCS and the ADS (i.e., HPCS failure), or
2. Two LPCI loops, the HPCS and the ADS (i.e., LPCS diesel generator failure), or
3. One LPCI loop, the LPCS, the HPCS and ADS (i.e., LPCI 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 can prevent automatic initiation and successful operation of less than the following combination of ECCS equipment:
1. Two LPCI loops and the ADS, or 2. One LPCI loop, the LPCS and the ADS, or
3. One LPCI loop, the HPCS and the ADS, or
4. The LPCS, the HPCS, and ADS.

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 6.3-3 These are the minimum ECCS combinations which re sult after assuming any single active component failure and assuming that the EC CS line break disables the affected system.

f. Long term (10 minutes after initiation signal) cooling requires the removal of decay heat by means of the standby service water system.

In addition to the break which initiated the loss of coolant event, the system is ab le to sustain one failure, either active or passive, and s till have at least one ECCS pump (LPCI, HPCS, or LPCS) operating with a residual heat removal (RHR) heat exchanger loop with 100% service water flow.

g. Offsite power is the preferred source of power for the ECCS network and every reasonable precaution is made to ensure its high availability. However, onsite emergency power is provided with sufficient diversity and capacity so that all the above requirements can be met if offsite power is not available.
h. The onsite diesel fuel reserve is designed in accordance with IEEE 308-1971 criteria.
i. Diesel-load configur ation is as follows:
l. LPCI loop A (with heat exchange r) and the LPCS connected to the Division 1 diesel generator.
2. LPCI loop B (with heat excha nger) and loop C connected to the Division 2 diesel generator.
3. The HPCS connected to the Division 3 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 do not propagate to and/or affect the performance of the ECCS.
k. Non-ECCS systems interfacing with the ECCS buses are au tomatically shed from and/or isolated from the ECCS buses when a LOCA signal exists and offsite ac power is not available.
l. No more than one storage battery is connected to a dc power bus.
m. The logic required to automatically initia te the ECCS is capab le of being tested during plant operation. Each system of the ECCS including flow rate and sensing network is capable of being test ed during shutdown or during reactor operation. Pump discharge is routed to the suppression pool or condensate

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 6.3-4 storage tank through a test line. The inje ction line isolation valves and isolation check valves are tested in accordance with Section 3.9.6. n. Provisions for testing the ECCS networ k components (elect ronic, mechanical, hydraulic, and pneumatic, as applicable) are installed in such a manner that they are an integral and nonseparable part of the design.

6.3.1.1.3 Emergency Core C ooling System Requirements for Protection from Physical Damage The ECCS piping and components are protected against damage from movement, thermal stresses, the effects of the LOCA, a nd the safe shutdow n earthquake (SSE).

The ECCS is protected against th e effects of pipe whip which might result from piping failures up to and including the LOCA. This protec tion is provided by sepa ration, pipe whip restraints, or energy absorbing ma terials. Any of these three methods is applied to provide protection against damage to ECCS piping and components which otherwise could result in a reduction of ECCS effectiveness to an unacceptable level.

Physical separation outside the drywell is achieved as follows:

a. The ECCS is separated in to three functional groups:
1. HPCS
2. LPCS and LPCI loop A with 100% service water and one RHR heat exchanger
3. LPCI loops B and C with 100% service water and one RHR heat exchanger
b. The equipment in each group is separate d from that in the other two groups. In addition, HPCS and the reactor core isolation cooling (RCIC) (which is not an ECCS) are separated.
c. Separation barriers exist between the functional groups a nd between HPCS and RCIC as required to ensure that e nvironmental disturbances affecting one functional group will not affect the remaining groups.

6.3.1.1.4 Emergency Core Cooling System Environmental Design Basis

The only active components in the HPCS, LPCS, or LPCI system s located in the drywell are the check valves.

These safety-related, injection/isolation check valves are qualified for the C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDCN-03-003 6.3-5 accident environmental requirements specified in Section 3.11 and are installed above the expected flood level in the drywell. The AD S valves are located in the drywell and are qualified to the accident environmen tal conditions specified in Section 3.11.

The balance of the ECCS equipment (e.g., pumps, motors) is qualified for accident environmental requirements specified in Section 3.11.

Note: "Qualification" of safety-related mech anical (SRM) equipment is not part of the Columbia Generating (CGS) Sta tion Environmental Qualifica tion (EQ) 10 CFR 50.49 program but is part of the process that maintains the plant design basis.

6.3.1.2 Summary Descri ptions of Emergency Core Cooling System

The ECCS injection network consists of an HPCS system, an LPCS system, and the LPCI mode of the RHR system. The ADS assists the injection network under certain conditions.

These systems are briefly describe d in this section as an introduc tion to more detailed system descriptions in Section 6.3.2.

6.3.1.2.1 High-Pre ssure Core Spray

The HPCS pumps water through a peripheral ring spray sparge r 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. The HPCS also provides spray cooli ng heat transfer during breaks which uncover the core. The standby liquid control (SLC) system also injects to the reactor pressure vessel (RPV) by means of the HPCS core spray header. An SLC injection will occur with HPCS flow either on or off.

6.3.1.2.2 Low-Pressure Core Spray

The LPCS is an independent loop similar to th e HPCS, the primary diffe rence being the LPCS delivers water over the core at low reactor pressures. The primary purpose of the LPCS is to provide inventory makeup and spray cooling during large br eaks which uncover the core. When assisted by the ADS, LPCS also provides protection for small breaks.

6.3.1.2.3 Low-Pressure Coolant Injection The LPCI is an operating mode of the RHR system. Three pumps deliver water from the suppression pool to the bypass region inside the shroud through th ree separate reactor vessel penetrations to provide inventory makeup following large pipe breaks. When assisted by the ADS, LPCI also provides pr otection for small breaks.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-04-027 6.3-6 6.3.1.2.4 Automatic De pressurization System

The ADS utilizes seven of the reactor safety/relief valves (SRV s) to reduce reactor pressure during small breaks in the event of HPCS failure. When the vessel pressure is reduced to within the capacity of the low pressure systems (LPCS a nd LPCI), the systems provide inventory makeup so that acceptable postaccident temperatures are maintained in the core.

6.3.2 SYSTEM

DESIGN

6.3.2.1 Schematic Piping a nd Instrumentation Diagrams The process and flow diagrams for the ECCS are specified in the various Sections of 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, except ADS wh ich requires low reactor water level and indication that LPCI or LPCS is available. The ECCS is actuated automatically and requires no operator action during the first 10 minutes following the accident.

The preferred source of power for all three ECCS divisions is from regular ac power to the plant. Regular ac power is from the main transformers [TR-N(1) and (2)] during plant operation or from the startup transformer (TR-S) (an offsite power source) when the main

generator is off-line. Should regular ac power be lost, Divi sion 1 (LPCS and LPCI loop A) and Division 2 (LPCI loops B and C) would be transferred to a second offsite power supply and backup transformer (TR-B). Division 3 (HPC S) would be powered from its onsite standby diesel. If the backup transformer were also lost, Divisions 1 and 2 would then be powered from their respective and independe nt onsite standby diesels. A more detailed description of the power supplies for the ECCS is contained in Section 8.3.

6.3.2.2.1 High-Pressure Core Spray System

Process and flow diagrams are shown in Figures 6.3-3 and 6.3-4. The HPCS system consists of a single motor-driven centrifugal pump, a spra y sparger in the reacto r vessel located above the core (separate from the LPCS sparger), and associated sy stem piping, valves, controls, and instrumentation. The system is designed to op erate from regular ac or from a standby diesel generator supply if offsite power is not available. The system is designed to the requirements of ASME Section III.

With the exception of the check valve on the di scharge line, all activ e HPCS equipment is located outside the primary containment. Su ction piping is provided from the condensate storage tanks and the suppression pool. This ar rangement provides HPCS the capability to use high quality water from the conde nsate storage tanks. In the ev ent that the condensate storage

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-07-013 6.3-7 water supply becomes exhausted or is not available, automati c switchover to the suppression pool water source will ensure a closed cooling water supply for continuous operation of the HPCS system. The HPCS pump suction is also automatically transfer red to the suppression pool if the suppression pool water level exceeds a prescribed value. The condensate storage tanks contain a reserve of approximately 135,000 gal of water just for use by HPCS and RCIC.

Remote controls for operating the motor-operated components and diesel generator are provided in the main control ro om. The HPCS controls and in strumentation are described in Section 7.3.1. The system is designed to pump water into the r eactor vessel over a wide range of pressures.

For small breaks that do not result in rapid reactor depressurization, the system maintains reactor water level. For large breaks the HPCS system cools the core by a spray. The HPCS also provides for core cooling in the event of a station blackout. If a LOCA should occur, a low water level signal or a high drywell pressu re signal initiates the HPCS and its support equipment. The system can also be manually placed in operation.

The HPCS injection automatically stops with a high water level in the reactor vessel by signaling the injection valve to close and it auto matically starts again when a low water level signals the injection valve to ope

n. The HPCS system also serv es as a back-up to the RCIC system in the even t the reactor becomes isol ated from the main conde nser during operation and feedwater flow is lost.

The HPCS system head flow characteristic used for LO CA analyses is shown in Figure 6.3-5. 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

  • the system reaches rated core spray flow. The HPCS motor size is based on peak horsepower requirements.

The elevation of the HPCS pump is sufficiently below the water level of both the condensate storage tanks and the suppression pool to provide a flooded pump suction and to meet pump net positive suction head (NPSH) requirements with the containm ent at atmospheric pressure and the suction strainer bed entrained with debr is washed into the we twell following a LOCA. The available NPSH at the pump suction is su fficient to meet th e NPSH required (see Section 6.3.2.2.6). The available NPSH also ensures that no cavitation occurs anywhere in the pump suction line between the wetwell strainers and the pump suction.

A motor-operated valve is provided in the suction line from the suppre ssion 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 HPCS sy stem suction is from the condensate storage

  • psid - differential pressure between the reactor vessel and the suction source.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.3-8 system and to isolate the system from the suppression pool in the event of a leak in the HPCS system.

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 locat ed below the minimum suppression pool water level and is provided so the piping down stream of the valve can be maintained full of water by the discharge line fill system. The flow element is provided to measure system flow rate during LOCA and test conditions and for auto matic control of the minimum low flow bypass gate valv

e. The measured flow is i ndicated in the main control room. The restricting orifice was sized during the system preope rational test to limit system flow to prescribed values.

A low flow bypass line with a motor-operated gate valve connects to th e HPCS discharge line upstream of the check valve on the pump discharge line. Th e line bypasses water to the suppression pool to prevent pump damage from ove rheating when other di scharge line valves are closed. The valve au tomatically closes when flow in the main discharge line is sufficient to provide required pump cooling.

To ensure continuous core cooling, primary containment isolation does not interfere with HPCS operation.

The HPCS system incorporates relief valves to protect the components and piping from inadvertent overpressure. One relief valve with required capacity is located on the discharge side of the pump downstream of the check valve to relie ve thermally-expanded fluid or leakage. A second relief valve is located on the suction side of the pump. The HPCS components and piping are positioned to avoid damage from the phys ical effects of design basis accidents such as pipe whip, missiles, high te mperature, pressure, a nd humidity. The HPCS equipment and support structures are designed in accordance with Seismic Category I criteria.

The system is assumed to be filled with wate r for seismic analysis.

Provisions are included in the HPCS system which will permit the HPCS sy stem to be tested.

These provisions are

a. Active HPCS components are testable during normal plan t operation and/or during shutdown,
b. A full flow test line is provided to route water from and to the condensate storage tanks without entering the RPV,
c. A full flow test line is provided to route water from and to the suppression pool without entering the RPV, C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDC N-0 2-0 1 0, 0 3-003 6.3-9 d. Instrumentation is provided to indicate system performance during normal and test conditions,
e. Check valves and motor-operated valves are capable of operation for test purposes, and
f. System relief valves are removable for bench-testing during plant shutdown.

6.3.2.2.2 Automatic De pressurization System

If the HPCS cannot maintain reac tor water level, the ADS, whic h is independent of any other ECCS, reduces the reactor pressu re so that flow from LPCI and LPCS systems can enter the reactor vessel for core cooling.

The ADS employs seven of the nuclear system pre ssure relief valves to relieve high pressure steam to the suppression pool. The design, loca tion, description, opera tional charact eristics, 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 System

Process and flow diagrams are shown in Figures 6.3

-4 and 6.3-6. The LPCS sys t em consis t s of a single motor-driven centrifugal pump, a spra y sparger in the reacto r vessel above the core (separate from the HPCS sparger), piping and va lves to convey water from the suppression pool to the sparger, and associated controls and instrumentation.

Design pressure and temperature of system components are based on ASME Section III.

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, th e effective core coo ling capability of the LPCS is extended to all break sizes because the ADS can rapidly reduce the reactor vessel pressure to the LPCS operating range. The system head flow characteristic assumed fo r LOCA analyses is shown in Figure 6.3-1.

The LPCS pump and all motor-operated valves can be operated individually in the control room. Operating flow and valve position indication is provided in the control room.

To ensure continuity of core cooling, primary containment isolation signals do not interfere with LPCS operation.

The LPCS discharge line to the reactor is provi ded with two isolation valves. One of these valves is a check valve located inside the drywell as close as practical to the reactor vessel. The LPCS injection flow causes this valve to open during LOCA conditions (i.e., no power is

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDC N-0 2-0 1 0, 0 3-003 6.3-10 required for valve actuation during LOCA).

If the LPCS line should break outside the containment, the check valve in the line inside the drywell w ill 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 containm ent. The valve is cap able of opening against a differential pressure equal to normal reacto r pressure, minus the minimum LPCS system shutoff pressure. A permissive switch prevents the valve ope rator from being energized to open until t h e reactor vessel press u re is l e ss than the value i n Table 6.3-1. This valve is normally closed to back up the inside check valve for containment integrity purposes. A test line is provided between the two valves. The test connection line has two normally closed valves to ensure containment integrity.

The LPCS system components and piping are arranged to avoid damage from the physical

effect of design-basis ac cidents, such as pipe whip, missile s, high temperature, pressure, and humidity.

With the exception of the check valve on the di scharge line, all activ e 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 locat ed below the minimum suppression pool water level and is provided so the piping down stream of the valve can be maintained full of water by the discharge line fill system. The flow element is provided to measure system flow rate during LOCA and test conditions and for auto matic control of the minimum low flow bypass globe valve. The measur ed flow is indicated in the main control room. The restricting orifice was sized during the system preope rational test to limit system flow to prescribed values.

A low flow bypass line with a motor-operated globe valve connects to the LPCS discharge line upstream of the check valve on the pump discharge line. Th e line bypasses water to the suppression pool to prevent pump damage due to overheating when other di scharge line valves are closed or reactor pressure is greater than the LPCS system discharge pressure following system initiation. The valve au tomatically closes when flow in the main discharge line is sufficient to provide required pump cooling.

The LPCS flow passes through a motor-operated pump suction valve that is normally open.

This valve can be closed from the control room to isolate the LPCS system from the suppression pool should a leak deve lop in the system. This valv e is located as close to the

suppression pool penetration as practical. Since th e LPCS takes a suc tion on the suppression pool, a closed loop is established fo r the water escaping from the break.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-07-013 6.3-11 The LPCS pump is located in th e reactor building sufficiently below the water level in the suppression pool to ensure a flooded pump suction and to meet pump NPSH requirements with the containment at atmospheric pressure and postaccident debris entrained on the beds of the suction strainers. A pressure gauge is provided to indicate the suction head. The available NPSH at the pump suction is sufficient to meet the NPSH required (see Section 6.3.2.2.6). The LPCS system incorporates relief valves to prevent the components and piping from inadvertent overpressure conditions. One relie f valve is located on the pump discharge.

A second relief valve is located on the suction side of the pump.

The LPCS system piping and support structures are designed in accordance with Seismic Category I criteria. The system is assumed to be filled with water for seismic analysis.

Provisions are included in the LP CS system which will permit the system to be tested. These provisions are

a. All active LPCS components are testab le during normal plant operation and/or shutdown,
b. A full flow test line is provided to ro ute water from and to the suppression pool without entering the RPV,
c. A suction test line supplying high quality water is provided to test pump discharge into the RPV during normal plant shutdown,
d. Instrumentation is provided to indicate system performance during normal and test operations,
e. Check valves and motor-operated valves are capable of operation for test purposes, and
f. Relief valves are removable for bench-testing during plant shutdown.

6.3.2.2.4 Low-Pressure C oolant Injection System

The LPCI system is an operating mode of the RHR system. The LPCI sy stem is automatically actuated by low water level in the reactor and/

or high pressure in the drywell and, when reactor vessel pressure is low e nough, uses the three RHR motor-driven pumps to draw suction from the suppression pool and inj ect cooling water flow into the reactor core to cool the core by flooding. Each loop has its own suction a nd discharge piping and separate vessel nozzle which connects with the core sh roud to deliver flooding water on top of the core. The system is a high volume core flooding system. The design pressure and temperature of system components is based on ASME Section III.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.3-12 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 size s because the ADS will rapidly reduce the reactor vessel pressure to the LPCI operating range. The head flow characteristic assumed in the LOCA analyses fo r the LPCI system is shown in Figure 6.3-2.

The process and flow diagram for the RHR system is contained in Section 5.4.7. The pumps, piping, controls, and instrumenta tion of the LPCI loops are separated and protected so that no single physi cal event, including missiles, can make all loops inoperable.

To ensure continuity of core cooling, primary containment isolation signals do not interfere with the LPCI mode of operation.

Each LPCI discharge line to the reactor is provided with tw o isolation valves. The valve inside the drywell is a check va lve and the valve outside the drywell is a motor-operated gate valve. No power is required to operate the ch eck valve inside of th e drywell since it opens with LPCI injection flow. If a break were to occur outboard of the check valve, the valve would shut isolating the r eactor from the line break.

The motor-operated isolation valve outside of the drywell is also the LPCI injection valve and it is located as close as practical to the dryw ell wall. It is capab le of opening against a differential pressure equal to normal reactor pressure minus the upstream pressure with the RHR pump running at minimum flow. A permissi ve switch prevents th e valve operator from energizing open until the reactor vess el pressure is as shown in Table 6.3-1.

Figure 5.4-16 process diagram shows the additional flow paths available other than the LPCI mode. 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 system valves to the LPCI lineup. Inlet and outlet va lves from the heat exchangers however receive no automatic signals. The heat exchanger inle t valves are key-locked open and the outlet valves are administratively controlled in the open position. The RHR system continues in the LPCI mode until the operator determines that another mode of operation is needed (such as containment cooling) and takes action to manually initiate that mode. The LPCI will not be diverted to any other mode of operation until adequate core coo ling is ensured. No operator actions are needed during the short term.

A check valve in the pump discharge line is used together with a discharge line fill system to keep the discharge lines full of water, there by, preventing water hamm er on pump start. A flow element in each pump discharge line is used to provide a measure of system flow and to originate automatic signals for control of the pump minimum flow valves. The minimum flow

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-07-013 6.3-13 valve permits a small flow to the suppression pool in the event no discharge valve is open or in the case of a LOCA where vessel pressu re is higher than pump shutoff head.

Using the suppression pool as the source of wate r, the LPCI pump estab lishes 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 system can be obtained from the RHR process diagram in Figures 5.4-16 and 5.4-17.

The LPCI pumps and equipment are described in detail in Section 5.4.7. The RHR heat exchangers are not associated with the emergenc y core cooling 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 accor dance with Seismic Cate gory I criteria. The available NPSH at the pump suction is sufficient to meet the NPSH required (see Section 6.3.2.2.6). The characteristics for the RHR (LPCI) pumps are shown in Figures 5.4-18 , 5.4-19 , and 5.4-20.

The LPCI system incorporates a relief valve on each of the pump discharge lines which protects the components and piping from overpressure conditions.

There is a relief valve on the common suction header from the reactor recirculation piping for loops A and B. In addition, each of the three suction pipes from the suppression pool for loops A, B, and C is provi ded with a relief valve.

The following provisions are incl uded in the LPCI system to permit testing of the system:

a. Active LPCI components are designed to be testable during normal plant operation and/or duri ng plant shutdown,
b. A discharge test line is provided for the three pumps to route suppression pool water back to the suppression pool without entering the RPV,
c. A suction test line, supplying high qua lity water, is provide d to test discharge into the RPV during normal plant shutdown,
d. Instrumentation is provided to indicate system performance during normal and test operations,
e. Check valves and motor-operated valves are capable of operation for test purposes, C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.3-14 f. Lines taking suction from the recirculation system are provided for loops A and B to provide for shutdown cooling and to test pump discharge into the RPV during plant shutdown, and
g. System relief valves are removable for bench-testing during plant shutdown.

6.3.2.2.5 Emergency Core Cooling System Discharge Line Fill System

The ECCS discharge line fill system is designed to mainta in the pump discharge lines in a filled condition to ensure the time between the signal to start the pump and the initiation of flow into the RPV is minimized.

Since the ECCS discharge lines are elevated above the suppression pool, check valves are provided near the pumps to prevent back flow from emptying the lines into the suppression pool. To ensure that any leakage from the discharge lines is re placed and the lines are always kept full, a water leg pump system is provided for each of the three ECCS divisions. The power supply to these pumps is classified as essential when the ma in ECCS pumps are not operating. Indication is provided in the control room as to whether the water leg pumps are operating.

6.3.2.2.6 Emergency Core Coo ling System Suction Strainers

NRC Bulletin 96-03, Potential Plugging of Emergency Core Cooling Suction Strainers by Debris in Boiling Water Reactors, requested that the ECCS suction strainers be evaluated with regard to the potential for plugging during accident conditions.

The ECCS suction strainers were replaced to conform with the requirements of the bulletin.

There are two suction strainer s for each ECCS pump. Each strainer is Quality Class I, Seismic Category I, Cleanliness Class B, and has a service rating of ANSI 150#. Strainer materials and fabrication meet ASME Section III, Class 2 require ments. The "N" stamp is not applied since the strainers cannot be hydrostatica lly tested. The strain er body is stainless steel 304 or 316, or engineer approved equal, suitable for s ubmergence in high quality water during a 40-year lifetime.

The ECCS suction strainers have a cylindrical stacked disk configuration, as shown on Figures 6.3-7 and 6.3-8. The strainers are attached to ANSI 150# RF flanges. The following information identifies the overall dimensions, ra ted flow conditions, and other considerations used in the design of the ECCS strainers.

Strainer sizes were selected ba sed on several criteria. The strainer beds had to be big enough to entrain post-LOCA wetwell debris without exceeding the maximum allowable head losses. The maximum head losses across the strainers were determined based on maintaining sufficient pressure in the pump suction lines to preclude cavitation unde r run-out conditions with the C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.3-15 suppression pool water at 204.5

°F. The strainer sizes were also limited by physi cal constraints in the suppression pool and hydrod ynamic design considerations.

The screen size for the suction strainers on the RHR system is based on the more restrictive criteria set by the pump manufacturer or th e spray nozzle orifice opening. The pump manufacturer imposed a maximum particle size of 0.09375 in., based on the size of the smallest orifice/flow path in th e pump mechanical seal. This is significan tly more restrictive than the requirement imposed by the spray nozzles which have an orifice opening of 0.26563 in. Accordingly, the strainers were specified to prevent the passage of particles 0.09375 in. or greater. The diameter of the holes in the strainer perforated plate is 0.09375 in. Particles smaller than 0.09375 in. (3/32 in.) would normally pass th rough the ECCS strainers.

However, following a LOCA, fibrous debris is postu lated to be in the wetwell. This debris, once deposited on the strainers, would cause particle s finer than 3/32 in. to be entrained on the strainer bed.

Hydrodynamic and pressure loads were developed whic h were applied conc urrently with the load due to process flow through the stra iner. The hydrodynamic pressure loads on the strainer address actual strainer geometries and the drag effects resulting from the strainers, dimensional, and porous properties.

The following information provides details regard ing location, size, and submergence of each ECCS strainer, relative to the minimum suppress ion pool water level of 466 ft 0.75 in. The location of the RHR strainers is also shown in Figure 6.2-32.

ECCS Pump Quantity Centerline Elevation Approximate Azimuth Minimum Submergence (ft) Outer Diameter (in.)

Length (in.) RHR-P-2A 2 447 ft 26° 17.1 47.5 28 RHR-P-2B 2 447 ft 153° 17.1 47.5 28 RHR-P-2C 1 447 ft 7 in.

38° 17.0 36 42 RHR-P-2C 1 447 ft 7 in.

38° 17.0 36 70 LPCS-P-1 1 447 ft 7 in.

58° 17.0 36 36 LPCS-P-1 1 447 ft 7 in.

38° 17.0 36 76 HPCS-P-1 2 438 ft 9 in.

90° 25.8 36 51

During normal operation, corrosi on products accumulate in the suppression pool forming a sediment on the pool surfaces. Following a LOCA, those sediments are assumed to be resuspended in the suppression pool water and entrained on the st rainer beds, together with other debris.

A spectrum of breaks were analy zed to determine the maximum amount of debris which could be in the wetwell following a LOCA. The ECCS strainers have been designed to provide a satisfactory head loss af ter entraining all wetwell debris fo llowing a LOCA. The analysis was

C OLUMBIA G ENERATING S TATION Amendment 62 F INAL S AFETY A NALYSIS R EPORT December 2013 LDCN-12-036 6.3-16 performed using the guidance provided in Reference 6.3-3 and determined the maximum postulated quantities of debris th at would be in the suppressi on pool following a LOCA. The debris types that are assessed in the analysis include the following:

Fiber TempMat Fiber Insulati on, miscellaneous fiber sour ces (i.e., cloth, rope)

RMI Reflective Metal Insulation foils , equipment tags (modeled as RMI)

Sediment Suppression pool sediment, dirt, dust, and conc rete dust

Coatings Qualified epoxy coating within the break zone of influence

Coatings Unqualified (lat ent) paint in drywell

Coatings Zinc unqualifie d coating in wetwell

Labels Adhesive backed labels

Rust Rust flakes from uncoated surfaces in drywell and wetwell

A portion of the strainer surface area was rese rved (presumed unavailable in the analysis) to provide for additional design margin.

The debris that is postulated to reach the suppression pool is a ssumed to be fully entrained on the strainers of ECCS pumps that are available to operate, in pr oportion to their relative flow rates.

Calculations demonstrating the acceptability of the new strainers and the NPSH for all ECCS pumps were performed in accordan ce with Regulatory Guide 1.1.

NPSH = Wetwell air space pressure + static pr essure - friction losses - vapor pressure The NPSH calculations are based on a p eak suppression pool temperature of 204.5 F and bounding flowrates for the time of peak pool temperature. This is the bounding configuration for minimizing available NPSH. The analysis which established the 204.5 F temperature used the following conservative assumptions:

a. The suppression pool is the only heat si nk available to the co ntainment system.

No credit is taken for passi ve structural heat sinks in the drywell, suppression chamber air space, or in the suppression pool;

C OLUMBIA G ENERATING S TATION Amendment 62 F INAL S AFETY A NALYSIS R EPORT December 2013 6.3-17 b. No cooling is assumed for 10 minutes. After 10 minutes, the RHR heat exchangers are assumed to remove energy by recirculating water from the suppression pool through the RHR heat exchangers; and

c. The suppression pool volume is at mi nimum Technical Specifications level (112,197 ft 3), with an initial condition of 90 F. Standby servi ce water, which cools the RHR heat exchanger, is also at 90 F. In addition, the NPSH calculation used the following conservative assumptions:
a. The suppression chamber is assumed to be at 14.7 psia throughout the event,
b. No credit is taken for e xpansion of the suppression pool volume from its initial volume at 90 F to 204.5 F, and c. The NPSH required is the pump manufacturer's NPSH requi red plus two feet.

Vapor pressure at the peak suppr ession pool temperature of 204.5 F is 12.6 psia (30.3 ft). In accordance with Regulatory Guide 1.1, "no increase in containment pressure from that present prior to postulated loss-of-coolan t accidents" is assumed. Th erefore, the wetwell air space pressure is assumed to be 0 psig. Ba sed on a minimum suppression pool level of 466 ft 0.75 in., summary NPSH data for each of the ECCS systems is provided below:

Summary of ECCS Pumps NPSH RHR LPCS HPCS NPSH available at pump suction (ft) 34.2 37.7 40.7 NPSH required (ft) 16 15 26 NPSH margin at pump suction (ft) 18.2 22.7 14.7

The ECCS strainers were designed to ensure that with the strainers entrai ned with debris there was sufficient pressure in the suction line to preclude cavitat ion at the high points of the suction lines.

The strainer designs are based upon the suppr ession pool temperature and pressure of 204.5 F and 14.7 psia, respectively. Th e actual suppression pool atmosphe re is calculated to be higher than 14.7 psia following a LOCA, adding pressu re to the suction lines, and increasing the margin to cavitation at the lines' high points.

With no operator action, the RHR valve alignmen t will result in approximately 40% of its LPCI flow through the RHR heat exchangers, w ith the balance of the flow through the open heat exchanger bypass valve.

For a design basis recirculatio n line break, the partial flow through the heat exchangers will remove heat at about 75% of their design heat rate. At 10 minutes, the operator must close the bypass valve to achieve full cooling.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.3-18 There are sufficient margins in the NPSH and suppression pool analyses to ensure that the lack of operator action for 20 minutes will not challenge the requir ed NPSH for the ECCS pumps at the pump nozzles or allow cavitation anywhere in the suction lines.

All ECCS suction lines in the suppression pool have b een designed with large diameter piping (24 in.) to reduce the inlet veloc ity (maximum 6.67 ft/sec). Th is inlet velocity will support a vortex of no more than 2.5 ft in height. The inle t to each of the ECCS su ction lines is at least 17 ft below the minimum suppressi on pool level. Vortex forma tion at the ECCS pump inlets as a result of lowered suppr ession pool level is thus not considered a problem.

Since it has been conservativel y established that all ECCS suction lines are adequately submerged to preclude formati on of an undesirable vortex, no confirmatory preoperational testing is required.

6.3.2.3 Applicable C odes and Classifications

The applicable codes and classification of the ECCS are specified in Section 3.2. All vital piping systems and components (pumps, valves , etc.) for the ECCS comply with ASME Section III of the Edition and Addenda that were mandatory at the time of their order or a later Edition and Addenda. The piping a nd components of the ECCS whic h form part of the reactor coolant pressure boundary are Safety Class 1.

The remaining piping and components are Safety Class 2, 3, or G, as indicated in Section 3.2. The equipment and piping of the ECCS are designed to the requirements of Seismic Category I. This seismic designation applies to all structures and equipment essential to the core cooling function. The IE EE codes applicable to the controls and power supplies are specified in Section 7.1.

6.3.2.4 Materials Specifications and Compatibility

Materials specifications and compatibility for the ECCS are presented in Section

6.1. Nonmetallic

materials such as l ubricants, seals, pack ings, paints and primers, insulation, as well as metallic materials, etc., are selected as a result of engi neering evaluation for compatibility with other material s in the system and the surroundings pertaining to chemical, radiolytic, mechanical, and nuclear effects. Materials used were revi ewed and evaluated and found to be acceptable with rega rd to radiolytic and pyrolyt ic 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 or the delivery of coolant to the reactor vessel. No individual system of the ECCS is single failure proof, with the exception of the LPCI and ADS. Therefore, it is expected that single failures will disable individual systems of the ECCS. The consequences (remaining available systems) of the most severe singl e failures are shown in Table 6.3-3. The LOCA caused by a pipe

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 6.3-19 break in an ECCS, with the single failure of a DG in another division and the loss of offsite power, will result in the minimum available ECCS.

During a LOCA, for protection against and miti gation of a single passive ECCS failure (pump seal or valve bonnet leak), a Clas s 1E level instrument is mount ed just above floor level in each ECCS pump room and in the RCIC pump room to detect such failures (after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />) during long-term cooling (assuming loss of the othe r non-Class 1E leak detection equipment). The maximum leak rate postulated is 23 gpm, whic h results from the tota l failure of an RHR pump seal. Operator action will isolate the source of the leak af ter detection and before it has any adverse effects on ECCS operation.

The functional testing and calibration of the ECCS is prescribed by the Technical Specifications.

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 acc ounted for in the design are thermal stresses, loadings from a LOCA, and seismic effects.

The ECCS piping and components located inside the ECCS and RCIC/CRD pump rooms are protected from flooding and missiles generated outside the room in which the particular pump

is located by the reinforced-concrete structur e, including doors and wa ll penetrations, which minimize the effects of missiles and flooding. Each pump room contains the majority of the active components of one emergency core cooling or RCIC

/CRD subsystem.

The ECCS is protected against th e effects of pipe whip which might result from piping failures up to and including the design basis LOCA. This protection is provide d by separation, pipe whip restraints, and energy absorbing materials. These three methods are applied to provide protection against damage to pi ping and components of the E CCS which otherwise could result in a reduction of ECCS effectiveness.

The component supports which protect against damage from movement and from seismic events are discussed in Section 5.4.14. The methods used to prov ide assurance that thermal stresses do not cause damage to th e ECCS are described in Section 3.9.3.

6.3.2.7 Provisions for Performance Testing

Periodic system and component testing prov isions for the ECCS are described in Section 6.3.2.2 as part of the individual syst em descriptions and in Section 6.3.1.1.2 as part of the overall system description.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-20 6.3.2.8 Manual Actions

The ECCS is actuated automatically and requires no operator action during the first 10 minutes following an accident. During the long-term cooling period (after 10 minutes), the operator will initiate the RHR system heat exchangers in th e suppression pool cooling mode.

6.3.3 EMERGENCY

CORE COOLING SYSTEM PERFORMANCE EVALUATION

The ECCS performance is eval uated using analytical met hods in compliance with the requirements of 10 CFR 50 Appendix K to show conformance to the acceptance criteria of 10 CFR 50.46. The methods used analyze the full LOCA break spectrum, including small, intermediate, and large size breaks. A spectru m of breaks and single failures is run using a consistent set of initial conditions to determine the re sultant peak clad te mperature (PCT). The PCT is calculated for the potentially limiting ev ents and the design basis break is identified based on that parameter. The break spectrum analysis results confirm that considerable margin exists to the acceptanc e criteria of 10 CFR 50.46. The break spectrum analysis addresses two loop and single loop ope ration. The following Chapter 15 accidents require ECCS operation:

a. Steam system piping break -

outside containment, Section 15.6.4 , b. Loss-of-coolant accidents -

inside containment, Section 15.6.5 , and c. Feedwater line break - out side containment, Section 15.6.6.

The baseline analyses to verify the adequacy of ECCS design were performed by the NSSS vendor for the initial core, a GE 8 x 8 fueled core. The adequacy of the ECCS design was verified subsequently for Single Loop Operation (SLO), Extended Load Line Limit Analysis (ELLLA), reactor power uprate, changes in fuel design, and adjustable speed drive reactor recirculation pumps.

The NSSS vendor analysis established the large break in the reactor recirculation suction line, with failure of the HPCS diesel generator as the limiting (design basis) event. The NSSS vendor analyses are desc ribed in References 6.3-1 , 6.3-2 , 6.3-4 and 6.3-7.

The AREVA NP break spectrum analysis for the ATRIUM-10 fuel identified the limiting break as a 100% double-ended guillotine (DEG) break in the reactor recirculation coolant (RRC) pump suction line with the coincident failure of a LPCI diesel generator (Reference 6.3-14). The break spectrum analyses were performed at a point on the power/flow map to support the plant rated thermal power operation with increased core flow.

The applicable limiting break is then used in the ECCS heatup analyses to determine the maximum average planar linear heat generation rate (MAPLHGR) limits fo r the specific fuel type.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-21 The GE14 analysis establishe s the small break of 0.07 ft 2 in the recirculation suction line with top peaked axial power shape and failure of th e HPCS diesel generator as the limiting break event. The GE14 analysis is described in Reference 6.3-17.

A summary description of the re load design basis LOCA analysis methods is provided in this section. For a complete description of the design basis LOCA event see References 6.3-13 , 6.3-14 , and 6.3-17.

6.3.3.1 Emergency Core Cooling System Bases for Technical Specifications

The MAPLHGRs calculated in this performance evaluation provide a basis to ensure conformance with the acceptance criteria of 10 CFR 50.46.

For ATRIUM-10 and GE14, the MAPLHGR limits are determined from ECCS limits (PCT) only, because the thermal-mechanical limits are incorporated into the LHGR limits. The MAPLHGR limits are provided in the COLR. Testing requirements for ECCS are discussed in Section

6.3.4. Limits

on minimum suppression pool water le vel are discussed in Section 6.2.

6.3.3.2 Acceptance Criteria for Emergenc y Core Cooling System Performance

The applicable acceptance criter ia, extracted from 10 CFR 50.46, are listed and a discussion of conformance is provided. The reload fuel vendors ECCS licensing methodologies (References 6.3-9 , 6.3-10 , 6.3-11 , and 6.3-12) require demonstration of compliance with the first three criteria. Descriptions of the met hods used to demonstrate compliance are shown in Reference 6.3-13.

Criterion 1, Peak Cladding Temperature "The calculated maximum fuel element cladding temperature shall not exceed 2200° F."

Criterion 2, Maximum Cladding Oxidation "The calculated total local oxidation of th e cladding shall nowhere exceed 0.17 times the total cladding thickn ess before oxidation."

Criterion 3, Maximum Hydrogen Generation "The calculated total amount of hydrogen generated from th e chemical reaction of the cladding with water or steam shall not ex ceed 0.01 times the hypothetical amount that would be generated if all the metal in the cladding cy linder surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react."

  • Compliance with Criteria 1, 2, and 3 is summarized in Table 6.3-5 and Figure 6.3-9.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-029 6.3-22 Criterion 4, Cool able Geometry "Calculated changes in core geometry shall be such that th e core remains amenable to cooling."

As described in Reference 6.3-13 , Section 3.2 conformance to Criterion 4 is demonstrated by conforman ce to Criteria 1 and 2.

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 valu e and decay heat shall be removed for the extended period of time re quired by the long-lived radioactivity remaining in the core."

Compliance with this criterion was demonstrated during the original and uprate review of the plant ECCS design (Reference 6.3-1 and 6.3-7). Briefly summarized, the core remains covered to at least the jet pump suction elevation and spray cooling cools the uncovered region.

As discussed in Reference 6.3-14 , Section 8.0, since the ECCS design and performance do not change with fuel reloads, compliance is maintained in subsequent reload cycles.

The ECCS LOCA licensing methodologies for GE14 and the co mpliance with the acceptance criteria as described above ar e documented in References 6.3-18 through 6.3-23. Compliance with Criteria 1, 2, 3, 4 and 5 for GE14 is summarized in Table 6.3-5 and Figure 6.3-9.

6.3.3.3 Single Failure Considerations

The consequences of potential ope rator errors and single failures and potential for submergence of valve motors in the ECCS are discussed in Section 6.3.2. The following bounding single failures are described in Table 6.3-3

a. Low-pressure coolant injection emer gency diesel generator, which powers two LPCI pumps,
b. Low-pressure core spray emergency di esel generator, which powers one LPCI pump and one LPCS pump, and
c. High-pressure core spray.

The systems that remain operational after these failures are shown in Table 6.3-3. For large breaks, failure of one of the di esel generators is, in genera l, the more severe failure.

Substantial amounts of initial vess el inventory are lost through the break during the blowdown.

With fewer systems available, there is less E CCS flow available for reflooding the core and the C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-23 core will reflood later. The la ter reflooding results in higher peak cladding temperatures. For small breaks LOCAs, a HPCS failure is the worst single failure.

As shown in Table 6.3-3, at least one core spray system remains operational, if the break is not in the ECCS piping. If the break occurred in the HPCS or LPCS and the single failure were the other spray system, no core spray system would be available to provide long term cooling. Because the remaining core cooling systems would be able to maintain the water level above the top of the fuel, ad equate core cooli ng is provided without a spray system.

The SAFER/GESTR-LOCA methodologies by GE Hitachi Nuclear Energy consider the single failures for recirculation sucti on line break as described in Table 6.3-3a. The worst single failure for both large and small recirculation line breaks is HPCS failure, in which ADS, LPCS and 3 LPCIs remain operational.

Table 6.3-3a also shows the limiti ng single failures and remaining systems for non-recirculation line breaks.

6.3.3.4 System Performa nce During the Accident

In general, the system response to an accident is as follows:

a. Receiving an initiation signal,
b. A small lag time (to open all valves and have pumps to rated speed), and c. ECCS flow entering the vessel.

Key ECCS initiation and operating parameters used in the LOCA analyses are provided in Table 6.3-2. The representative sequence of events is presented in Table 6.3-4. System flow curves are provided in Figures 6.3-1 and 6.3-2.

Operator action is not required during the s hort-term cooling period following the LOCA.

During the long-term cooling period (after 10 minutes), the operator may take actions to:

a. Use ECCS for vessel level control,
b. Use ADS or SRVs for vessel pressure control, or
c. Place systems into operation, such as containm ent cooling, standby liquid control, or drywell spray.

Key operating parameters, GE14 fuel parameters and ECCS initiation parameters used in the GE14 LOCA analysis are provided in Tables 6.3-2a , 6.3-2b and 6.3-2c, respectively. The representative sequences of events are presented in Tables 6.3-4a and 6.3-4b.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-24 6.3.3.5 Use of Dual Function Componen ts for Emergency Core Cooling System

With the exception of the LPCI system, the systems of the ECCS are designed only to cool the reactor core 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 that have emergency core cooling f unctions, or vice versa. Because the ADS initiating signal or the overpressure signal opens the SRVs there is no conflict between the two SRV functions.

The LPCI subsystem uses the RHR pumps and some of the RHR valves and piping. When reactor water level is low or a high drywell pressure exists, the LPCI subsystem has priority through the valve control logi c over the other RHR subsystems for containment cooling or shutdown cooling. Immediately following a LO CA, the RHR system is aligned to the LPCI mode.

The primary storage facility for ECCS water is the suppression pool which is not shared with any other systems except as a secondary source for RCIC. The RCIC system, although not an ECCS, may supply water to the reactor during LOCA conditions while reactor pressure is above the minimum credited pressure. Since any leakage from the core and safety/relief discharge drains back to the suppression pool, sufficient quantity of water is available for core cooling (see Table 6.2-4

).

The condensate storage tanks comprise the normal water source for HPCS and RCIC. A minimum of 135,000 ga l is required exclusively for RP V makeup. The HPCS and RCIC systems will automatic ally switch suction to the suppression pool when the minimum condensate storage tank supply is exhausted. The HPCS system will also automatically switch suction to the suppression pool when suppressi on pool level reaches a predetermined high level limit.

6.3.3.6 Emergency Core Cooling System Analyses for Loss-of-Coolant Accident

A LOCA may occur over a wide spectrum of break locations and sizes.

Responses to the break vary significantly over the break spectrum. The largest possible break is a DEG; however, this is not necessarily the most severe challenge to the ECCS. Because of these complexities, an analysis coveri ng the full range of break sizes a nd locations is required. The LOCA analysis also assumes a coincident loss of power and an additional single failure. See References 6.3-7 and 6.3-14 for more detail.

Regardless of the initiating break characteristics, the event response is separated into three phases; blow down, refill and reflood. The relative dura tion of each phase is dependant on break size and location.

During the blow down phase of the LOCA, there is a net loss of coolant i nventory, an increase in fuel cladding temperature due to core flow de gradation and, for the la rger breaks, the core

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 6.3-25 becomes fully or partially uncovered. There is a rapid decrease in pressure during the blow down phase. During the early phase of the depressurization, the exiting coolant provides core cooling. The HPCS and LPCS systems also provide some heat removal. The blow down phase is defined to end when LPCS reaches rated flow. When the LPCS diesel generator is the single failure, the blow down phase end is defined as when LPCS , if operational, would have reached rated flow.

During single loop operation (SLO) the break may o ccur in either loop.

The results of a break in the inactive loop would be similar to those from a break in two-loop operation. The break in the active loop during SLO resu lts in a more rapid loss of co re flow and earlier degraded core conditions.

In the LOCA refill phase, the ECCS is functioning and there is a net increase of coolant inventory. During this phase the core sprays provide co re cooling and, along with LPCI, supply liquid to refill the lower portion of the reactor vessel. In general, the core heat transfer to the coolant is less than the fuel decay heat rate and the fu el cladding temperature continues to increase during the refill phase.

In the reflood phase, the coolant inventory has increased to the point wh ere the mixture level reenters the core region. During the core reflood phase, cooling is provided above the mixture level by entrained reflood liquid and below the mixture level by pool boiling. Sufficient

coolant eventually reaches the core hot node and the fuel cladding temperature decreases, terminating the event.

6.3.3.6.1 Loss-of-Coolant Accident Description

Immediately after the postulated double-ended recircula tion suction 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 loses suction and almost immediately ceases to pump. The pump in the intact loop coasts down relatively slowly. This pump coast down govern s the core flow response for the next several seconds. When the jet pump suc tions uncover, calculated core flow decreases to near zero. When the recirculation pump suction nozzle uncovers, th e 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.

Heat transfer rates on the fuel cladding during the early stages of the blowdown are governed primarily by the core flow response. Nucleate boiling continues in the high power plane until shortly after the core flow loss that results from jet pump uncovery. Film boiling heat transfer C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-26 rates then apply, with increasi ng heat transfer resulting from the core flow increase during the lower plenum flashing period. Heat transfer then slowly decreases until the high power axial plane uncovers. At that time, convective heat transfer is assumed to cease.

Water level inside the shroud rema ins high during the early states of the blowdown because of flashing of the water in the core. After a short time, the level inside the shroud has decreased to uncover the core. Several sec onds later, the ECCS is actuated. As a result the vessel water level begins to increase. Some time later the lower plenum is fille d and the core is then rapidly recovered.

The cladding temperature at the high power plane decreases initia lly because nucleate boiling is maintained, the heat input decreases, and the sink temper ature decreases. A rapid, short duration cladding heatup follows the time of bo iling transition when film boiling occurs and the cladding temperature approaches that of th e fuel. The subsequent heatup is slower, being governed by decay heat and core spray heat transfer. Finally the heatup is terminated when the core is recovered by the accumulation of ECCS water.

6.3.3.6.2 Loss-of-Coolant Accident Analysis Procedures and Input Variables

The GE Hitachi Nuclear Energy ECCS-LOC A licensing evaluation methodologies are described in References 6.3-18 through 6.3-23. The GE14 analysis is documented in Reference 6.3-17, consistent with References 6.3-1 and 6.3-2. The AREVA NP LOCA-ECCS evaluation model is identified as EXEM BWR-2000 LOCA analys is methodology. The EXEM BWR-2000 is documente d in References 6.3-9 , 6.3-10 , 6.3-11 , and 6.3-12. These vendor methodologies cover the time from the event until the reactor has been reflooded. The NSSS vendor, GE, performed the long term ECCS evaluation, as desc ribed in Reference 6.3-7. The evaluation documents that th e ECCS satisfy the requireme nts described in Section 6.3.3.2. As documented in References 6.3-1 and 6.3-14 , the reactor power uprate and the new fuel did not impact the conclusions reached in Reference 6.3-7.

6.3.3.6.2.1 LOCA Analysis Metho dology, GE Hitachi Nuclear Energy

Several computer models are us ed in the LOCA analysis to determine the LOCA response.

These models are LAMB, SCAT/TASC, GESTR-LOCA, and SAFER (References 6.3-7 , 6.3-18 through 6.3-23). Together, these models evaluate the short-term and long-term reactor vessel blowdown response to a pipe rupture, the subsequent core flooding by ECCS, and the final rod heatup.

The LAMB model 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 (primarily core flow as a function of time) is used in the SCAT model for calculating blowdown heat transfer and fuel dryout time.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-27 The SCAT/TASC model completes the transient short-term thermal-hydraulic calculation for large recirculation line breaks.

Developed for GE11 and later fuels with partial-length rods, an improved SCAT model (designated "TASC") is used to predict the time and location of boiling transition and dryout. The time and location of boiling transition is predicted during the period of recirculation pump coastdown. When the core inlet flow is low, TASC 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.

The GESTR-LOCA model provides the parameters to initialize the fuel st ored energy and fuel rod fission gas inventory at the onset of a postulated LOCA for input to SAFER. GESTR-LOCA also establishes the tran sient pellet-cladding gap conduct ance for input to both SAFER and SCAT/TASC.

The SAFER model 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 pe rformance, 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 heat transfer coefficients (w hich determine the severity of the temperature change) and the resulting PCT as functions of time. Fo r GE11 and later fuel analysis with the SAFER code, the part length fuel rods are treated as full-length r ods, which conservatively overestimate the hot bundle power.

6.3.3.6.2.2 LOCA Analysis Methodology, AREVA NP

The AREVA NP methodology employs three major computer codes to eval uate the system and fuel response during the LOCA. The RELAX code is used to calculate the system and hot channel response during the blow down, refill, and reflood phas es of the LO CA. The HUXY code is used to perform heat up calculations for the LOCA, and to calculate PCT and local clad oxidation at the high power axial plane. The RODEX2 code is used to determine fuel parameters, such as stored energy, fo r input into the other LOCA codes.

The analysis starts with the specification of fuel parameters using RODEX2 to determine the initial store energy for bo th the blow down analysis and the heat up analysis. This is accomplished by ensuring that the initial stored energy in RELAX and HUXY is the same or higher than that calculated by RODEX2 fo r the power, exposure, and fuel design.

The RELAX code is used to cal culate the system th ermal-hydraulic response during the blow down phase of the LOCA. Following the blow down calculation, another RELAX analysis is performed to analyze the maximum power assembly (hot channel) of the core.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-28 The RELAX code is also used to compute the system and hot channel hydraulic response during the refill and re flood phase of the LOCA.

The ATRIUM-10 fuel rod models are developed using RODEX2.

Data from the RELAX and RODEX2 analyses are used to create a detailed model of the highest power plane of the hot channel with the HUXY code.

6.3.3.6.2.3 LOCA Anal ysis Input Variables The significant input variables used by the LOCA codes are listed in Tables 6.3-1 and 6.3-2. The plant operating parameters and GE14 fuel parameters used for the GE14 LOCA analysis are summarized in Tables 6.3-2a and 6.3-2b, respectively. The limiting calculation for CGS has been performed for 3716 MW t (106.6% power) a nd 115 Mlb/hr (106% core flow) to support operation within the power/flow map. The 106.6% power represents 102% of the power that produces 105% of the rated steam flow. The 106% core flow represents the maximum increased core flow. The performance of the ECCS analysis at the maximum core flow results in the highest radial peaking factor given that the ca lculations are in itialized at the same MAPLHGR and minimum critical power ratio (MCPR) limits. Therefore, this analysis envelopes lower flow conditions at rated core power because the calculations would be initialized with a lower radial peaking factor while maintaining the same initial MAPLHGR and MCPR values.

For SLO, the LOCA behavior is modeled by assuming reactor power at 106.6% and by closing a valve that isolates the intact (ina ctive) loop almost imme diately after the LOCA initiation time. Since the power level is much greater than the maximum allowed in SLO, the LOCA analysis predicts a higher core steam generation rate and a longer period of core uncovery than would be calculated if the reduced SLO power were modeled.

6.3.3.7 Break Spectrum Calculations

Break spectrum analyses have been performed to establish the limiting break for the CGS boiling water reactor (BWR) 5 reactor system.

Previous analyses by GE, the NSSS vendor have shown that a large pipe break in the recirculation line on the suction side of the recirculation pump is the most limiting break for a BWR 5. The GE analysis includes breaks in both recirculation and non-recirculation piping.

Figure 6.3-9 shows the original plant break spectrum analysis for the GE fuel. For the GE14 analysis, the break spectrum is determined and documented in Reference 6.3-17 , consistent with original plant break spectrum analysis in Reference 6.3-1.

Two break types (geometry) are considered for the recirculation pipe break; the DEG break and the split break. For the DEG break, the pipe is completely severed, resulting in two independent flow paths to the containment. The DEG break is modeled by setting the break area equal to the full pipe cross-sectional area and varying the discharge coefficient.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-29 The split break is a longitudinal opening or hole th at results in a single br eak flow path to the containment. Appendix K of 10 CFR 50 defines th e cross-sectional area of the piping as the maximum split break area required for analysis.

6.3.3.7.1 Break Spectrum Calcula tion, GE Hitachi Nuclear Energy

A sufficient number of breaks fo r recirculation suction line ar e analyzed for GE14 with the potentially limiting single failures using nominal assumptions. This ensures that the limiting combination of break size, locati on, axial power shape and single failure has been identified.

The limiting large break for nominal assumptions is the 100% DBA with mid-peaked axial power shape and HPCS DG failure. The overall limiting LOCA is the small recirculation suction line break of 0.08 ft 2 for nominal assumptions with t op peaked axial power shape and HPCS DG failure.

Using the Appendix K input assumptions, analyses of large breaks for GE14 fuel type, are also performed with the limiting singl e failure. The 100%, 80%, and 60% DBA cases also satisfy the Appendix K requirement for using the Moo dy Slip Flow Model with three discharge coefficients of 1.0, 0.

8, and 0.6, respectively. The limit ing Appendix K case for large break is the 100% DBA with mid-peaked axial power shape and HPCS DG failure. The overall limiting LOCA is the small recircul ation suction line break of 0.07 ft 2 for Appendix K assumptions with top peaked axial power shape and HPCS DG failure.

The GE14 analysis also consid ers the non-recirculation line br eaks (CS line, LPCI line and etc.) as well as alternate operating modes (ELLLA, ICF, FFWTR and SLO) Reference 6.3-17 documents all the analysis results.

6.3.3.7.2 Break Spectrum Calculation, AREVA NP

The AREVA NP break spectrum anal ysis considers a full range of break sizes, break locations, break geometry, ECCS system single failures, axial power shapes, and initial operating conditions. Breaks in the recirculation pump su ction and discharge lines were analyzed as potentially limiting break loca tions. The DEG break was m odeled by setting the break area equal to the full pipe cr oss-sectional area and varying the di scharge coefficient between 1.0 and 0.4. The range in the discharge coefficient was used to cover uncertainty in the actual geometry at the break. The split break areas ranged from full pipe area to 0.04 ft

2. Non-recirculation line breaks are not limiting LOCAs (Reference 6.3-14). The break spectrum calculations were performed with an assumed failure of one ECCS.

Table 6.3-3 lists the assumed single failures and available ECCS for the single failure.

The hot channel is modeled at the highest exposure dependent MAPLHGR and at a conservative MCPR limit for the break spectrum analysis. Reactor operation with a recirculation loop drive flow mismatch of up to 5% is supported in the break spectrum calculations.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-30 The limiting break configuration and size were determined to be a 1.0 DEG recirculation suction line break along with failure of the LPCI diesel generator.

6.3.3.8 Loss-of-Coolant Acci dent Analysis Conclusions

The ECCS will perform the required design f unctions and comply with 10 CFR 50.46 acceptance criteria.

6.3.3.8.1 Loss-of-Coolant Acci dent Analysis Conclusions, GE Hitachi Nuclear Energy The GE14 limiting large break for two loop operati on is the recirculation suction line break of DBA with HPCS diesel generato r failure at 104.1% rated power (3629 MWt)/100%

rated flow conditions with a mid peaked axial power shape (Reference 6.3-17). The overall GE14 limiting LOCAs are the small recirculation suction line breaks of 0.07 ft 2 and 0.08 ft 2 for Appendix K and nominal assumptions, respectively, with high pressure core spray diesel generator failure at 104.1% rated po wer (3629 MWt)/100% rated flow conditions and a top peaked axial power shape (Reference 6.3-17). The SLO case is performed at the maximum attainable power and flow on the ELLLA rod line. The case conservatively assumes the simultaneous dryout of all axial fuel nodes almost immediately following the initiation of the event. A SLO multiplier of 1.0 on MAPLHGR is applied (Reference 6.3-17).

6.3.3.8.2 Loss-of-Coolant Accident Analysis Conclusions, AREVA NP

The limiting LOCA for AREVA NP ATRIUM-10 fuel is a 100% DEG break of the recirculation pump suction line with a coincident failure of the LPCI dies el generator, for both two loop and single loop recircula tion pump operation. The limit ing axial power shape in the core is peaked at the location 80% of the activ e fuel length above the bot tom of the active fuel (top-peaked). The initial operating state modeled is 106.6% rated thermal power and 106% of rated core flow. Using the high power and flow conditions for the SLO analysis supports the entire range of SLO initial power/flow conditio

n. The exposure dependent MAPLHGR limits for ATRIUM-10 fuel are documented in Reference 6.3-13. A multiplier is applied to the normal (two loop) operation MAPLHG R limit to obtain the SLO MAPLHGR (References 6.3-13 and 6.3-14).

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 6.3-31 6.3.4 TESTS AND INSPECTIONS

6.3.4.1 Emergency Core Cooling System Performance Tests

The systems of the ECCS were tested for their operational ECCS function during the preoperational and/or startup test program.

Each component was test ed for power source, range, direction of rotation, set point, limit switch setting, torque switch setting, etc. Each pump was tested for flow capacity for comparison with vendor data (this test was also used to verify flow measuring capability

.) The flow tests involved th e same suction and discharge source; i.e., suppression pool or condensate storage tank.

All logic elements were 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.

During preoperational tests each system was tested for respons e time and flow capacity while taking suction from its normal source and delivering flow into the reactor vessel.

See Section 14.2 for a thorough discussion of preoperational testing for these systems.

Pump and valve periodic test s are discussed in Section 3.9.6.

6.3.4.2 Reliability Tests and Inspections

Active components of the HPCS, ADS, LPCS, and LPCI systems are designed so that they may be tested during normal plan t operation. Full flow test ca pability is provide d by a testing path back to the suction source. The full flow test is used to verify the capacity of each ECCS pump loop while the plant remain s undisturbed in the power gene ration mode. In addition, each individual valve may be tested in accordance with Inservice Testing Program requirements. Input jacks are provided such that each ECCS loop can be tested for response time.

Testing of the initiating instrumentation and co ntrols portion of the ECCS is discussed in Section 7.3.1. The emergency power system, which suppl ies electrical power to the ECCS in the event that offsite power is unavailabl e, is tested as described in Section 8.3.1. The frequency of testing is prescribed by the Technical Specifications. Visual inspections of ECCS components located outside the drywell can be made at any time dur ing power operation.

Components inside the drywell can be visually inspected only during peri ods of access to the drywell. When the reactor vesse l is open, the spargers and other internals can be inspected.

6.3.4.2.1 High-Pressure Core Spray Testing

The HPCS can be tested at fu ll flow with condensate storag e tank water at any time during plant operation, except when the r eactor vessel water level is low or when the condensate level in the condensate storage tanks is below the reserve level (135,000 gal) or when the valves

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 6.3-32 from the suppression pool to the pump are open.

If an initiation signal occurs while the HPCS is being tested, the system automatically returns to the operating mode. The two motor-operated valves in the test line to the condensat e storage system are interlocked closed when the suction valve from the suppression pool is open.

A design flow functional test of the HPCS over the operating pressure and flow range is performed by pumping water from the condensate storage tanks and back through the full flow test return line to the condensate storage tanks.

The suction valve from the suppression pool a nd the discharge valve to the reactor remain closed. These two valves are tested separately to ensure operability.

6.3.4.2.2 Automatic Depressurization System Testing

The ADS valves are fully tested during the time when the reactor is being depressurized prior to or repressurized following a refueling outage. This testin g includes simulated automatic actuation of the system throughout its emergenc y operating sequence, but excludes actual valve actuation. 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 Low-Pressure Core Spray Testing

The LPCS pump and valves are te sted periodically. With the injection valve closed and the return line open to the suppression pool, full flow pump capability is demonstrated. The injection valve and the check valve are tested in a manner similar to that of the LPCI valves.

6.3.4.2.4 Low-Pressure C oolant Injection Testing

Each LPCI loop can be tested during reactor operation. The te st conditions are tabulated in Chapter 5. During plant operation, this test does not inject cold water into the reactor because the injection line check valve is held closed by vessel pressure, which is higher than the pump pressure. The injection line portion is tested with reactor water when the reactor is shut down and when a closed system loop is created.

This prevents unnecessary thermal stresses.

To test an LPCI pump at rate d flow, the test line valve to the suppression pool is opened and the pump suction valve from the suppression pool is opened (this valve is normally open). For loops A and B, the valve to the suppression chambe r spray ring header is also opened. Correct operation is determined by observing th e instruments in the control room.

If an initiation signal occurs dur ing the tests, the LPCI system automatica lly returns to the operating mode. The valves in the test lines are closed automatic ally to ensure that the LPCI pump discharge is correctly routed to the reactor vessel.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-33

6.3.5 INSTRUMENTATION

REQUIREMENTS

Design details including redundancy and logic of the ECCS instrumentation are discussed in Section 7.3.1.

Instrumentation required for automatic and manual initiation of the HPCS, LPCS, LPCI, and

ADS is discussed in Section 7.3.1 and is designed to meet th e requirements of IEEE 279 and other applicable 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 Table 6.3-1 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 RHR 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 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 0 psid

  • to 1160 psid.
  • 6.

3.6 REFERENCES

6.3-1 GE Nuclear Energy, "Washington Public Power Supply System Nuclear Project 2, SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis,"

NEDC-32115P, Class III (Proprieta ry), DRF A00-05078, Revision 2.

6.3-2 GE Nuclear Energy, "Washington Public Power Supply System Nuclear Project 2, SRV Setpoint Tolerance and Out-of-Service Analysis,"

GE-NE-187-24-0992, Revision 2.

6.3-3 GE BWROG Committee on ECCS Suc tion Strainers, "Utility Resolution Guidance for ECCS Suction Strainer Bl ockage," NEDO-326 86, Revision 0.

6.3-4 GE Nuclear Energy, Washington Public Power Supply System Nuclear Project 2, "WNP-2 Power Uprate Transient Analysis Task Report,"

GE-NE-208-08-0393, DRF A 00-05078 and -05371.

6.3-5 Deleted.

6.3-6 Deleted.

  • psid - differential pressure be tween RPV and pump suction source.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-34 6.3-7 General Electric Company, "General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10CFR50 Appendix K," NEDO-20566A, September 1986.

6.3-8 Framatome ANP, "Mechanical and Thermal-Hydraulic Design Report for Columbia Generating Station ATRIUM-10 Fuel Assemblies," EMF-2865(P), Revision 1, April 2003.

6.3-9 Framatome ANP, "EXEM BW R-2000 ECCS Evaluation Model," EMF-2361(P)(A), Revi sion 0, May 2001.

6.3-10 Exxon Nuclear Company, "HUXY: A Generalized Multirod Heatup Code with 10 CFR 50 Appendix K Heatup Option Users Manual," XN-CC-33(P)(A), Revision 1, November 1975.

6.3-11 Exxon Nuclear Company, "Exxon Nuclear Compa ny ECCS Cladding Swelling and Rupture Model," XN-NF-82-07(P

)(A), Revision 1, November 1982.

6.3-12 Exxon Nuclear Compa ny, "RODEX2 Fuel Rod Ther mal-Mechanical Response Evaluation Model," XN-NF-81-58(P)(A), Revision 2 a nd Supplements 1 and 2, March 1984.

6.3-13 Framatome ANP, "Columbia Ge nerating Station LOCA-ECCS Analysis MAPLHGR Limit for ATRUIM-10 Fu el," EMF-3172(P), Revision 1, June 2005.

6.3-14 Framatome ANP, "Columbia Ge nerating Station LOCA Break Spectrum Analysis for ATRIUM-10 Fuel," EM F-3171(P), Revision 1, June 2005.

6.3-15 "High Pressure Core Spray System (HPCS)," Design Basis Document, Section 308.

6.3-16 "Low Pressure Core Spray System (LPCS)," Design Basis Document, Section 316.

6.3-17 "Columbia Generati ng Station GE14 ECCS-LOCA Evaluation," GE Hitachi Nuclear Energy, 0000-0090-6853-R0, February 2009.

6.3-18 "The GESTR -LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 1, GESTR-LOCA - A Model for the Prediction of Fuel Rod Thermal Performance," NEDE-237 85-1-PA, Revision 1, October 1984.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-35 6.3-19 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol.

2, SAFER - Long Term Inventory Model for BWR Loss-of-Coolant Analysis," NEDE-2378 5-1-PA, Revision 1, October 1984.

6.3-20 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 3, SAFER/GESTR Application Methodology,"

NEDE-23785-1-PA, Revision 1, October 1984.

6.3-21 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 3. Supplemen t 1, Additional Information for Upper Bound PCT Calculation," EDE-23785P-A, Revision 1, March 2002.

6.3-22 "TASC-03A A Computer Program for Transient Analysis of a Single Channel,"

NEDC-32084P-A, Revisi on 2, July 2002.

6.3-23 "Compilation of Improvements to GENE's SAFER ECCS-LOCA Evaluation Model," NEDC-32950P, Re vision 1, July 2007.

C OLUMBIA G ENERATING S TATION Amendment 62 F INAL S AFETY A NALYSIS R EPORT December 2013 LDCN-12-036 6.3-37 Table 6.3-1 Emergency Core Cooling System Design Parameters Parameter Value Initiation Signals High drywell pressure 2.0 psig (not credited) L2 (Low low water level) 9.26 ft above top of active fuel L1 (Low low low water level) 2.68 ft. above top of active fuel LPCS pump running 150 psig pump discharge pressure LPCI pump running 100 psig pump discharge pressure High Pressure Core Spray System Minimum rated flow at vessel pressure (differential pressure between vessel head and suction source) psid gpm 200 6350 1130 1550 1160 516 Vessel pressure that injection valve may open 1175 psia Maximum flow (runout) 7341 gpm Low Pressure Core Spray System Minimum rated flow at vessel pressure (differential pressure between vessel head and suppression pool air volume) psid gpm 128 6350 Vessel pressure that injection valve may open 485 psia Maximum flow (runout) 7800 gpm Low Pressure Coolant Injection Mode RHR System Minimum rated flow at vessel pressure (differential pressure between vessel head and suppression pool air volume) psid gpm 26 7450 Vessel pressure that injection valve may open 485 psia Maximum flow (runout) three pumps 24100 gpm Automatic Depressurization System Number of safety relief valves with ADS function 7 valves Time delay: - Initiation signal to valves open 105 seconds a

a Either of both ADS trip systems may be manua lly inhibited, if necessary, to eliminate resetting the timer.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-38 Table 6.3-2 Loss-Of-Coolant Accident Analysis Initial Conditions and Input Pa rameters - ATRIUM-10 Parameter Value Plant Parameters Core thermal power (includes 2% power

uncertainty) 3716 MWt (106.6%

of rated)

Total core flow rate 115.0 Mlb/hr (106% of rated)

Steam flow rate 16.1 Mlb/hr (107.3% of rated)

Steam dome pressure 1055 psia Core inlet temperature 536°F Core inlet enthalpy 530.0 Btu/lb (Calculated by AREVA NP)

ECCS fluid temperature 120° F Fuel design ATRIUM-10 (10x10 array) Initial minimum critical power ratio 1.25 ATRIUM-10 hot asse mbly (two loop and single loop operation) Recirculation pump moment of inertia (pump, motor, and drive line) 22,700 lbm-ft 2 (AREVA NP analysis limiting value)

Initiation Signals L2 (Low low water level) 5.9 ft. above top of active fuel/

437.5 in above vessel zero L1 (Low low low water level) 1.0 ft. above top of active fuel/

378.5 in above vessel zero LPCS pump running 150 psig pu mp discharge pressure LPCI pump running 100 psig pu mp discharge pressure

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-39 Table 6.3-2 Loss-Of-Coolant Accident Analysis Initial Conditions and Input Parameters -

ATRIUM-10 (Continued)

High Pressure Core Spray System Initiation signal L2 Time delay; initiation signal to pump at rated

speed 27 sec Time delay; initiation signal to injection valve open a 37 sec Maximum injection valve stroke time 17 sec Vessel pressure that injection valve may open 1175 psia Pressure that flow may commence (differential pressure between vessel head

and drywell) 1160 psid Minimum rated flow at 1160 psid b 413 gpm Minimum rated flow at 0 psid b 6250 gpm Vessel head v HPCS flow curve Figure 6.3-5 LPCS Initiation signal L1 Time delay; initiation signal to pump at rated

speed 27 sec Maximum injection valve stroke time 22 sec Time delay; initiation signal to injection valve open a 42 sec Vessel pressure that injection valve may open 351 psia Pressure that flow may commence (differential pressure between vessel head

and drywell) 285 psid Minimum rated flow at 122 psid b 5625 gpm Minimum rated flow at 0 psid b 7030 gpm Vessel head v LPCS flow curve Figure 6.3-1

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-40 Table 6.3-2 Loss-Of-Coolant Accident Analysis Initial Conditions and Input Parameters -

ATRIUM-10 (Continued)

LPCI Initiation signal L1 Time delay; initiation signal to pump at rated

speed 27 sec Maximum injection valve stroke time 26 sec Time delay; initiation signal to injection valve open a 46 sec Vessel pressure that injection valve may open 351 psia Pressure that flow may commence (differential pressure between vessel head

and drywell) 222 psid Rated flow at 200 psid b 6672 gpm 3 loops / 2224 1 pump Minimum rated flow at 0 psid b 21102 gpm 3 loops / 7034 1 pump Vessel head v LPCI flow curve Figure 6.3-2 ADS Initiation signal L1 AND LPCI pump running OR LPCS pump running Number of safety reli ef valves with ADS function 5 valves Time delay; initiation signal to valves open 120 sec (maximum) Minimum flow capacity for 5 valves at

1205 psig in the vessel 4.5 Mlbm/hr a Including instrumentation response time of 5 seconds and diesel generator start/load time of 15 seconds and assuming vessel pressu re permissive is satisfied.

b psid: pressure differential between reactor vessel and drywell.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-41 Table 6.3-2a Plant Operational Parameters (GE14)

Parameter Nominal Assumption Appendix K Assumption Rated Case Core Thermal Power (MW) 3629 3702 Rated Case Core Flow (Mlbm/hr) 108.5 108.5 ELLLA Case Core Thermal Power (MW) 3629 3702 ELLLA Case Core Flow (Mlbm/hr) 102 102 SLO Case Core Thermal Power (MW) 2684.2 2737.9 SLO Case Core Flow (Mlbm/hr) 61.845 61.845 Vessel Steam Dome Pressure (psia) 1055 1055 Feedwater Temperature (°F) 425.7 428 PLHGR Uncertainty (%)

N/A 2 Number of ADS Valves Assumed Available 5 5 Feedwater Temperature Reduction (°F) 65 (1) 65 (1) ICF Core Flow (Mlbm/hr) 115 115 (1) See the discussion in S ection 5.4.3 of Reference 6.3-17.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-42 Table 6.3-2b GE14 Fuel Parameters Parameter Analysis Value PLHGR (kW/ft) - LOCA Analysis Limit

- Appendix K - Nominal 13.40 13.40 x 1.02 12.80 MAPLHGR (kW/ft) - LOCA Analysis Limit

- Appendix K - Nominal 12.82 12.82 x 1.02 12.24 Rod Average Exposure (MWd/MTU) 16,000 Initial Operating MCPR - LOCA Analysis Limit

- Appendix K - Nominal 1.25 1.25 ÷ 1.02 1.25 + 0.02 Fueled Rods per Assembly 92

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-43 Table 6.3-2c SAFER/GESTR-LOCA ECCS Parameters (GE14)

Low Pressure Coolant Injection (LPCI) System Variable Units Analysis Value a. Maximum vessel pressure at which pumps can inject flow psid (vessel to drywell) 222 b. Minimum rated flow (into shroud)

  • Vessel pressure at which below listed flow rates are quoted
  • One (1) LPCI pump injecting inside shroud
  • Two (2) LPCI pumps injecting inside shroud
  • Three (3) LPCI pumps injecting inside shroud psid (vessel to drywell) gpm gpm gpm 20 6,713 13,426 20,139 c. Run-out flow at 0 psid (vessel to drywell)
  • One (1) LPCI pump injecting inside shroud
  • Two (2) LPCI pumps injecting inside shroud
  • Three (3) LPCI pumps injecting inside shroud gpm gpm gpm 7,034 14,068 21,102 d. Initiating signals
  • Low low low water level (Level 1) inches above vessel "zero" 378.5 e. Vessel pressure at wh ich injection valve may open psig 336 f. Maximum delay time from pump start until pump is at rated speed sec 26 g. Maximum injection va lve stroke time-opening sec 26 h. Delay time to process initiation signal sec 5 C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-44 Table 6.3-2c SAFER/GESTR-LOCA ECCS Parameters (GE14) (Continued)

Low Pressure Core Spray (LPCS) System Variable Units Analysis Value a. Maximum vessel pressure at which pumps can inject flow psid (vessel to drywell) 285 b. Minimum rated flow at vessel-to-drywell pressure (into shroud) gpm psid 5625 122 c. Run-out flow at 0 psid (vessel to drywell) gpm 7030 d. Initiating signals

  • Low low low water level (Level 1) inches above vessel "zero" 378.5 e. Vessel pressure at wh ich injection valve may open psig 336 f. Maximum delay time from pump start until pump is at rated speed sec 7 g. Maximum injection va lve stroke time-opening sec 22 h. Delay time to process initiation signal sec 5

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-45 Table 6.3-2c SAFER/GESTR-LOCA ECCS Parameters (GE14) (Continued)

High Pressure Core Sp ray (HPCS) System Variable Units Analysis Value a. Vessel Pressure at which flow may commence psid (vessel to source) 1160 b. Minimum rated flow and vessel pressure gpm/psid (vessel to source of suction) 413/1160 920/1130 5000/200 6250/0 c. Run-out flow at 0 psid (vessel to source of suction) gpm 6250 d. Initiating signals

  • Low low water level (Level 2) inches above vessel "zero" 437.5 e. Maximum delay time from pump start until pump is at rated speed sec 7 f. Maximum injection valve stroke time-opening sec 17 g. Delay time to process initiation signal sec 5

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-46 Table 6.3-2c SAFER/GESTR-LOCA ECCS Parameters (GE14) (Continued)

Automatic Depressurization System (ADS)

Variable Units Analysis Value a. Total number of valves with ADS function available 7 b. Number of ADS valves assumed in the analysis 5 c. Pressure at which belo w listed capacity is quoted psig 1205 d. Minimum flow capacity at pr essure given in c with all available ADS valves open lbm/hr 9.0 x 10 5e. Initiating Signals

  • Low low low water level (Level 1) and
  • ADS Timer Delay from initiati ng signal completed to the time valves are open inches above vessel "zero" sec 378.5 120 f. Delay time to process initiation signal sec 5

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-47 Table 6.3-3 Single Failures Considered in the ECCS Performance Evaluation - AREVA Location Failure Systems Remaining a Recirculation Suction Line LPCS Diesel Generator Failure ADS, HPCS, 2 LPCI Recirculation Suction Line HPCS Failure ADS, LPCS, 3 LPCI Recirculation Suction Line LPCI Diesel Generator Failure ADS, HPCS, LPCS, 1 LPCI HPCS Spray Line LPCS Diesel Generator Failure ADS, 2 LPCI LPCS Spray Line HPCS Diesel Generator Failure ADS, 3 LPCI a For a LOCA from an ECCS line break, the systems remaining are those listed, less the ECCS system in which the break is assumed.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-48 Table 6.3-3a Single Failure Considered in ECCS Performance Evaluation Based on SAFER/GESTR-LOCA (GE14)

Break Location Assumed Failure (1) Systems Remaining (2) (3) Recirculation Suction Line LPCI Emergency D/G ADS, HPCS, LPCS, 1 LPCI Recirculation Suction Line LPCS Emergency D/G ADS, HPCS, 2 LPCI Recirculation Suction Line HPCS Emergency D/G ADS, LPCS, 3 LPCI Core Spray Line LPCS Emergency D/G ADS, 2 LPCI Steamline Inside Containment LPCI Emergency D/G ADS, HPCS, LPCS, 1 LPCI Steamline Outside Containment HPCS Emergency D/G ADS, LPCS, 3 LPCI Feedwater Line HPCS Emergency D/G ADS, LPCS, 3 LPCI LPCI Line HPCS Emergency D/G ADS, LPCS, 2 LPCI (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.

(3) The analyses are performed with two non-function ADS valves in addition to the single failure.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 6.3-49 Table 6.3-4 Loss-Of-Coolant Accident Sequence of Events for Limiting Break (AREVA NP Analysis)

Time (second)

Event 0.0 Break initiation 0.8 Reactor scram initiated 7.9 Level 2 reached (low-low RPV level) 9.3 Level 1 reached (low-low-low RPV level) 10.9 Jet pumps uncover 15.0 RRC pump su ction uncovered 17.5 Start lower plenum flashing 44.9 Start HPCS flow 72.7 Start LPCS flow 76.7 Start LPCI flow 79.8 Reach rated LPCS flow 79.8 End of blowdown 118.9 Core reflooded 118.9 Peak cladding temperature reached 129.3 ADS valves open

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-50 Table 6.3-4a Event Scenario for 100% DBA Re circulation Suc tion Line Break HPCS DG Failure (Appendix K, GE14)

Event Time (sec)

Break Occurs

0.0 Scram

Initiated and Occurs 0.01 Level 1 Trip 4.97 Feedwater Flow Reaches Zero 5.00 First Peak PCT GE14 Fuel (1232°F) Occurs 5.50 Jet Pump Suction Uncovers 5.98 Main Steamline Flow Stops 6.14 Suction Line Uncovers 8.54 Lower Plenum Flashes 9.15 LPCS/LPCI IV Pressure Permissive Reached 30.45 LPCS Injection Occurs 57.45 LPCI Injection Occurs 61.45 Second Peak PCT GE14 Fuel (1346°F) Occurs 148.18

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-035 6.3-51 Table 6.3-4b Event Scenario for 0.07 ft 2 Recirculation Suction Line Break HPCS DG Failure (Appendix K, GE14)

Event Time (sec)

Break Occurs

0.0 Scram

Initiated and Occurs 0.01 Feedwater Flow Reaches Zero 5.00 Level 1 Trip 114.50 SRVs Open 178.47 Jet Pump Suction Uncovers 221.47 ADS Valves Open 239.50 Main Steamline Flow Stops 246.99 Lower Plenum Flashes 248.61 Suction Line Uncovers 369.46 LPCS/LPCI IV Pressure Permissive Reached 394.23 LPCS Injection Occurs 421.23 LPCI Injection Occurs 425.23 Peak PCT GE14 Fuel (1647°F) Occurs 450.81

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-10-029 6.3-52 Table 6.3-5 ECCS Performance Analysis Results Parameter GE14 Value AREVA NP Value Two loop operation Single loop operation Two loop operation Single loop operation Thermal power (including 2% power uncertainty) 106.2% rated power (3702 MWt) 78.5% rated power (2737.9 MWt) 106.6% rated power (3716 MWt) 106.6% rated power (3716 MWt)

Core flow 100% rated flow (108.5 Mlb/hr) 57% rated flow (61.845 Mlb/hr) 106% rated flow 115 Mlb/hr 106% rated flow 115 Mlb/hr Limiting break 0.07 ft 2 Recirculation suction line, HPCS DG failure 100% DBA Recirculation suction line, HPCS DG failure 100% DEG RRC suction line LPCI DG failure 100% DEG RRC suction line LPCI DG failure Peak cladding temperature (Appendix K) 1647°F 1210°F 1604°F 1601°F Licensing basis peak cladding temperature 1710°F Maximum cladding oxidation 1% 0.26% 0.26% Total core hydrogen generation 0.1% < 1.0% < 1.0%

Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Head Versus Low-Pressure Core Spray Flow used in LOCA Analysis 960222.13 6.3-101000200060007000 0 100 200 Flow (gpm)300040005000 300 250 50 150 Columbia Generating Station Final Safety Analysis Report Pressure Vessel Head Over Drywell (psid)

Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.Head Versus Low-Pressure Coolant Injection Flow used in LOCA Analysis 960222.14 6.3-201000200060007000 0 100 200 Flow (gpm)300040005000 250 50 150 Columbia Generating Station Final Safety Analysis Report Pressure Vessel Head Over Drywell (psid)

Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 06.3-3.1 7 02E22-04,7,1High-Pressure Core Spray - Process DiagramRev.FigureDraw. No.

Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 6.3-4 101 M520High-Pressure Core Spray and Low-Pressure Core Spray Flow DiagramsRev.FigureDraw. No.

Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Head Versus High-Pressure Core Spray Flow used in LOC A Analysis 960222.12 6.3-501000200060007000 0 400 800 Flow (gpm)

Pressure Vessel Head Over Drywell (psid)300040005000 1200 1000 200 600 Columbia Generating StationFinal Safety Analysis Report Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 6.3-6 8 02E21-04,4,1Low-Pressure Core Spray - Process DiagramRev.FigureDraw. No.

Typical 48 in. Diameter Strainer 920843.07 6.3-7 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Penetrations Qualifications Inc.

8006 Sulfate Mixture

BPM-D-4 gnm re-generated

R-44 VPR vs. variable Note: Strainer halves are bolted together to form one strainer with a 47.5 inch Outer Diameter 48 inch Diameter Half - Strainer Configuration for Penetrations X-32, X-35 Columbia Generating StationFinal Safety Analysis Report Typical 36 in. Diameter Strainer 920843.06 6.3-8 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Penetrations Qualifications Inc.

8006 Sulfate Mixture

BPM-D-4 gnm re-generated

R-44 VPR vs. variableNote: The number of disks varies with strainer length.

36 inch Diameter Strainer Configuration for Penetrations X-31, X-34, and X-36 Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Peak Cladding Temperature and Maximum LocalOxidation Versus Break Area - Hanford Original Rated Power 960222.23 6.3-9 Suction Break LPCI D/G Failure Suction Break LPCS D/G Failure

Suction Break HPCS Failure Max. CSLN Break

LPCS D/G FailureMax STML Break LPCI D/G FailureMax STML Break

HPCS Failure Large Break Method

For Suct Break Small Break Method

For Suct Break Max. Fdwr Break

HPCS Failure 0 1000 2000 0.01 0.1 1.0Break Area (Square Feet)

Peak Cladding Temperature (°Fahrenheit) 0 10 20 Maximum Local Oxidation (%)

Columbia Generating StationFinal Safety Analysis Report C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-1 6.4 HABITABILITY SYSTEMS

6.4.1 DESIGN

BASIS

The main Control Room Envelope Habitability (CREH) systems are designed to ensure habitability inside the main control room. The CREH systems ensure the Control Room Envelope (CRE) occupants can c ontrol the reactor safely under normal conditions and maintain it in a safe condition following a radiological even t, a hazardous chemical release, or a smoke challenge. The CREH systems ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design ba sis accident (DBA) conditions. Under DBA conditions, personnel will receive ra diation exposures no greater than 5 rem total effective dose equivalent (TEDE) for the duration of the accident in accordance with 10 CFR part 50.67 as discussed in Chapter 15. The CREH Program en sures the CREH system is in compliance with General Design Criterion 19 (GDC 19) of 10 CFR 50, Appendix A, and in compliance with the guidance of Regulatory Guide 1.196.

Emergency supplies for the control room, technical support center (TSC), and operational support center will be provided by the Emergency Response Organization.

Portable breathing

apparatus is also provided in the control room for operating personnel protection in the event of a fire external to the plant or a chemical spill on or offsit

e. The control room heating, ventilating, and air conditioni ng (HVAC) is operated in the recirculation mode without filtration by the emergency filter units for both of these scenarios.

In the event of a LOCA, operating personnel wi thin the control room are protected from airborne radioactivity for up to 30 days by means of pressurizing th e control room with filtered air drawn from two separate remote fresh air intakes through the c ontrol room emergency filtration (CREF) system. Both intakes are physically remote from all plant structures. The CREF system has two redundant trains which can filter air drawn for the intakes. The system is designed such that both trai ns will start simultaneously, however a single train operation results in higher LOCA dose than a dual train operation, therefore the license basis LOCA dose analysis assumes a single trai n operation. If two trains start, the operator will be directed to not stop the second train until at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> post accident.

Redundant radiation monitors are located at each of the two remote intake headers. If desired, the valves in the most contaminated remote intake may be manually closed at any time post accident. However, to maintain control room pressurization at least one remote intake must be open at any time post accident.

Adequate shielding is also provided to protect operating personnel from radiation streaming.

The control room doors are ad equately designed to protect operating personnel from a steam pipe break in the turbine generator building.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-2 The control room HVAC is also pr essurized in the event of a fire within the plant, but external to the control room, to prevent ingress of smoke or combustion vapors.

Components of the HVAC systems serving the control room that are required to ensure control

room habitability and essentia l equipment operations are re dundant, Seismic Category I, and powered from Class 1E buses.

6.4.2 SYSTEM

DESIGN

6.4.2.1 Definition of Main Control Room Envelope The main control room is located on el. 501 ft of the radwaste building. Included in the CRE are all essential control equipment of the plant plus a toilet, kitc hen, dining area, and an office area. These areas are frequently occupied.

The CRE boundary is the combination of walls , floor, ceiling, doors, penetrations, ducting, and equipment that physically form the boun dary of the CRE. The equipment boundary includes fan housings, air handler s, and associated drain loop seals of the control room ventilation systems. The ducting boundary includes the HVAC duc ts serving the control room starting from the fresh air isolation dampers to the common supply h eader penetrating the control room ceiling, and up to the isolation damper in the kitchen and ba throom exhaust duct. The enclosed volume of the CR E is approximately 214,000 ft

3. See Reference 6.4-1 for a more detailed description of the CRE.

6.4.2.2 Ventilation System Design

A description of the ventilation systems serving the control room and a listing of the design and performance parameters of the ventilation system equipment is provided in Section 9.4.1.

6.4.2.3 Leaktightness

A description of system leaktight ness is discussed in Section 9.4.1.

6.4.2.4 Interaction With Other Zone s and Pressure Containing Equipment Normal access into the main control room is through corridors that are radiologically clean.

Chemicals stored within the radwaste building or the immediately adjacent structures are in small quantities and are not hazardous to control room personnel.

Within the main CRE, ther e are no pressure vessels or piping systems that would affect control room habitability, except for th e individual Halon fire extinguish ing system within the control panels. Halon emitted to the main control room would be in the form of leakage from the Halon flooding systems. If all the Halon cylinders in the largest system were to release

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-3 simultaneously, the projected concentration in the CRE would be about 2690 ppm (<0.3% by volume). This concentration is significantly less than the 50,000 ppm level at which the concentration would be immediately dangerous to life and health (IDLH). The decrease in oxygen concentration in the control room would be approximately 0.1%. The main control room is protected from external pressurized systems by distance and c oncrete shield walls.

6.4.2.5 Shielding Design

The control room is designed with adequate shielding to protect occupa nts from conditions of airborne activity in containmen t and the reactor building, air borne activity in the radwaste building, the activity surroundi ng the building as a result of isotopes released to the environment, and activity built up on the main control room filters (located one floor above the control room). The concrete wa lls surrounding the control room are a minimum 2 ft thick and the floor and ceiling slabs are a minimum 1 ft thick. Radiation str eaming is minimized by locating equipment, cable tray, a nd duct penetrations in the area s where radioactive sources are weak or nonexistent. There are no significant piping penetrations into the main control room.

The normal primary access doors have been desi gned with air locks and may be used to prevent air inleakage into the control room during ingress and egress. The control room dose analysis for a LOCA does not take credit for the installed control room door air locks to minimize air inleakage. Radiation streaming th rough the doors has also been analyzed and evaluated as insignificant.

Direct doses to the control room from confined sources such as in some areas of the radwaste building, the turbine building, and from potential DBA sources in containment and in the reactor building are negligible due to local shielding provided around the source and shielding around the control room. Radiation from contai nment must penetrate the following shielding before reaching the control room: the 0.75-in. steel containment shell, the 5-ft-thick concrete biological shield wall, the 2-ft-t hick concrete reactor building wa ll, and the 2-ft-thick concrete control room wall. Similarly, a 2-ft-thick concrete wall exists between the turbine building and the 2-ft-thick control room wall. In areas, the turbine building wall is 42 in. thick for shielding and missile purposes yielding 5.5 ft of protection to the control room from turbine building radiation areas. The HVAC room above the control room has an 18-in. concrete roof slab.

This room coupled with the 1-ft-thick concrete control room ceiling yields an effective 2.5 ft of concrete shielding for th e control room ceiling.

Details of the dose evaluation for the control room are given in Chapter 15. 6.4.3 SYSTEM OPERATIONAL PROCEDURES

During normal and emergency ope ration the control room operato r selects the air handling unit which operates to maintain design temperatures in the control room. Periodically the operating unit is exchanged with the standby unit so that the service time of both units is approximately

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-4 equal. In the event the operating unit fails, control room personnel start the standby unit from the control room.

The responses of the control room habitability system to either hazardous ch emical or airborne radioactivity are compatible. In the event of a hazardous chemic al release, th e operators may take action to stop the exhaust fan, shut the associated damper , and close the fresh air inlet damper for each HVAC train. On receipt of a high-high airborne radioactivity level alarm signal at a remote intake, the operators may re spond by closing the appr opriate remote intake isolation valves. Portable br eathing apparatus is available.

6.4.4 DESIGN

EVALUATION

6.4.4.1 Radiological Protection

Personnel in the main control room are protected from the radi ological effects of a postulated accident by pressurizing the main co ntrol room with 1000 cfm of filtered air drawn from either of two remote fresh air intakes. This operation limits the 30-d ay dose to operators to below that of GDC 19 of 10 CFR 50, Appendix A, and 10 CFR 50.67. Essentia l components of the control room habitability sy stems are redundant, Seismic Category I, and powered from Class 1E buses.

The emergency ventilation system is of the dual inlet design with manual isolation valves above the control room. See Section 9.4.1 for the system description. The guidance in Regulatory Guide 1.183 was used in the control room dose analyses fo r Columbia Generating Station (CGS) and is addressed in the individual event evaluations in Chapter 15.

6.4.4.2 Toxic Gas Protection

6.4.4.2.1 Chlorine

Chlorine is not used at CGS.

Transportation routes involved in chlorine movements include Hanford Route 4 South to the we st on which there may be four shipments per year. In the past, 1-ton cylinders have been shipped two or three times per year on the Hanford Railroad (750 ft east of CGS); however th ere have been none since June 1983 and it is anticipated that chlorine will continue to be tr ansported on the highway instead.

Control room concentrations from a postulate d accident were calculate d using the methodology of References 6.4-2 and 6.4-3. Assuming no operator action, the maximum control room concentration of gaseous chlorine from an offsite accident involving the rupture of a 1-ton cylinder at a point 4500 ft di rectly upwind of the control room air intake is 29 mg/m 3 at 32 minutes after the arrival of the leading edge of the initial vapor cloud. This is below the 45 mg/m 3 2-minute toxicity limit specified in Reference 6.4-4.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-5 The protection provided to the control room operators from an offsite chlorine release includes the capability of closing the control room air ducts with dampers and isolating the control room. The postulated accident and associated assumptions would yield concentrations exceeding the short-term exposure limit of 11.5 mg/m 3 specified by Reference 6.4-5 for approximately 3.5 hr assuming no operator action. Since the odor thre shold is approximately 0.01 ppm (0.03 mg/m 3), per Reference 6.4-6 , operators could quickly detect the presence of chlorine and isolate the contro l room. With this realistic assumption, there would be no hazardous exposure to chlorine.

In summary, a. The CGS control room fresh air intake is not equipped with chlorine detectors and automatic isol ation equipment,

b. No chlorine is stored onsite, and
c. Chlorine storage and movement within 5 miles is less than thresholds specified in Reference 6.4-4.

6.4.4.2.2 Sodium Oxide

The Department of Energy Fast Flux Test Facility (FFTF) is locate d approximately 4000 m southwest of CGS. A large quantity of liquid s odium was used in the operation of the FFTF.

The facility is shut down and in the process of deactivation and decommissioning. Sodium has been drained from the primary and secondary heat transfer system loops and is being maintained in solid state in th e Sodium Storage Facility tanks. A small amount of residual sodium remains in the piping systems and has been solidified (Reference 6.4-7).

The accident evaluated during the initial licensing of CGS was a liquid sodium release from a FFTF secondary loop component failure due to a tornado. The probability of such a release is significantly reduced because th e primary and secondary loops ar e now drained and the sodium solidified. Since solidified sodium continues to be located at the site, this analysis is retained as a bounding event until the solidified sodium is re moved from the site or the possibility of a release is further reduced.

The analysis is assumed that a failure occurs in the FFTF secondary loop component due to a tornado. A resulting postulated 100,000-lb sodium release over 20 hr was considered bounding for CGS control room habitability purposes (Reference 6.4-8).

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-6 The following assumptions are made:

a. Two million pounds of liquid sodium c ontained in the primary coolant loop are not considered in the analysis since it is contained in the FFTF reactor containment building,
b. 100,000 lb of liquid se condary sodium may be released and ignited,
c. Up to 36% of the sodium oxide formed in the combustion of the 100,000 lb of sodium may be released and transported away as an aerosol,
d. Fire resulting from the accidental release of 100,000 lb of sodium would consume the available sodium at whatever rate it is released, and
e. The average sodium oxide release ra te assumed was for a 20-hr postulated incident at 2426.4 lb/hr.

Where applicable, Reference 6.4-4 was utilized. However, due to the nature of the postulated sodium fire and the complexities of the disp ersion analysis, the following additional modeling assumptions were utilized:

a. CGS onsite meteorological data collected from April 1974 through March 1976 was used to establish the upper wind speed values in addition to the established 5% dispersion meteorology for the CGS site;
b. To account for the rise of sodium oxide aerosol due to the buoyancy of the hot gases, the height of rise of the aerosol plume was conservati vely predicted using Part 1, References 6.4-9 and 6.4-10;
c. To account for settling and deposition of the sodium oxide particulates within the plume, depleted source terms were established (Reference 6.4-11); and
d. Six plume dispersion modeling equations were used to calcula te concentrations outside the CGS control room fresh air intakes as a function of wind speed and stability. Credit for FFT F building wake dilution effects during high wind speed conditions, plume meandering for stable low wind speed conditions, and both a depleted plume equation and tilted plume equation to account for deposition were included as discussed in References 6.4-11 , 6.4-12 , and 6.4-13.

The analysis resulted in a maximum sodium oxide concentration outside the control room intakes of 8.7 mg/m

3. A wind speed of 1.2 m/sec would allow FFTF approximately 55 minutes to warn CGS control room personne l of the approaching sodium oxide cloud, assuming that the cloud was trave ling directly toward the CGS s ite. The permissible warning C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-7 time, as well as the cloud concentration, would increase for li ghter wind speed conditions, i.e., up to approximately 1.5-hr warning time for a 0.75 m/sec wind producing a maximum cloud concentration of 8.7 mg/m
3. Wind speeds greater than 1.2 m/sec yield concentrations less than the long-term toxicity limit of 2 mg/m
3.

A warning time of approximately 55 minutes is sufficient to perm it proper notification to take place between FFTF and Energy Northwest personne l, to isolate the CGS control room.

Procedural arrangements are in place be tween FFTF and Energy Northwest for timely notification of the control room in the event of a sodium oxide release. In th e unlikely event that sodium oxide enters the control room, portable breathing equipment is available.

6.4.4.2.3 Miscellaneous Chemicals

Other onsite stored chemicals were re viewed in accordan ce with Reference 6.4-4 to assess their potential impact on the habitability of the control room in th e event of postulated hazardous chemical releases. Chemicals stored onsite and analyzed for impact on the control room habitability are ammonium hydroxide, carbon dioxide, trichlorofluor omethane (Freon-11), dichlorodifloromethane (Freon-12), chlorodifluoromethane (Freon-22), trichlorotrifluoromethane (Fre on-113), and 1,1,1,2-tetrafluoromethane (Freon-134a), hydrogen peroxide, hydrogen, isopropyl alcohol, methyl ethyl ketone, nitr ogen (liquid), propane, sodium hydroxide (in solution), sodium hypochlorite, sodium bromide, a nd sulfuric acid, diesel fuel, ethylene glycol, fyrquel, GE Betz

Dearborn inhibitor AZ8104,

gasoline, Halon 1301, hydrochloric acid, mineral spirits , insecticide, herbicides, fertilizers, lubricants, transformer oils, ONDEO NALCO chemicals, paint products, propylene glycol, and polyaluminum chloride solution.

The analysis (Reference 6.4-14) indicated that most of these chemicals did not require chemical hazard evaluations due to the fact that they exist in small quan tities, are stored far away from the control room intakes, have a very low vapor pressure, or are bounded by the results of the calculations performed on the chemicals listed below.

The following chemicals met the screening criteria of Reference 6.4-4 required a chemical hazard evaluation:

a. A liquid nitrogen storage tank containing 75,000 lb of nitrogen locat ed at the corner of the diesel generator building.
b. A tank containing 12,000 lb of cardox (CO2) stored in the turbine generator building.
c. A 55-gallon drum containing ammonium hydroxide stored approximately 100 ft from building 74 (warehouse fo r maintenance lubricants).

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-8 d. Two tanks containing 1700 gallons each of Freon-11 stored in the Refrigerant Storage and Maintenance building (Building 72) approximately 800 ft from the nearest control room air intake.

Postulated releases to the atmosphere and subse quent transport to control room fresh air intakes of these chemicals were evaluated. The results of the analysis (Reference 6.4-14) indicated that an accidental release of these chemicals wi ll result in concentrati ons in the control room that are well below the toxicity limit of each of the chemicals. Therefore, these chemicals do not pose a hazard to the control room operators.

There are a significant number of compressed gas bottles containing process gasses such as nitrogen, hydrogen, argon, he lium and others containing acetyl ene, argon/methane and oxygen used within the plant buildings and onsite bo ttle storage locations.

These gas bottles do not represent a control room habitability concern due to the small quantity of gas contained in each bottle.

Maximum quantities of hydrogen ga s stored in the gas bottle storage building (120 bottles containing a total of 144 lb) and in a trailer park ed adjacent to the ga s bottle storage building containing 294 lb will not pose any problem because the lightness and dispersal qualities of the gas and the distances (approximately 400 ft) to the nearest control room air intake would result in negligible concentrations at that location.

The Hydrogen Storage and Supply Facility (HSSF) has a maximum storage capacity of approximately 9800 pounds of liquid and gaseous hydrogen. Th e storage of this amount of hydrogen at the HSSF is not considered a hazard for control room ha bitability due to the distance (approximately 2900 ft) between the closest fresh air intake and the HSSF.

An 18,000-gal sulfuric acid storage tank, one 5000-gal tank of sodium hyp ochlorite, and one 5000-gal tank of sodium bromide are loca ted near the circulating water pump house approximately 570 ft from the control room intake. Two 2100-gal tanks of hydrogen peroxide are located near pump house 1B (approximately 300 ft from the control room intake). Other stored chemicals include 500-gal propane tanks (located over 1100 ft from the control room intake), as well as other miscella neous or transient storage of lesser quantities of chemicals that are bounded by the analyses performed for th e chemicals stored in bulk quantities.

6.4.5 TESTING

AND INSPECTION

The main control room HVAC system and its components are tested as follows:

a. Predelivery and compone nt qualification tests, b. Postdelivery acceptance tests, and
c. Postoperation surveillance tests.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-9 Written test procedures establish acceptable criteria for the tests. The tests are performed to meet the objectives of Regulatory Guide 1.52 and Regulatory Guide 1.197.

The factory and component qualification tests consist of the following:

a. All equipment was factory inspected and tested in accordance with the applicable equipment specifi cations, codes, and quality assurance requirements.

System ductwork and erection of equi pment was inspected during various construction stages for quality assurance. Construction test s were performed on all mechanical components and the system was balanced for the design air and water flows and system operating pressures. Controls , interlocks, and safety devices were checked, adjusted, and test ed to ensure the proper sequence of operation.

b. The emergency filter units, which are normally in standby, are started periodically to ensure fan operation. The fans are factory tested in accordance with AMCA Standard 210, "Air Movi ng and Conditioning Association, Test Code for Air Moving Devices."

Filters are tested as described in Section 9.4.1. c. All valves associated with the control room HVAC system are factory leak tested, bubble tight, at a pre ssure differential of 0.2 psig. Electrically operated valves are factory tested to ensure that valve stroke time, full open to full close, does not exceed 4 sec. Once installed, the valves are stroked to verify operability. The fresh-air inta ke valves are periodically tested to ensure control room inleakage through closed intake valves is minimized.

d. The postdelivery acceptance tests are performed as described in Section 14.2.
e. The operational surveillance testing is described in the Technical Specifications.

6.4.6 INSTRUMENTATION

REQUIREMENTS

A discussion of instrumentation associated with main control room ha bitability systems is provided in Sections 9.4.1 and 7.3.1.1.7.

6.

4.7 REFERENCES

6.4-1 "Control Room Boundary Leakag e Limitations," TM

-2082, Revision 5.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-07-025 6.4-10 6.4-2 Turner, D. B., Workbook of Atmospheric Dispersion Estimates , Public Health Service, U.S. Department of Health Education, and Welfare, Figures 3.2 and 3.3, 1970.

6.4-3 Wing, J., Toxic Vapor Concentration in the Control Room Following a Postulated Accidental Release , NUREG-0570, Nuclear Regulatory Commission, June 1979.

6.4-4 "Assumptions for Evaluating the Habita bility of a Nuclear Power Plant Control Room During a Postul ated Hazardous Chemical Release," Regulatory Guide 1.78, June 1974.

6.4-5 Nuclear Regulatory Commission, St andard Review Plan, Section 6.4, NUREG-0800 (Revision 2), July 1981.

6.4-6 Occupational Health Guid elines for Chemical Hazards , NIOSH, U.S. Department of Health and Human Services, August 1981.

6.4-7 FFTF Hazard Analysis Supporting Discussion & Analysis , "Fast Flux Test Facility Hazard Assessment," HNF-SD-PRP-HA-0.15 Revision 6, April 31, 2007.

6.4-8 Excerpts from Sections 6.4, "Habitability System," and 15.2, "Accident Analyses," of the FFTF FSAR (Amendment 3, February 1, 1977).

6.4-9 Briggs, G. A., "Plume Rise: A Recent Critical Review," Nuclear Safety Vol. 12, No. 1, 1971.

6.4-10 Briggs, G. A., "Plume Rise Predictions," Le ctures on Air Pollution and Environmental Impact Analysis, American Meteorological Society, Boston, Mass., 1975.

6.4-11 Slade, D., Meteorology and Atomic Energy, U.S.

Atomic Energy Commission, Division of Technical Inform ation, Springfield, VA 1968.

6.4-12 Stern, A. C., Air Pollution, Their Transformation and Transport, Vol. I Third Edition, Academic Press, New York, 1976.

6.4-13 Nuclear Regulatory Commission, BTP HMB, Diffusion C onditions for Design Basis Accident Evaluations, 1977.

6.4-14 "Chemical Hazard Analysis for Control Room Hab itability," CGS calculation number NE-02-06-02, April 2007.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-000 6.5-1 6.5 FISSION PRODUCT REMOVAL AND CONTROL SYSTEMS

6.5.1 ENGINEERED

SAFETY FEATURE FILTER SYSTEMS

There are two air filtration systems that are required to perform safe ty-related functions following a design basis accident. They are th e control room emergency filtration (CREF) system, which is described in Sections 6.4 and 9.4.1 , and the standby gas treatment (SGT) system described in this section.

6.5.1.1 Design Bases

The SGT system is designed to maintain airborne radioactive release from the secondary containment to the atmosphere within the lim its required by 10 CFR 50.67. The system is designed to enable purging of the primary cont ainment through the SGT system filters when

airborne radiation levels inside the primary containment are too high to permit direct purging to atmosphere by means of the reactor buildi ng exhaust system as discussed in Section 9.4.

The SGT system design meets seismic requireme nts and single failure criterion. Each SGT system filter train is sized to maintain the s econdary containment (reactor building) at least 0.25-in. water gauge below atmospheric pressure under the following conditions:

a. Air leakage into the secondary containm ent at a continuous rate of one building air change per day,
b. A drop in barometric pressure at the rate corresponding to adverse meteorological conditions,
c. Relative humidity increase resulting from vapor from the spent fuel pool, and
d. The volumetric expansion of air within the secondary containment due to the heat sources in the reactor building.

6.5.1.2 System Design

The SGT system is shown in Figure 3.2-2. The layout of the SGT system units is shown in Figure 12.3-23. Principal system components are listed and described in Table 6.5-1. The system consists of two fully redundant filter tr ains, each of which consists of the following components in series:

a. A demister (moisture separator) to remove entrained water particles in the incoming air stream;

C OLUMBIA G ENERATING S TATION Amendment 62 F INAL S AFETY A NALYSIS R EPORT December 2013 LDCN-12-018 6.5-2 b. Two banks of electric blast coil heat ers, one primary and one backup, each powered from separate emergency diesel buses. Each heater is composed of three 6.9 kW stages and is sized to lim it the relative humidity of the heated air to 70% at design flow during post-LOCA conditions;

c. A bank of prefilters to rem ove most particulates from the air stream. The filters have an atmospheric dust spot efficien cy of 80-85% by ASHRAE Standard 52.1 (MERV 13 rating by ASHRAE standard 52.2);
d. A bank of high-efficiency particulate ai r (HEPA) filters to remove virtually all particulates, including iodine fi ssion products from the airstream;
e. Two 4-in.-deep bank of char coal adsorber filters are in stalled in series. Filters are of an all-welded, gasketless design.

Each charcoal adsorber filter has electric strip heaters.

f. A second bank of HEPA filters, identical to item d. The function of this second HEPA filter bank is to capture charco al dust as well as particulate fission product releases that may escap e from the charcoal filters.

All of the above components are mounted in an a ll welded steel housing. The SGT filter trains are located on the el. 572 ft of the reactor build ing. A 12-in.-thick concrete partition wall, 14 ft high, separates the two trains. The Seismic Category I design partition wall serves as

both a missile barrier and fire barrier between the two trains.

There are at least 2268 lb of charcoal in each of the two adsorber units. The adsorbing capability of each unit is 2.5 mg of halogens per gram of charcoal or a total of 2577 g. The

maximum theoretical accumulation of halogens on the SGT system adsorbers for a 30-day

period after a LOCA is 67 g.

Three independent deluge spray systems are pr ovided for fire protection in each SGT filter train. One deluge spray system is provided fo r protection of the pref ilter and a deluge spray system is provided for each of the two charcoal filter beds.

Two centrifugal fans are provided with each SG T filter train. The primary fan starts automatically upon receipt of an initiation signal.

The backup fan operates only in the event of primary fan failure. The two fans of each unit are powered from separate emergency diesel

buses. Two identical control systems which are supported by emergency power adjust the

automatic inlet vanes on the fans to control flow rate. See Section 7.3.1.1.9. Ductwork and butterfly valves on the discharge air side of each filter train are arranged such that either fan can draw air through the filter train and discha rge it either out of the reactor building, by means of the reactor building el evated release duct, or back into the reactor building.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.5-3 Provision is made to return air to the reactor bu ilding so that decay heat generated within the SGT unit due to the collection of radi oactive contaminants is removed.

Ductwork and valving for the intake of each SGT unit is configured so that the units can draw air from the reactor building in the immediate vicinity of the unit, the primary containment drywell, the wetwell, or from any combinati on of the three locations. The connection to primary containment is through the prim ary containment purge exhaust lines.

During normal plant operation both SGT units ar e on standby. In standby, only the strip heaters in the charcoal sections operate. The strip heaters cycl e to maintain the filter plenum temperature to ensure that th e relative humidity within the pl enum does not exceed 70%. This protects the charcoal adsorber from condensed moisture.

The maximum dewpoint temperature in the r eactor building during normal plant operation is 75°F. When in standby, all isolation valves downstream of the unit fans are closed.

Whenever the drywell requires venting to relieve pressure, purging to inert or to deinert, or purging to improve the quality of the drywell atmo sphere, the SGT system can be used to treat the effluent gas before release. For this pr ocess, the system is manually operated from the control room. The operator initiates the SGT system and adju sts SGT flow to the required flow rate. A sensor in the fan discharge duct transmits a flow signal to a recorder monitored by the operator during the evolution. Purge suppl y air to the primary containment is supplied from the reactor building supply air system. Du ring the process of inerting, nitrogen gas is supplied from the containment nitrogen inerting system.

Both SGT filter trains are automati cally actuated by the following signals:

a. High radiation in the reactor building ventilation exhaust duct,
b. High pressure in the drywell, and
c. Reactor vessel low-low water level.

When actuated the following sequence of events occur in each SGT train:

a. The primary bank of electric blast coil heaters is energized and all valves begin to move to their proper positions;
b. After the primary bank of heaters ha s time to reach a te mperature that will ensure air entering the charcoal bed is maintained below 70% relative humidity, the primary fan receives a start signal;
c. If the primary fan fails to start or r un, following a time delay, the primary fan and heater are deenergized.

Then the primary fan in let valve receives a close signal and the backup heater is energi zed. Next, following an additional time

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.5-4 delay to reach temperature, the backup fan isolation valve is opened and the backup fan receives a start signal;

d. The operating fan inlet vane position is controlle d by the reactor building pressure control system to ensure th at secondary containment pressure is reduced to at least a negative pressure of 0.25 in. w.g.. The control system will adjust fan flow rate as needed to maintain the negative pressure.

Both SGT units are operating within two minut es following the initiation signal. The same sequence is followed if the initiation signal is coincident with a loss of offsite power.

The operator may stop one of the SGT trains from the control room after startup is complete.

In the event that the radiation monitors in the discharge duct indicate an unacceptable radiation level in the system discharge air, the operator starts the second unit and diverts the discharge air of the operating unit back into the reactor bu ilding to minimize offsite release of halogens and to cool the charcoal bed.

The following is a comparison of the engineered safety feature (ESF) filtration systems with each position detailed in Regulat ory Guide 1.52, Revision 2.

Article A - Introduction

The ESF filtration systems provided for CGS are designed to the General Design Criterion referenced in Article A. Those syst ems designed to meet the criterion are:

a. Standby gas treatment system, and
b. Control room emergency filtration system.

Article B - Discussion

The two systems are both classed as secondary systems and are not subject to the drywell environment during any design ba sis accident and are not subject to containment cooling sprays. Equipment design includes the ability to operate under all envir onmental conditions to which they can be subjected during accident conditions. The components of each control room

filter unit are as described in this article excep t that no demisters are required and HEPA filters are not provided downstream of the charcoal ad sorber section. The effects of aging, weathering, and relative humidity have been c onsidered in the design of these atmosphere cleanup systems, and they are tested periodica lly to verify required performance capability.

The effects of moisture on the ch arcoal adsorber media is minimi zed by the use of strip heaters for humidity control in the plenum of the charco al adsorbers section of the SGT system units and by periodically circulating h eated air through the control room emergency filtration units.

Adequate space and accessibility for personnel has been incorporated in filter unit design to

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.5-5 ensure maintainability and testability. Testing of filters is performed as specified in the

Technical Specifications.

Article C - Regulatory Position

Section 1.8.3 provides an analysis of the engineered safety feature air filtration systems with respect to the regulatory positions of Regulatory Guide 1.52, Revision 2.

6.5.1.3 Design Evaluation The SGT system is designed to pr event the exfiltration of contam inated air from the secondary containment following an accident or abnormal occurrence. All necessary equipment and surrounding structures are Seismic Category I.

The ESF buses supply power to the SGT system in the event of loss of normal ac pow er. Two fully redundant equipment trains separated by a missile wall are provided to ensure that a single failure does not impair or

preclude system operation.

6.5.1.4 Tests and Inspections The SGT system and its components are thoroughl y tested in a program consisting of the following classifications:

a. Predelivery tests and co mponent qualification tests, b. Postdelivery acceptance tests, and
c. Postoperation surveillance tests.

All SGT system fans were factory tested in accordance with AMCA Standard 210, "Air Moving and Conditioning Associati on Test Code for Air Moving De vices." Fans are started once per month to ensure operability.

Written test procedures establish acceptance criteria for all tests. Test re sults are recorded in performance records.

Predelivery tests were performed to meet the objectives of Regulatory Guide 1.52, Revision 2.

Postdelivery tests were performed to meet the objectives of Regulatory Guide 1.52, Revision 2 (using ANSI N510-1980). Postoperation tests are performed as specified in the Technical Specifications.

The HEPA filters are factory tested to a minimu m efficiency of 99.97% when measured with a 0.3-micron dioctyl phthalate (DOP) aerosol.

Tests are performed in accordance with ASME AG-1-1997. See Section 1.8.3 for comp liance by alternate approach to Regulatory Guide 1.52, Revision 2.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.5-6 In place leak testing of the HEPA filters is conducted in accordance with Regulatory Guide 1.52, Revision 2, as discu ssed in Section 1.8.3 , to demons trate a penetration and system bypass of less than 0.05%.

Charcoal media qualification tests meet the objec tives of Regulatory Guid e 1.52, Revision 2.

Charcoal samples laboratory test results are required within 31 days of removal.

Charcoal beds are leak tested in accordance with the Technical Specifications to demonstrate a penetration and system bypass of less than 0.05%.

Valves associated with the SGT system were factory leak tested, bubble tight, at a pressure differential of 2 psig. Valves were factory tested to ensure that valve st roke time, full close to full open, did not exceed 4 sec. The SGT system valves are periodically stroked as specified in the Technical Specificati ons to ensure operability.

6.5.1.5 Instrument ation Requirements

Additional information regarding the instrumentation and control system for SGT is contained in Section 7.3.1.

The instrumentation and controls are designed to meet the objec tives of Regulatory Guide 1.52, Revision 2.

The following instrumentation is provided for each SGT train in addition to that previously described:

a. An indicating differential pressure gauge is provided across each element (excluding heaters) in the SGT train. High differential pressure alarms in the main control room and is recorded by computer;
b. Relative humidity detectors with humidity indication in the main control room are located before the electric blast coil h eaters and the charcoal adsorber banks.

High humidity alarms in the main contro l room and is recorded by computer;

c. Thermostats with sensors on either side of an adsorber section control strip heaters in both adsorber plenum sections. Two thermostats in parallel energize the heaters on a temperature drop to 90°F.

Another thermostat deenergizes the heaters on a temperature rise to 110°F, with a manual reset thermostat cutting out the heaters on a temperature rise to 125°F; and

d. Temperature indication is provided in th e main control room for air entering the electric blast coil heater section and th e air leaving both banks of charcoal

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-09-023 6.5-7 filters. Temperature switch sensors are located on the downstream side of the prefilter and adsorber sections. A temperature rise to 250°F causes an alarm in

the main control room. The control room operator determines the cause of the temperature rise and can manually initiate the deluge spray system if necessary.

6.5.1.6 Materials

The housings and framing materials of the SGT filter units are fabricated of steel alloys and, as such, are nonflammable. The following is a list of the materials used in the various

components of the SGT filter units.

Demisters - The demister (moisture separator) section of each SGT unit consists of four assemblies of metal baffle plates and fi berglass separator pads. Each assembly has three fiberglass pads and one 4-in.-thick galvani zed metal moisture elim inator with a nominal face area of 16 x 20 in.

Prefilters - There are four 24 in. x 24 in. prefilters in each SGT unit. The prefilters are a pleated, U.L. Class 1, fiberglass m ounted on a metal retainer frame.

Absolute Particulate Filters - There are two banks of HEPA filters, one before and one after the charcoal adsorber section, on each SGT filter unit.

The HEPA filters consist of U.L. Class 1 fiberglass media in stainless steel frames with aluminum separators. There are four 24 in. x 24 in. filters in each filter bank.

Charcoal Adsorber Media - Each charcoal adsorber filter unit (two per SGT train) contains about 40 ft 3 of charcoal. The charco al used in the filters is a potassium iodide or triethylenediamine (TEDA) impr egnated coconut base charcoal. Typically, over 1000 lbs of charcoal are contained in each of the four filter units.

The only material in the SGT units that suppor ts combustion is the charcoal, which has a minimum ignition temperature of 330°C. The ch arcoal is provided with a deluge spray system. A 12-in.-thick concrete partition wall is provided between the two SGT units for fire protection.

6.5.2 CONTAINMENT

SPRAY SYSTEM

Design Bases

The containment spray system is capable of reducing containment pressure during the postaccident period of a LOCA through condensation of steam in the drywell and through cooling of the noncondensable gases in th e free volume above the suppression pool.

Containment spray is not required to prev ent overpressurization of the containment.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 6.5-8 The containment spray system also provides fo r fission product removal from the containment atmosphere. During a LOCA a substantial frac tion of the fission product release occurs after initial blowdown is complete. No credit is ta ken for suppression pool sc rubbing of the wetwell air space. A portion of the fission products releas ed from the reactor pressure vessel will be removed from the drywell atmosphere by drywell sprays. The drywell sprays are assumed to be initiated 15 minutes after the LOCA and turned off after one day.

6.5.3 FISSION

PRODUCT CONTROL SYSTEMS

The release of fission products to the environm ent in the event of a LOCA is controlled passively by the leaktight integrity of the primary and secondary containments and actively by the SGT system that filters the efflue nt from the secondary containment.

6.5.3.1 Primary Containment

Primary containment response to a design basis accident is discussed in Section

6.2.1. Figure

6.2-23 provides a basic layout of the primary containment.

In the event of a LOCA, oxygen concentration is controlled by the containment atmosphere control system which mixes, monitors, and controls the contai nment atmosphere as described in Section

6.2.5. Primary

containment purging is discussed in Section 6.2.1.

6.5.3.2 Secondary Containment

The SGT system is provided to control the re lease of fission products from the secondary containment to the environment. Secondary containment details are provided in Section 6.2.3 and SGT system details are provided in Section 6.5.1.

6.5.3.3 Standby Liquid Control (SLC) System

The SLC system is initiated as directed by proce dure to inject sodium pentaborate solution into the reactor pressure vessel when there is evidence of fuel da mage following a LOCA. Flow from the break will carry the boron to the s uppression pool. Maintaining the pool pH above 7.0 for the duration of the accident will minimi ze the re-evolution of gaseous iodine. See Section 9.3.5.

C OLUMBIA G ENERATING S TATION Amendment 62 F INAL S AFETY A NALYSIS R EPORT December 2013 Table 6.5-1 Standby Gas Treatment System Component Description Per Unit LDCN-12-018 6.5-9 Charcoal Filters Type Deep bed Quantity Design Flow (acfm)

Two in series

4800 Media Charcoal

Radioiodine removal Not less than 99.5% methyl iodide, tested at 30 C and 70% relative humidity Depth of each bed (in.)

4 Pressure drop, clean (in. wg)

2.0 Residence

time each train (sec.) 0.5 Ignition temperature, minimum ( C) 330 Iodine desorption temperature range ( F) 250-300 (low threshold)

Charcoal halogen loading, gm 67 (maximum theoretical loading for 30-day accident duration)

2577 (absorbing capability)

HEPA Filters Type High efficiency, dry Quantity Two banks, four filters each Capacity (acfm) 4800 each bank Media Fiberglass U.L. Class 1 Efficiency (%) 99.97 with 0.3-micron DOP aerosol Pressure drop, clean (in. wg) 1.0 nominal

Prefilter Type Medium efficiency, dry Quantity One bank, four filters Design Flow (acfm) 4800 Media Fiberglass Efficiency (%) 80-85%

Pressure drop, clean (in. wg)

0.5 nominal

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Table 6.5-1 Standby Gas Treatment System Component Descripti on Per Unit (Continued)

LDCN-05-009 6.5-10 Heater Type Electric,on-off

Quantity Two banks Capacity (kW) 20.7 (nominal each bank)

Stages Three

SGT System Exhaust Fans Type Centrifugal (with volume control)

Quantity Two 100% capacity units

Design Flow (acfm) 4800 Static Pressure (in. wg) 16 nominal Drive Direct

Motor (hp) 25 Demister Type Multiplebed

Quantity One bank, four filter units Design Flow (acfm) 4800 Media Metal baffle plate and fiberglass pads Pressure drop, clean (in. wg)

0.8 nominal

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDCN-00-088 6.6-1 6.6 INSERVICE INSPECTION OF ASME CODE CLASS 2 AND CLASS 3 COMPONENTS

The structural integrity of ASME Code Class 2 and 3 components is ma intained as required by the Inservice Inspection (ISI) Pr ogram in accordance with 10 CFR 50.55a. With the structural integrity of any component not conforming to the above requireme nts, the structural integrity will be restored to within its limits or the a ffected component will be isolated. For Class 2 components, isolation will be accomplished pr ior to increasing reactor coolant system temperature above 200 F. The Preservice Inspection Program Plan (Reference 5.2-6) addr e sses preservice inspections of Quality Groups B and C (ASME Boiler and Pressu re Vessel Code,Section III Class 2 and 3) components as required by Section XI of th e ASME Boiler and Pressure Vessel Code.

The Inservice Inspection Program (ISI) addresses inservice insp ections of Quality Groups B and C (ASME Boiler and Pressure Vessel Code ,Section III, Class 2 and 3) components as required by Section XI of the ASME Boiler and Pressure Vessel Code.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 6.7-1 6.7 MAIN STEAM ISOLATION VALVE LEAKAGE CONTROL SYSTEM

The main steam isolation valve leakage control system (MSLC) is isolated and deactivated.

The structural integrity of pi ping systems and components le ft in place is maintained.

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