ML15355A500

{{Adams | number = ML15355A500 | issue date = 12/21/2015 | title = Columbia, Final Safety Analysis Report, Amendment 63, Chapter 4 - Reactor | author name = | author affiliation = Energy Northwest | addressee name = | addressee affiliation = NRC/Document Control Desk, NRC/NRR | docket = 05000397 | license number = | contact person = | case reference number = GO2-15-159 | package number = ML15356A148 | document type = Final Safety Analysis Report (FSAR) | page count = 641 }}

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{{#Wiki_filter:COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Chapter 4 REACTOR TABLE OF CONTENTS

Section Page LDCN-02-022, 03-003 4-i 4.1 SUMMARY DESCRIPTION............................................................4.1-1 4.1.1 REACTOR VESSEL....................................................................4.1-1 4.1.2 REACTOR INTERN AL COMPONENTS..........................................4.1-1 4.1.2.1 Reactor Core...........................................................................4.1-2 4.1.2.1.1 General............................................................................... 4.1-2 4.1.2.1.2 Core C onfiguration.................................................................4.1-4 4.1.2.1.3 Fuel Assembly Description........................................................4.1-4

4.1.2.1.3.1 Fuel Rod...........................................................................4.1-4 4.1.2.1.3.2 Fuel Bundle........................................................................4.1-4 4.1.2.1.4 Assembly Support and Control Rod Location.................................4.1-5 4.1.2.2 Shroud...................................................................................4.1-5 4.1.2.3 Shroud Head and Steam Separators................................................4.1-6 4.1.2.4 Steam Dryer Assembly...............................................................4.1-6 4.1.3 REACTIVITY CO NTROL SYSTEMS..............................................4.1-7 4.1.3.1 Operation...............................................................................4.1-7 4.1.3.2 Description of Rods...................................................................4.1-7 4.1.3.3 Supplementary Reactivity Control..................................................4.1-9 4.1.4 ANALYSIS TECHNIQUES...........................................................4.1-9 4.1.4.1 Reactor Internal Components.......................................................4.1-9 4.1.4.1.1 MASS (Mechanical Analysis of Space St ructure)..............................4.1-10 4.1.4.1.1.1 Pr ogram Description.............................................................4.1-10 4.1.4.1.1.2 Program Version and Computer...............................................4.1-10 4.1.4.1.1.3 History of Use.....................................................................4. 1-10 4.1.4.1.1.4 Exte nt of Application.............................................................4.1-10 4.1.4.1.2 SNAP (M ULTISHELL).............................................................4.1-10 4.1.4.1.2.1 Pr ogram Description.............................................................4.1-10 4.1.4.1.2.2 Program Version and Computer...............................................4.1-10 4.1.4.1.2.3 History of Use.....................................................................4. 1-11 4.1.4.1.2.4 Exte nt of Application.............................................................4.1-11 4.1.4.1.3 GASP.................................................................................. 4.1-11 4.1.4.1.3.1 Pr ogram Description.............................................................4.1-11 4.1.4.1.3.2 Program Version and Computer...............................................4.1-11 4.1.4.1.3.3 History of Use.....................................................................4. 1-11 4.1.4.1.3.4 Exte nt of Application.............................................................4.1-11 4.1.4.1.4 NOHEAT............................................................................. 4.1-11 4.1.4.1.4.1 Pr ogram Description ............................................................. 4.1-11 COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Chapter 4 REACTOR

TABLE OF CONTENTS (Continued)

Section Page LDCN-02-000, 02-022, 03-003 4-ii 4.1.4.1.4.2 Program Version and Computer...............................................4.1-12 4.1.4.1.4.3 History of Use.....................................................................4. 1-12 4.1.4.1.4.4 Exte nt of Application.............................................................4.1-12 4.1.4.1.5 FINITE................................................................................ 4.1-12 4.1.4.1.5.1 Pr ogram Description.............................................................4.1-12 4.1.4.1.5.2 Program Version and Computer...............................................4.1-12 4.1.4.1.5.3 History of Use.....................................................................4. 1-12 4.1.4.1.5.4 Extent of Use......................................................................4. 1-12 4.1.4.1.6 DYSEA................................................................................ 4.1-12 4.1.4.1.6.1 Pr ogram Description.............................................................4.1-12 4.1.4.1.6.2 Program Version and Computer...............................................4.1-13 4.1.4.1.6.3 History of Use.....................................................................4. 1-13 4.1.4.1.6.4 Exte nt of Application.............................................................4.1-13 4.1.4.1.7 SHELL 5.............................................................................. 4.1-13 4.1.4.1.7.1 Pr ogram Description.............................................................4.1-13 4.1.4.1.7.2 Program Version and Computer...............................................4.1-13 4.1.4.1.7.3 History of Use.....................................................................4. 1-14 4.1.4.1.7.4 Exte nt of Application.............................................................4.1-14 4.1.4.1.8 HEATER.............................................................................. 4.1-14 4.1.4.1.8.1 Pr ogram Description.............................................................4.1-14 4.1.4.1.8.2 Program Version and Computer...............................................4.1-14 4.1.4.1.8.3 History of Use.....................................................................4. 1-14 4.1.4.1.8.4 Exte nt of Application.............................................................4.1-14 4.1.4.1.9 FAP-71 (Fatigue Analysis Program)............................................. 4.1-14 4.1.4.1.9.1 Pr ogram Description.............................................................4.1-14 4.1.4.1.9.2 Program Version and Computer...............................................4.1-14 4.1.4.1.9.3 History of Use.....................................................................4. 1-15 4.1.4.1.9.4 Extent of Use......................................................................4. 1-15 4.1.4.1.10 CREE P/PLAST.....................................................................4. 1-15 4.1.4.1.10.1 Program Description...........................................................4.1-15 4.1.4.1.10.2 Program Version and Computer.............................................4.1-15 4.1.4.1.10.3 History of Use...................................................................4. 1-15 4.1.4.1.10.4 Exte nt of Application...........................................................4.1-15 4.1.4.2 Fuel Rod Thermal Analysis.........................................................4.1-15 4.1.4.3 Reactor Systems Dynamics..........................................................4.1-15 4.1.4.4 Nuclear Engineering Analysis.......................................................4.1-16 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page LDCN-10-029 4-iii 4.1.4.5 Neutron Fluence Calculations ....................................................... 4.1-16 4.1.4.6 Thermal Hydraulic Calculations .................................................... 4.1-16 4.

1.5 REFERENCES

........................................................................... 4.1-16 

4.2 FUEL SYSTEM DESIGN ................................................................ 4.2-1

4.2.1 DESIGN

BASES ......................................................................... 4.2-1 4.2.1.1 Fuel System Damage Limits ......................................................... 4.2-1 4.2.1.1.1 Stress/Strain Limits ................................................................. 4.2-1 4.2.1.1.2 Fatigue Limits ....................................................................... 4.2-1 4.2.1.1.3 Fretting Wear Limits ............................................................... 4.2-1 4.2.1.1.4 Oxidation, Hydridi ng, and Corrosion Limits .................................. 4.2-1 4.2.1.1.5 Dimensi onal Change Limits ....................................................... 4.2-1 4.2.1.1.6 Internal Ga s Pressure Limit ....................................................... 4.2-1 4.2.1.1.7 Hydraulic Loads Limits ............................................................ 4.2-2 4.2.1.1.8 Control Rod Reactivity Limits .................................................... 4.2-2 4.2.1.2 Fuel Rod Failure Limits .............................................................. 4.2-2 4.2.1.2.1 Hydrid ing Limits .................................................................... 4.2-2 4.2.1.2.2 Claddi ng Collapse Limits .......................................................... 4.2-2 4.2.1.2.3 Fretting Wear Limits ............................................................... 4.2-2 4.2.1.2.4 Overheating of Cladding Lim its .................................................. 4.2-2 4.2.1.2.5 Overheating of Pellet Limits ...................................................... 4.2-2 4.2.1.2.6 Excessive Fuel Enthalpy Li mits .................................................. 4.2-2 4.2.1.2.7 Pellet-Cladding Interaction Limits ............................................... 4.2-2 4.2.1.2.8 Bursting Limits ...................................................................... 4.2-2 4.2.1.2.9 Mechanical Fracturing Limits .................................................... 4.2-3 4.2.1.3 Fuel Coolability Limits ............................................................... 4.2-3 4.2.1.3.1 Cladding Embrittlement Limits ................................................... 4.2-3 4.2.1.3.2 Violent Expulsi on of Fuel Limits ................................................ 4.2-3 4.2.1.3.3 Generalized Cl adding Melt Limits ............................................... 4.2-3 4.2.1.3.4 Fuel Rod Ballooning Limits ....................................................... 4.2-3 4.2.1.3.5 Structural De formation Limits .................................................... 4.2-3 4.2.2 DESCRIPTION AND DESIGN DRAWINGS ..................................... 4.2-3 4.2.2.1 Contro l Rods ........................................................................... 4.2-3 4.2.2.2 Velocity Limiter ....................................................................... 4.2-5 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page LDCN-10-029 4-iv 4.2.3 DESIGN EVALUATION .............................................................. 4.2-6 4.2.3.1 Fuel System Damage Evalua tion ................................................... 4.2-6 4.2.3.1.1 Stress/Strain Evaluatio n............................................................ 4.2-6 4.2.3.1.2 Fatigue Evaluati on .................................................................. 4.2-6 4.2.3.1.3 Fretting Wear Evaluation .......................................................... 4. 2-6 4.2.3.1.4 Oxidation, Hydriding, and Corrosion Evaluation ............................. 4.2-6 4.2.3.1.5 Dimensional Change Evaluation ................................................. 4.2-6 4.2.3.1.6 Internal Gas Pressure Evaluation ................................................. 4.2-6 4.2.3.1.7 Hydraulic Lo ad Evaluation ........................................................ 4.2-7 4.2.3.1.8 Control Rod Reactivity Evaluation .............................................. 4.2-7 4.2.3.2 Fuel Rod Failure ....................................................................... 4.2-7 4.2.3.2.1 Hydridi ng Evaluation .............................................................. 4. 2-7 4.2.3.2.2 Cladding Collapse Evalua tion .................................................... 4.2-7 4.2.3.2.3 Fretting Wear Evaluation .......................................................... 4. 2-7 4.2.3.2.4 Overheati ng of Cladding Evaluation ............................................. 4.2-7 4.2.3.2.5 Overheating of Pellet Limits ...................................................... 4.2-7 4.2.3.2.6 Excessive Fuel Enthalpy Evaluation ............................................. 4.2-7 4.2.3.2.7 Pellet-Cladding Interaction Evaluation .......................................... 4.2-8 4.2.3.2.8 Bursti ng Evaluation ................................................................. 4.2-8 4.2.3.2.9 Mechanical Fr acturing Evaluation ............................................... 4.2-8 4.2.3.3 Fuel C oolability Evaluation .......................................................... 4.2-8 4.2.3.3.1 Cladding Embrittlement Evaluation ............................................. 4.2-8 4.2.3.3.2 Violent Expulsion of Fuel Evaluation ........................................... 4.2-8 4.2.3.3.3 Generalized Cl adding Melt Eval uation .......................................... 4.2-8 4.2.3.3.4 Fuel Rod Ba llooning Evalua tion ................................................. 4.2-8 4.2.3.3.5 Structural De formation Evaluation .............................................. 4.2-9 4.2.4 TESTING, INSPECTION, AND SURVEILLANCE PLANS .................. 4.2-9 4.2.4.1 Fuel Testing, Insp ection, and Surv eillance ....................................... 4.2-9 4.2.4.2 Online Fuel Sy stem Monitoring .................................................... 4.2-9 4.2.4.3 Post-Irradiation Surveillance ........................................................ 4.2-9 4.2.4.4 Channel Manage ment Program ..................................................... 4.2-10 4.

2.5 REFERENCES

........................................................................... 4.2-11 

4.3 NUCLEAR DESIGN ...................................................................... 4.3-1

4.3.1 DESIGN

BASES ......................................................................... 4.3-1 4.3.1.1 Reactivity Basis ........................................................................ 4.3-1 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page LDCN-15-011 4-v 4.3.1.2 Overpow er Bases ...................................................................... 4.3-1

4.3.2 DESCRI

PTION .......................................................................... 4.3-1 4.3.2.1 Nuclear Desi gn Descripti on ......................................................... 4. 3-1 4.3.2.2 Power Di stribution .................................................................... 4.3-1 4.3.2.2.1 Power Distribution Calcula tions.................................................. 4.3-1 4.3.2.2.2 Power Distribu tion Measurements ............................................... 4.3-1 4.3.2.2.3 Power Distri bution Accuracy ..................................................... 4.3-1 4.3.2.2.4 Power Di stribution Anomalies .................................................... 4.3-1 4.3.2.3 Reactivity Coefficients ............................................................... 4.3-2 4.3.2.4 Control Requirements ................................................................ 4. 3-2 4.3.2.4.1 Shutdown Reactivity ................................................................ 4.3-2 4.3.2.4.2 Reactivity Variations ............................................................... 4.3-2 4.3.2.5 Control Rod Patterns and Reactivity Worths ..................................... 4.3-2 4.3.2.6 Criticality of React or During Refu eling ........................................... 4.3-3 4.3.2.7 Stability ................................................................................. 4.3-3 4.3.2.7.1 Xenon Tr ansients ................................................................... 4.3-3 4.3.2.7.2 Thermal H ydraulic Stability ...................................................... 4.3-3 4.3.2.8 Vessel Irradiations ..................................................................... 4.3-3 4.3.3 ANALYTICAL METHODS ........................................................... 4.3-4 4.3.4 CHAN GES ................................................................................ 4.3-5 4.

3.5 REFERENCES

........................................................................... 4.3-5 

4.4 THERMAL-HYDRAULIC DESIGN ................................................... 4.4-1

4.4.1 DESIGN

BASES ......................................................................... 4.4-1 4.4.1.1 Safety Design Bases ................................................................... 4.4-1 4.4.1.2 Requirements for St eady-State Cond itions ........................................ 4.4-1 4.4.1.3 Requirements for Anticipated Operational Occurrences (AOOs) ............. 4.4-1 4.4.1.4 Summary of Design Bases ........................................................... 4. 4-1 4.4.2 DESCRIPTION OF THERMAL-HYDRAULIC DESIGN OF REACTOR CORE ....................................................................... 4.4-1 4.4.2.1 Summary Comparison ................................................................ 4.4-1 4.4.2.2 Critical Power Ratio .................................................................. 4.4-2 4.4.2.3 Linear Heat Generation Rate ........................................................ 4.4-2 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page LDCN-15-011, 10-004 4-vi 4.4.2.4 Void Fracti on Distribution ........................................................... 4.4-2 4.4.2.5 Core Coolant Flow Distri bution and Orifici ng Pattern ......................... 4.4-2 4.4.2.5.1 Flow Distribution Data Comparison ............................................. 4.4-2 4.4.2.5.2 Effect of Channel Flow Uncertainties on the MCPR Uncertainty .......... 4.4-2 4.4.2.6 Core Pressure Drop and Hydraulic Loads ........................................ 4.4-3 4.4.2.7 Correlation and Physical Data ...................................................... 4.4-3 4.4.2.8 Thermal Effects of Operational Transients ....................................... 4.4-3 4.4.2.9 Uncertainties in Estimates ........................................................... 4.4-3 4.4.2.10 Flux Tilt Considerations ............................................................ 4.4-4 4.4.3 DESCRIPTION OF THE TH ERMAL AND HYDRAULIC DESIGN OF THE REACTOR COOL ANT SYSTEM ........................................ 4.4-4 4.4.3.1 Plant Confi guration Data ............................................................. 4.4-4 4.4.3.1.1 Reactor Coolant System Configuration ......................................... 4.4-4 4.4.3.1.2 Reactor Coolant System Thermal Hydraulic Data ............................ 4.4-4 4.4.3.1.3 Reactor Coolant Sy stem Geometric Data ....................................... 4.4-4 4.4.3.2 Operating Rest rictions on Pu mps ................................................... 4.4-4 4.4.3.3 Power-Flow Operating Map ......................................................... 4. 4-5 4.4.3.3.1 Limits for Normal Opera tion ..................................................... 4.4-5 4.4.3.3.2 Regions of the Power-Flow Map ................................................. 4.4-5 4.4.3.3.3 Design Features fo r Power-Flow C ontrol ...................................... 4.4-5 4.4.3.4 Temperature-Po wer Operating Map ............................................... 4.4-7 4.4.3.5 Load-Following Characteris tics ..................................................... 4.4-7 4.4.3.6 Thermal and Hydraulic Characteristics Summary Table ....................... 4.4-7 4.4.4 EVAL UATION .......................................................................... 4.4-7 4.4.4.1 Bypass Flow ............................................................................ 4.4-7 4.4.4.2 Thermal Hydr aulic Stability Analysis .............................................. 4.4-7 4.4.5 TESTING AND VERIFICATION ................................................... 4. 4-8 4.4.6 INSTRUMENTATIO N REQUIREMENTS ........................................ 4.4-8 4.4.6.1 Loose Parts ............................................................................. 4.4-8 4.

4.7 REFERENCES

........................................................................... 4.4-8 

4.5 REACTOR MATERIALS ................................................................ 4.5-1 4.5.1 CONTROL ROD SYSTEM STRUCTURAL MATERIALS .................... 4.5-1 4.5.1.1 Material Specifications ............................................................... 4.5-1 4.5.1.2 Special Materials ...................................................................... 4.5-3 4.5.1.3 Processes, Insp ections and Te sts ................................................... 4.5-3 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page 4-vii 4.5.1.4 Control of Delta Ferrite Content .................................................... 4.5-4 4.5.1.5 Protection of Materials During Fabrication, Shipping, and Storage.......... 4.5-4 4.5.2 REACTOR INTERN AL MATERIALS

............................................. 4.5-5 4.5.2.1   Material Specifications ............................................................... 4.5-5 4.5.2.2   Controls on Weldi ng ..................................................................

4.5-7 4.5.2.3 Nondestructive Examination of Wrought Seamless Tubular Products ....... 4.5-7 4.5.2.4 Fabrication and Processing of Austenitic Stainless Steel - Regulatory Guide Conformance ................................................................... 4.5-8 4.5.2.5 Contamination, Protection, and Cleaning of Austenitic Stainless Steel ...... 4.5-8 4.5.3 CONTROL ROD DRIVE HOUSING SUPPORTS ................................ 4.5-9 4.6 FUNCTIONAL DESIGN OF REACTIVITY CONTROL SYSTEMS ........... 4.6-1 4.6.1 INFORMATION FOR THE CONTROL ROD DRIVE SYSTEM ............. 4.6-1 4.6.1.1 Control Rod Dr ive System De sign ................................................. 4.6-1 4.6.1.1.1 Desi gn Bases ......................................................................... 4.6-1 4.6.1.1.1.1 Sa fety Design Bases .............................................................. 4.6-1 4.6.1.1.1.2 Power Gene ration Design Basis ............................................... 4.6-1 4.6.1.1.2 Desc ription ........................................................................... 4.6-1 4.6.1.1.2.1 Control Rod Drive Mechanisms ............................................... 4.6-2 4.6.1.1.2.2 Drive Components ............................................................... 4.6-3 4.6.1.1.2.2.1 Dr ive Piston ..................................................................... 4.6-3 4.6.1.1.2.2.2 I ndex Tube ...................................................................... 4.6-3 4.6.1.1.2.2.3 Collet Assembly ................................................................ 4.6-3 4.6.1.1.2.2.4 Pi ston Tube ..................................................................... 4.6-4 4.6.1.1.2.2.5 St op Piston ...................................................................... 4.6-4 4.6.1.1.2.2.6 Flange a nd Cylinder Assembly .............................................. 4.6-5 4.6.1.1.2.2.7 Lock Plug ....................................................................... 4.6-5 4.6.1.1.2.3 Materials of Construction ....................................................... 4.6-5 4.6.1.1.2.3.1 I ndex Tube ...................................................................... 4.6-6 4.6.1.1.2.3.2 C oupling Spud .................................................................. 4.6-6 4.6.1.1.2.3.3 Collet Fingers .................................................................. 4.6-6 4.6.1.1.2.3.4 Seals and Bushings ............................................................ 4.6-6 4.6.1.1.2.3.5 Summary ........................................................................ 4.6-6 4.6.1.1.2.4 Control Rod Dr ive Hydraulic System ........................................ 4.6-7 4.6.1.1.2.4.1 Hydrau lic Requireme nts ...................................................... 4.6-7 4.6.1.1.2.4.2 System Description ............................................................ 4. 6-8 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page 4-viii 4.6.1.1.2.4.2.1 Supply Pump ................................................................. 4.6-8 4.6.1.1.2.4.2.2 Accumulato r Charging Pressure .......................................... 4.6-9 4.6.1.1.2.4.2.3 Drive Water Pressure ....................................................... 4.6-9 4.6.1.1.2.4.2.4 Cooling Water Header ...................................................... 4.6-10 4.6.1.1.2.4.2.5 Scram Discharge Volume .................................................. 4.6-10 4.6.1.1.2.4.3 Hydraulic Control Units ...................................................... 4.6-11 4.6.1.1.2.4.3.1 Insert Drive Valve ........................................................... 4.6-12 4.6.1.1.2.4.3.2 Insert Exhaust Valve ........................................................ 4.6-12 4.6.1.1.2.4.3.3 Withdr aw Drive Valve ..................................................... 4.6-12 4.6.1.1.2.4.3.4 Withdraw Exhaust Valve ................................................... 4.6-12 4.6.1.1.2.4.3.5 Speed Control Units ........................................................ 4.6-12 4.6.1.1.2.4.3.6 Scram Pilot Valves .......................................................... 4.6-12 4.6.1.1.2.4.3.7 Scra m Inlet Valv e ........................................................... 4.6-12 4.6.1.1.2.4.3.8 Scram Exhaust Valve ....................................................... 4.6-12 4.6.1.1.2.4.3.9 Scra m Accumulator ......................................................... 4.6-13 4.6.1.1.2.5 Control Rod Drive System Operation ......................................... 4.6-13 4.6.1.1.2.5.1 Rod Insertion ................................................................... 4.6-13 4.6.1.1.2.5.2 Rod Withdrawal ................................................................ 4.6-13 4.6.1.1.2.5.3 Scram ............................................................................ 4.6-14 4.6.1.1.2.6 Instru mentation ................................................................... 4.6-15 4.6.1.2 Control Rod Drive Housing Supports ............................................. 4.6-15 4.6.1.2.1 Safety Objective ..................................................................... 4.6-15 4.6.1.2.2 Safety Design Bases ................................................................ 4.6-15 4.6.1.2.3 Desc ription ........................................................................... 4. 6-15 4.6.2 EVALUATION OF THE CO NTROL ROD DRIVES ............................ 4.6-16 4.6.2.1 Control Rods ........................................................................... 4.6-17 4.6.2.1.1 Materials Adequacy Throughout Design Lifetime ............................ 4.6-17 4.6.2.1.2 Dimens ional and Tolerance Analysis ............................................ 4.6-17 4.6.2.1.3 Thermal Analysis of the Tendency to Warp ................................... 4.6-17 4.6.2.1.4 Forces fo r Expulsion ............................................................... 4.6-17 4.6.2.1.5 Functional Failure of Critical Components ..................................... 4.6-18 4.6.2.1.6 Precluding Excessive Rates of Reactivity Addition ........................... 4.6-18 4.6.2.1.7 Effect of Fuel Rod Failure on Control Rod Channel Clearances ........... 4.6-18 4.6.2.1.8 Mechanical Damage ................................................................ 4.6-18 4.6.2.1.9 Evaluation of Control Rod Velocity Limiter ................................... 4.6-19 4.6.2.2 Control Rod Drives ................................................................... 4.6-19 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page 4-ix 4.6.2.2.1 Evalua tion of Scram Time ......................................................... 4.6-19 4.6.2.2.2 Analysis of Malfunction Relating to Rod Withdrawal ........................ 4.6-19 4.6.2.2.2.1 Drive Housing Fails at Attachment Weld .................................... 4.6-19 4.6.2.2.2.2 Rupture of Hydraulic Line(s) to Drive Housing Flange ................... 4.6-20 4.6.2.2.2.2.1 Pressure-U nder Line Break

.................................................. 4.6-20 4.6.2.2.2.2.2   Pressure-O ver Line Break .................................................... 4.6-20 4.6.2.2.2.2.3   Simultaneous Breakage of the Pressure

-Over and Pressure-Under Lines ............................................................................. 4.6-21 4.6.2.2.2.3 All Drive Flange Bolts Fail in Tension ....................................... 4.6-21 4.6.2.2.2.4 Weld Joining Flange to Housing Fails in Tension .......................... 4.6-22 4.6.2.2.2.5 Hous ing Wall Ruptures .......................................................... 4.6-23 4.6.2.2.2.6 Flange Plug Blows Out .......................................................... 4.6-23 4.6.2.2.2.7 Ball Check Va lve Plug Blows Out ............................................ 4.6-24 4.6.2.2.2.8 Drive/Coo ling Water Pressure Control Valve Failure ..................... 4.6-24 4.6.2.2.2.9 Ball Check Valve Fails to Close Passage to Vessel Ports ................. 4.6-25 4.6.2.2.2.10 Hydrau lic Control Unit Valv e Failures ..................................... 4.6-25 4.6.2.2.2.11 Collet Fingers Fail to Latch ................................................... 4.6-26 4.6.2.2.2.12 Withdrawal Speed Control Valve Failure .................................. 4.6-26 4.6.2.2.2.13 Slow or Partial Loss of Air to the Scram Discharge Valves ............ 4.6-26 4.6.2.2.3 Scram Reliability .................................................................... 4.6-27 4.6.2.2.4 Control Rod Supp ort and Operation ............................................. 4.6-27 4.6.2.3 Control Rod Drive Housing Supports ............................................. 4.6-27 4.6.3 TESTING AND VERIFICATION OF THE CONTROL ROD DRIVES ..... 4.6-28 4.6.3.1 Control Rod Drives ................................................................... 4.6-28 4.6.3.1.1 Testing and Inspection ............................................................. 4.6-28 4.6.3.1.1.1 Devel opment Tests ............................................................... 4.6-28 4.6.3.1.1.2 Factory Quality Control Tests .................................................. 4.6-28 4.6.3.1.1.3 Opera tional Tests ................................................................. 4.6-29 4.6.3.1.1.4 Accepta nce Tests ................................................................. 4.6-30 4.6.3.1.1.5 Surveillance Tests ................................................................ 4.6-30 4.6.3.1.1.6 Functi onal Tests .................................................................. 4.6-31 4.6.3.2 Control Rod Drive Housing Supports ............................................. 4.6-32 4.6.4 INFORMATION FOR COMBINED PERFORMANCE OF REACTIVITY CONTROL SYSTEMS .................................................................. 4.6-32 4.6.4.1 Vulnerability to Co mmon Mode Failures ......................................... 4. 6-32 4.6.4.2 Accidents Taking Credit for Multiple Reactivity Systems ..................... 4.6-33 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page 4-x 4.6.5 EVALUATION OF COMBINED PERFORMANCE ............................. 4.6-33 4.6.6 ALTERNATE ROD INSERTION SYSTEM ....................................... 4.6-33 4.6.6.1 System Description .................................................................... 4.6-33 4.6.6.2 Alternate R od Insertion Redundancy ............................................... 4.6-34 4.

6.7 REFERENCES

........................................................................... 4.6-34 

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR LIST OF TABLES

Number Title Page 4-xi 4.2-1 Control Rod Pa rameters ....................................................... 4.2-15 4.3-1 Summary of Neutron Fluence Results ....................................... 4.3-7 4.3-2 Reload Fuel Neutr onic Design Values ...................................... 4.3-8

4.3-3 Neutronic Desi gn Values ...................................................... 4.3-9

4.4-1 Thermal and Hydraulic Design Characteristics of the Reactor Core ..................................................................... 4.4-11

4.4-2 Mixed Core Thermal Hydraulic Analysis Results ......................... 4.4-12

4.4-3 Reactor Coolant System Geometric Data ................................... 4.4-13

4.4-4 Lengths and Sizes of Safe ty Injection Lines ................................ 4.4-14

4.4-5 Core Pressure Drop and Leakage Flow Results for Core Configurations ................................................................... 4.4-15

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR LIST OF FIGURES

Number Title 4-xii 4.1-1 Steam Separator 4.1-2 Steam Dryer Panel

4.1-3 Columbia Generating Stati on Cycle 19 Reference Loading Map

4.2-1.1 Original Equipment (OEM) Control Rod Blade Assembly

4.2-1.2 Duralife 215 Control Rod Blade Assembly

4.2-1.3 Marathon Control Rod Blade Assembly

4.2-1.4 Marathon Control R od Blade Absorber Details

4.2-1.5 Marathon Control Rod Blade Absorber Placement

4.2-2 Control Rod Velocity Limiter

4.3-1 Core Layout and Vessel Internal Components

4.4-1 Power-Flow Operating Map, Two Loop Operation

4.4-2 Power-Flow Operating Map, Single Loop Operation

4.6-1 Control Rod to C ontrol Rod Drive Coupling

4.6-2 Control Rod Drive Unit

4.6-3 Control Rod Drive Unit (Schematic)

4.6-4 Model 7RDB144B or C C ontrol Rod Drive (Breakdown)

4.6-5 Control Rod Drive Hydrau lic System (Sheets 1 and 2)

4.6-6 Control Rod Drive System Pr ocess Diagram (Sheets 1 through 3)

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR LIST OF FIGURES (Continued)

Number Title 4-xiii 4.6-7 Control Rod Drive Hydraulic Control Unit 4.6-8 Control Rod Drive Housing Support

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-1 Chapter 4 REACTOR 4.1 SUMMARY DESCRIPTION

This section was prepared using the licensing topical report, "General Electric Standard Application for Reactor Fuel" (GESTAR II) Reference 4.1-1, GESTAR II compliance documents (References 4.1-4 and 4.1-5), the cy cle-specific design report (Reference 4.1-2) and the "Fuel Bundle Informati on Report" (Reference 4.1-3).

The reactor assembly consists of the reactor vessel, internal components of the core, shroud, steam separator and dryer assemblies, and jet pumps. Also included in the reactor assembly are the control rods, control rod drive housings, and the cont rol rod drives. Figure 5.3-5 shows the arrangement of reacto r assembly components. A summary of the important design and performance characterist ics is given in Section 1.3. Loading conditions for reactor assembly components are specified in Section 3.9. The core load varies for each cycle and is shown in Reference 4.1-2. 4.1.1 REACTOR VESSEL

The reactor vessel design and desc ription are discussed in Section 5.3. 4.1.2 REACTOR INTERNAL COMPONENTS

The major reactor internal components are the core (fuel, channels, control blades, and instrumentation), the core support structure (inc luding the shroud, top guide and core plate), the shroud head and steam sepa rator assembly, the steam dr yer assembly, the feedwater spargers, the core spray spargers, and the jet pumps. Except for the Zi rcaloy in the reactor core, these reactor internals are stainless steel or other corrosion resistant alloys. All major internal components of the vessel can be removed except the jet pump diffusers, the jet pump risers, the shroud, the co re spray lines, spargers, and the fe edwater sparger. The removal of the steam dryers, shroud head and steam sepa rators, fuel assemblies, in-core assemblies, control rods, orificed fuel supports, and control rod guide tubes can be accomplished on a routine basis. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-2 4.1.2.1 Reactor Core

4.1.2.1.1 General

The reactor core is composed of fuel assemblies manufactured by Global Nuclear Fuel (GNF).

A number of important features of the BWR core design are summarized in the following paragraphs:

a. The BWR core mechanical design is ba sed on conservative app lication of stress limits, operating experience, and experimental test results. The moderate pressure levels characteristics of a direct cycl e reactor (approximately 1035 psia) result in mode rate cladding temperatures and stress levels;

b. The low coolant saturation temperature, high heat transfer coefficients, and neutral water chemistry of the BWR are significant, advantag eous factors in minimizing Zircaloy temperature and associated temperature-dependent corrosion and hydride buildup; The relatively uniform fuel cladding te mperatures throughout the core minimize migration of the hydrides to cold cla dding zones and reduce thermal stresses;

c. The basic thermal and mechanical cr iteria applied in th e design have been proven by irradiation of statistically significant quantities of fuel. The design heat transfer rates and lin ear heat generation rates ar e similar to values proven in fuel assembly irradiation;

d. The design power distribution used in sizing the core represents a worst expected state of operation;

e. The thermal margin analyses ensure that more than 99.9% of the fuel rods in the core are expected to avoid boiling transition for the most severe anticipated operational occurrences described in Chapter 15

. The possibility of boiling transition occurring during normal reactor operation is insignificant; and

f. Because of the large ne gative moderator density coef ficient of reactivity, the BWR has a number of inherent advantages. These are th e uses of coolant flow for load following, the inherent self-flatt ening of the radial power distribution, the ease of control, the spatial xenon stability, and the ability to override xenon to follow load.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 4.1-3 Boiling water reactors do not usually have inst ability problems due to xenon. This has been demonstrated by special tests which were conducted on operating BWRs and by calculations. Xenon transients are highly damped in a BWR due to the large negative power coefficient of reactivity (Reference 4.1-7). Columbia Generating Station (CGS ) has installed a stability de tect and suppress system to ensure hydrodynamic stability while operating in re gions susceptible to instability. Stability system limits are specified in the Technical Specifications and in the Core Operating Limits Report. Important features of the reactor core arrangement are as follows:

a. The original bottom-entry cruc iform control rods consist of B 4C in stainless steel tubes surrounded by a stainless steel sheath;

b. The bottom-entry cruciform Duralife 215 control rods consist of 18 high-purity stainless steel tubes at each wing filled with boron-carbide and three hafnium rods at the edge of each wing and a hafnium plate at the top;

c. The bottom-entry cruciform Marathon control rods consist of 17 high-purity stainless steel tubes in each wing. Eleven of the tubes are filled with boron-carbide, two of the tubes are partially filled with boron-carbide and four tubes are filled with hafnium rods (thr ee at the outer edge of each wing and one at the center of the wing). See Figure 4.2-1.5 for details;

d. The in-core location of the startup and power range instruments provides coverage of the large reactor core and provides an acceptable signal-to-noise

ratio and neutron-to-gamma ratio. All in-core instrument leads enter from the bottom and the instruments are in se rvice during refueling. In-core instrumentation is furthe r discussed in Sections 7.6.1.4 and 7.7.1.6;

e. As shown by experience obtained at other plants, the operator, utilizing the in-core flux monitor system, can maintain the desired power distribution within a large core by proper control rod scheduling;

f. The Zircaloy-2 and 4 channe ls provide a fixed flow pa th for the boiling coolant, serve as a guiding surface for the cont rol rods, and protect the fuel during handling operations;

g. The mechanical reactivity control perm its criticality checks during refueling and provides maximum plant safety. The core is designed to be subcritical at any time in its operating history with any one control rod fully withdrawn; and

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-4 h. The selected control rod pitch represents a practical value of individual control rod reactivity worth and allows ample clearance below the pressure vessel between control rod drive mechanisms for ease of maintenance and removal.

4.1.2.1.2 Core Configuration

The reactor core is arranged as an upright circular cylinder c ontaining a large number of fuel cells and is located within the reactor vessel. The coolant flows upward through the core. The BWR core is composed of essentially two components: fuel assemblies and control rods. The General Electric Company (GE) control rod mechani cal configuration (see Figure 4.2-1 ) is basically the same as used in all GE BWRs.

4.1.2.1.3 Fuel Assembly Description

The GNF reload fuel asse mblies are GNF2 (Reference 4.1-4) and GE14 (Reference 4.1-5). 4.1.2.1.3.1 Fuel Rod. A fuel rod consists of UO 2 pellets and a Zircaloy-2 cladding tube. A fuel rod is made by stacking pellets into a Zircaloy-2 cladding tube , which is sealed by welding Zircaloy end plugs in each end of the tube. The GNF fuel rods are pressurized to 10 atmospheres (References 4.1-4 and 4.1-5). The BWR fuel rod is designed as a pressure vessel. The ASME Boiler and Pressure Vessel (B&PV) Code, Section III, is used as a guide in the mechanical design and stress analysis of the fuel rod.

The rod is designed to withstand the applied loads, both external and internal. The fuel pellet is sized to provide sufficient vol ume within the fuel tube to accommodate differential expansion between fuel and clad. Overa ll fuel rod design is conservativ e in its accommodation of the mechanisms affecting fuel in a BWR environmen

t. Fuel rod design bases are discussed in more detail in Section 4.2.1.

4.1.2.1.3.2 Fuel Bundle. The fuel bundle has two important design features:

a. The bundle design places minimum external forces on a fuel rod; each fuel rod is free to expand in the axial direction, and

b. The unique structural design permits the removal and replacement, if required, of individual fuel rods.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-5 The fuel bundles are designed to meet all the criteria for core performance and to provide ease of handling. Selected fuel rods in each bundl e differ from the others in uranium enrichment.

This arrangement produces more uniform power production acr oss the fuel bundle and thus allows a significant reduction in the amount of heat transfer su rface required to satisfy the design thermal limitations.

The GNF reload bundle contains 92 fuel rods a nd 2 large central water rods, all in a 10 x 10 array. 4.1.2.1.4 Assembly Support and Control Rod Location

Some peripheral fuel assemblies are supported by the core plate. Otherwise, individual fuel assemblies in the core rest on fuel support pieces mounted on top of the cont rol rod guide tubes. Each guide tube, with its fuel support piece, bears the we ight of four a ssemblies and is supported by a control rod drive penetration nozzl e in the bottom head of the reactor vessel. The core plate provides lateral support and guidan ce at the top of each control rod guide tube.

The top guide, mounted inside the shroud, provid es lateral support and guidance for each fuel assembly. The reactivity of the core is controlled by cruciform control rods and their associated mechanical hydraulic drive system. The control rods occupy alternate spaces between fuel assemblies. Each independent drive enters the core from the bottom and can accurately position its associated control rod during normal operation and yet insert the control rod in less than 7 sec during the scram mode of operation. Bottom entry allows optimum power shaping in the core, ease of refu eling, and convenient drive maintenance.

4.1.2.2 Shroud

The shroud is a cylindri cal, stainless-steel stru cture which surrounds the core and provides a barrier to separate the upward flow through the core from th e downward flow in the annulus and also provides a floodable volume in the unlikely event of an accident which would otherwise drain the reactor pressure vessel. A flange at the top of the shroud mates with a flange on the shroud head and st eam separators. The upper cyli ndrical wall of the shroud and the shroud head form the core discharge plenum . The jet pump discharge diffusers penetrate the shroud support below the core elevation to in troduce the coolant to the inlet plenum. To prevent direct flow from the in let to the outlet nozzl es of the recirculation loops, the shroud support is welded to the vessel wall. The shroud support is designed to support and locate the jet pumps, core support structure, and some peripheral fuel assemblies.

Mounted inside the upper shroud cylinder in the space between the top of the core and the upper shroud flange are the core spray spargers with spray nozzles fo r injection of cooling COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-6 water. The core spray spargers and nozzles do not interfere with the installation or removal of fuel from the core.

4.1.2.3 Shroud Head and Steam Separators

The shroud head consists of a fl ange and dome onto which is we lded an array of standpipes,

with a steam separator located at the top of each standpipe . The shroud head mounts on the flange at the top of the cylinde r and forms the cover of the core discharge plenum region. The joint between the shroud head and shroud flange does not require a gasket or other replacement sealing technique. The fixed ax ial flow type steam separators have no moving parts and are made of stainless steel.

In each separator, the steam-wat er mixture rising from the st andpipe impinges on vanes which give the mixture a spin to establish a vortex wherein the centrifugal forces separate the steam from the water. Steam leaves the separator at the top and passes into the wet steam plenum below the dryer. The separated water exits from the lower end of the separator and enters the pool that surrounds the standpipes to enter the downcomer annulus. An internal steam separator diagram is shown in Figure 4.1-1 . For ease of removal, the shroud head is bolted to the shroud top flange by long shroud head bolts that extend above the sepa rators for easy access during re fueling. The shroud head is guided into position on the shroud via guide rods on the inside of the vessel and locating pins located on the shroud head . The objective of the shroud head bolt design is to provide direct access to the bolts during reactor refueling ope rations with minimum-depth underwater tool manipulation during the removal and installation of the assemblies.

4.1.2.4 Steam Dryer Assembly

The steam dryer assembly is m ounted in the reactor vessel a bove the shroud head and forms the top and sides of the wet steam plenum. Ve rtical guide rods on the inside of the vessel provide alignment for the dryer a ssembly during installation. The dryer assembly is supported by pads extending from the vessel wall and is locked into position during operation by the reactor vessel top head. Steam from the separators flows upward into the dryer assembly. The steam leaving the top of the dryer assembly flows into vessel stea m outlet nozzles which are located alongside the steam dryer assembly. Moisture is removed by the dryer vanes and flows first through a system of troughs and pipes to the pool surrounding the separators and then into the downcomer annulus between the core shroud and reactor vessel wall. The diagram of a typical steam dryer panel is shown in Figure 4.1-2 . COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-022 4.1-7 4.1.3 REACTIVITY CONTROL SYSTEMS

4.1.3.1 Operation

The control rods perform dual functions of power distribution sh aping and reactivity control. Power distribution in the core is controlled during operation of the reactor by manipulation of selected patterns of rods. The rods, which enter from the bottom of the near-cylindrical reactor core, are positioned in such a manner to counter-balance steam voids in the top of the core and effect signifi cant power flattening.

These groups of control elements, used for power flattening, experi ence a somewhat higher duty cycle and neutron exposure than the other rods in the control system.

The reactivity control function requires that all rods be available for either reactor "scram" (prompt shutdown) or reactivit y regulation. Because of this, the control elements are mechanically designed to withstand the dynamic forces resulting from a scram. They are connected to bottom-mounted, hydraulically actuated drive mechanisms which allow either axial positioning for reactivity regulation or rapid scram insertion. The design of the rod-to-drive connection permits each blade to be attached or detached from its drive without disturbing the remainder of the control system . The bottom-mounted dr ives permit the entire control system to be left intact and operable for tests with the reactor vessel open.

4.1.3.2 Description of Rods

The cruciform shaped control rods contain 76 stai nless steel tubes (19 tubes in each wing of the cruciform) filled with vibrati on compacted boron-carbide powder. The tubes are seal welded with end plugs on either end. Stainless steel balls are used to separate the tubes into individual compartments. The stainless steel balls are held in position by a slight crimp in the tube. The individual tubes act as pressure vessels to contain the helium gas released by the boron-neutron capture reaction.

The tubes are held in a cruciform array by a stainless steel sheath exte nding the full length of the tubes. A top handle, shown in Figure 4.2-1 , aligns the tubes and provides structural rigidity at the top of the control rod. Rolle rs, housed in the handl e, provide guidance for control rod insertion and withdrawal. A bottom casting is also used to provide structural rigidity and contains positioning rollers and a parachute-shaped velocity limiter. The handle and lower casting are welded into a single structure by means of a small cruciform post located in the center of the control rod. A steel stiffener is located approximate ly at the midspan of each cruciform wing. The control rods can be positioned at 6-in. step s and have a nominal withdrawal and insertion speed of 3 in./sec.

The foregoing description of the c ontrol rods applies to the design of the original control rods. There have been two different replacement control rods used, Du ralife 215 and Marathon

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-022 4.1-8 control rods. These replacement rods have design changes that increase the neutron absorption and make other material property improvements. The newer control rods are similar to and are fully interchangeable with th e original control rod assemblies and are compatible with the existing nuclear steam s upply system hardware.

The Duralife 215 control rods differ from the previ ous control rods in that a hafnium absorber plate is used at the top of each cruciform section, hafnium absorber ro ds replace several of the boron carbide absorber rods on the periphery of each cruciform section, and the stainless steel stiffener is removed from each wing. There ar e 21 absorber rods in each wing, of which 18 are stainless-steel tubes contai ning boron carbide and three ar e hafnium rods. The outside diameter remains the same. The length of the absorber column in these rods has been reduced from 143 in. to 137 in. to accommodate the t op 6-in.-high hafnium plate. The increased volume of neutron absorber material increases the relative reactivit y worth in the cold condition and increases the nuclear lifetime.

The Marathon control rod blades are an improv ed version of the Duralife 215 control blades and have the absorber and sheath arrangement replaced with an array of square tubes, which results in reduced weight and in creased absorber volume. The square tubes each have four lobes to allow adjacent tubes to be welded to each other. The abso rber tubes are welded lengthwise to form the four wings of the control rod. Each wing is comprised of 17 absorber tubes. The absorber tu bes each act as an individual pre ssure chamber for the retention of helium. The region between each pair of square tubes is filled with he lium and sealed top and bottom by welding. The four wings are then welded to the tie rod to form the cruciform-shaped member of the control rod. The Marathon control rod blade has the full-length tie rod replaced with a segmente d tie rod, which also reduces weight.

The square tubes are circular inside and are loaded with either B 4C or hafnium. The B 4C is contained in separate capsules to prevent its migration. The capsules are placed inside the square absorber tubes and are smaller than the absorber tube inside diameter, allowing the B 4C to swell before making contact with the absorber tubes ther eby increasing stress corrosion resistance. Empty tubes may be used adjacent to the tie rods to achieve the desired reactivity worth. The combination of absorbers and ab sorber tubes is based on the needed initial reactivity worth. In addition, empty capsules are used in some absorber tubes to provide a plenum for helium released during B 4C burnup. The velocity limiter, shown in Figure 4.2-2, is a device which is an i ntegral part of the control rod and protects against the low probability of a rod drop accident . It is designed to limit the free fall velocity and reactivity insertion rate of a control rod so that minimum fuel damage would occur. It is a one-way device, in that control rod scram time is not significantly affected.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-035 4.1-9 Control rods are cooled by the co re leakage (bypass) flow. The co re leakage flow is made of recirculation flow that leaks through the severa l leakage flow paths, which are as follows:

a. The area between fuel channel and fuel assembly nosepiece,

b. The area between fuel assembly nosepiece and fuel support piece,

c. Holes in the lower tie plate,

d. The area between fuel s upport piece and core plate,

e. The area between core plate and shroud,

f. Holes in the core plate near power range monitor instru ment guide tubes,

g. Various leakage paths around th e control rod gu ide tubes, and

h. Control rod driv e cooling water.

4.1.3.3 Supplementary Reactivity Control

Supplemental reactivity control is achieved with burnable poison. The supplementary burnable poison is gadolinia (Gd 2O3) mixed with UO 2 in selected fuel rods in each fuel bundle.

4.1.4 ANALYSIS TECHNIQUES

4.1.4.1 Reactor Internal Components

Computer codes used for the analysis of the in ternal components as a basis for the original operating license are listed as follows:

a. MASS

b. SNAP (MULTISHELL)

c. GASP

d. NOHEAT

e. FINITE

f. DYSEA

g. SHELL 5

h. HEATER

i. FAP-71

j. CREEP-PLAST

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-10 The following italicized detailed descriptions of these programs ar e historical and were provided to support the application for an operating license. 4.1.4.1.1 MASS (Mechanical Anal ysis of Space Structure)

4.1.4.1.1.1 Program Description . This is a proprietary program of GE and is an outgrowth of the PAPA (Plate and Panel Anal ysis) program originally developed by L. Beitch in the early 1960s. The program is based on the principle of the finite elem ent method. Governing matrix equations are formed in terms of joint displacements using a "stiffness-influence -coefficient" concept originally proposed by L. Beitch (Reference 4.1-9). The program offers curved beam, plate, and shell elements. It can handle mechanical and thermal l oads in a static analysis and predict natural frequencies and mode shapes in a dynamic analysis.

4.1.4.1.1.2 Program Version and Computer . The Nuclear Energy Di vision is using a past revision of MASS. This revi sion is identified as revision "0" in the computer production library. The program operates on the Honeywell 6000 computer.

4.1.4.1.1.3 Hi story of Use . Since its development in the early 1960s, the program has been successfully applied to a wi de variety of jet-engine structural problems, many of which involve extremely complex geometries. The use of the program in the Nuclear Energy Division also started shortly after its development.

4.1.4.1.1.4 Extent of Application . Besides the Jet Engine and Nuclear Energy Divisions, the Missile and Space Division, the Appliance Division, and the Turb ine Division of GE have also applied the program to a wide r ange of engineering problems. The Nuclear Energy Division uses it mainly for piping and reactor internals analyses.

4.1.4.1.2 SNAP (MULTISHELL)

4.1.4.1.2.1 Program Description. The SNAP Program, which is also called MULTISHELL, is the GE code which determines th e loads, deformations, and stresses of axisymmetr ic shells of revolution (cylinders, cones, di scs, toroids, and rings) for axisymmetric th ermal boundary and surface load conditions. Thin shell theory is inherent in the solution of E. Peissner's differential equations for each shell's influence co efficients. Surfa ce loading capability includes pressure, average te mperature, and liner through wa ll temperature gradients; the latter two may be linearly varied over the shell meridian. The theoretical limitations of this program are the same as those of classical theory.

4.1.4.1.2.2 Program Version and Computer. The current version ma intained by the GE Jet Engine Division at Evandale, Ohio, is being used on the Honeywell 6000 computer in GE/NED.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-11 4.1.4.1.2.3 Hi story of Use. The initial version of the Shell Analysis Program was completed by the Jet Engine Division in 1961. Since then, a considerable amount of modification and addition has been made to accommo date its broadening area of application. Its application in the Nuclear Energy Division has a history longer than 10 years. 4.1.4.1.2.4 Extent of Application . The program has been used to analyze jet engine, space vehicle and nuclear reactor components. Becaus e of its efficiency and economy, in addition to reliability, it has been one of the main shell analysis programs in the Nuclear Energy Division of GE. 4.1.4.1.3 GASP

4.1.4.1.3.1 Program Description . GASP is a finite element pr ogram for the stress analysis of axisymmetric or plane two-dimensional geometries. The element representations can be either

quadrilateral or triangular. Axis ymmetric or plane structural loads can be input at nodal points. Displacements, temperat ures, pressure loads, and axial inertia can be accommodated. Effective plastic stress and stra in distributions can be calculat ed using a bilinea r stress-strain relationship by means of an ite rative convergence procedure.

4.1.4.1.3.2 Program Version and Computer. The GE version, originally from the developer, Professor E. L. Wilson, operates on the Honeywell 6000 computer.

4.1.4.1.3.3 Hi story of Use . The program was developed by Professor E. L. Wilson in 1965 (Reference 4.1-10). The present version in GE/NED has been in operation since 1967.

4.1.4.1.3.4 Extent of Application. The application of GASP in GE/NED is mainly for elastic analysis of axisymmetric and plane structures under thermal and pressure loads. The GE version has been extensively tested and used by engineers in the company.

4.1.4.1.4 NOHEAT

4.1.4.1.4.1 Program Description. The NOHEAT program is a two-dimensional and axisymmetric transient nonlinear temperature analysis program. An unconditionally stable numerical integration scheme is combined with iteration procedure to compute temperature distribution within the body subjected to arb itrary time- and temperat ure-dependent boundary conditions.

This program utilizes the finite element method. Included in the analysis are the three basic forms of heat transfer, conduc tion, radiation, and convection, as well as internal heat generation. In addition, coo ling pipe boundary conditions are also treated. The output includes temperature histories of all the nodal points established by the user. The program can handle multitransient temperature input.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-12 4.1.4.1.4.2 Program Version and Computer. The current version of the program is an improvement of the program originally deve loped by I. Farhoomand and Professor E. L. Wilson of University of California at Berkeley (Reference 4.1-11). The program operates on the Honeywell 6000 computer.

4.1.4.1.4.3 Hi story of Use. The program was developed in 1971 and installed in GE Honeywell computer by one of its original developers, I. Farhoomand, in 1972. A number of heat transfer problems related to the reactor pedestal have been sa tisfactorily solved using the program. 4.1.4.1.4.4 Extent of Application . The program using finite element formulation is compatible with the finite element stress-analysis computer program GASP. Such compatibility simplified the connection of the two analys es and minimizes human error.

4.1.4.1.5 FINITE

4.1.4.1.5.1 Program Description . FINITE is a general-pur pose finite element computer program for elastic stress analysis of two-dimensional structural problems including (1) plane

stress, (2) plane strain, and (3) axisymmetric structures. It has provisions for thermal, mechanical, and body force loads. The materials of the structure may be homogeneous or inhomogeneous and isotropic or orthotropic. The development of the FINITE program is based on the GASP program (see Section 4.1.4.1.3 ). 4.1.4.1.5.2 Program Version and Computer. The present version of the program at GE/NED was obtained from the develope r J. E. McConnelee of GE/Gas Turbine Department in 1969 (Reference 4.1-12). The NED version is used on the Honeywell 6000 computer.

4.1.4.1.5.3 Hi story of Use . Since its completion in 1969, the program has been widely used in the Gas Turbine and the Jet Engine Departmen ts of the GE for the analysis of turbine components.

4.1.4.1.5.4 Extent of Use . The program is used at GE/NED in the analysis of axisymmetric or nearly-axisymmetr ic BWR internals.

4.1.4.1.6 DYSEA 4.1.4.1.6.1 Program Description . The DYSEA (Dynamic and Seis mic Analysis) program is a GE proprietary program develope d specifically for seismic a nd dynamic analysis of RPV and internals/building system. It ca lculates the dynamic response of linear structural system by either temporal modal superposition or re sponse spectrum method. Fl uid-structure interaction effect in the RPV is taken into a ccount by way of hydrodynamic mass.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-13 Program DYSEA was based on program SA PIV with added capability to handle the hydrodynamic mass effect. Structural stiffness and mass matrices are formulated similar to SAPIV. Solution is obtained in time domain by calculating the dynamic response mode-by-mode. Time integration is performed by using Newmark's -method. Response spectrum solution is also available as an option.

4.1.4.1.6.2 Program Version and Computer. The DYSEA version now operating on the Honeywell 6000 computer of GE, Nuclear Energy Systems Division, was developed at GE by modifying the SAPIV program. Capability wa s added to handle the hy drodynamic mass effect due to fluid-structure interact ion in the reactor. It can handle three-dimensional dynamic problems with beam, trusses, and springs. Both acceleration time histories and response

spectra may be used as input.

4.1.4.1.6.3 History of Use. The DYSEA program was develope d in the Summer of 1976. It has been adopted as a standar d production program since 1977 and it has been used extensively in all dynamic and seismic analysis of the RPV and internals/building system.

4.1.4.1.6.4 Extent of Application . The current version of DY SEA has been used in all dynamic and seismic analys is since its development. Results from test problems were found to be in close agreement with thos e obtained from either verified programs or analytic solutions.

4.1.4.1.7 SHELL 5

4.1.4.1.7.1 Program Description . SHELL 5 is a finite shell element program used to analyze smoothly curved thin shell structures with any distribution of elasti c material properties, boundary constraints, and mec hanical thermal and displacement loading conditions. The basic element is a triangle whose membrane displace ment fields are linear polynomial functions, and whose bending displacement field is a cubic polynomial function (Reference 4.1-13). Five degrees of freedom (three displacements and two bending rotations) are obtained at each nodal point. Output displacem ents and stresses are in a lo cal (tangent) surface coordinate system.

Due to the approximation of element membrane di splacements by linear functions, the in-plane rotation about the surface normal is neglected. Therefore, the only rotations considered are due to bending of the shell cross section and application of the method is not recommended for shell intersection (or disconti nuous surface) problems where in-plane rotation can be significant.

4.1.4.1.7.2 Program Version and Computer . A copy of the sour ce deck of SHELL 5 is maintained by GE/NED by Y. R. Rashid, one of the originators of the program. SHELL 5 operates on the UNIVAC 1108 computer.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-14 4.1.4.1.7.3 Hi story of Use . SHELL 5 is a program developed by Gulf General Atomic Incorporated (Reference 4.1-14) in 1969. The program has b een in production status at Gulf General Atomic, GE, and at other major computer operating systems since 1970. 4.1.4.1.7.4 Extent of Application. SHELL 5 has been used at GE to analyze reactor shroud support and torus. Satisfact ory results were obtained.

4.1.4.1.8 HEATER

4.1.4.1.8.1 Program Description. HEATER is a computer pr ogram used in the hydraulic design of feedwater spargers and their associated delivery header and pi ping. The program utilizes test data obtained by GE using full scale mockups of f eedwater spargers combined with a series of models which re presents the complex mixing pr ocesses obtained in the upper plenum, downcomer, and lower plenum. Mass and energy balances th roughout the nuclear steam supply system are m odeled in detail (Reference 4.1-15). 4.1.4.1.8.2 Program Version and Computer. This program was developed at GE/NED in FORTRAN IV for the Honeywell 6000 computer.

4.1.4.1.8.3 Hi story of Use. The program was developed by various individuals in GE/NED beginning in 1970. The present version of the program ha s been in operation since January 1972.

4.1.4.1.8.4 Extent of Application . The program is used in the hydraulic design of the feedwater spargers for each BW R plant, in the evaluation of design modifications, and the evaluation of unusual operational conditions.

4.1.4.1.9 FAP-71 (Fati gue Analysis Program)

4.1.4.1.9.1 Program Description . The FAP-71 computer code, or Fatigue Analysis Program, is a stress analysis tool used to aid in performing ASME-III Nu clear Vessel Code structural design calculations. Specifically, FAP-71 is used in determini ng the primary plus secondary stress range and number of allowa ble fatigue cycles at points of interest. For structural locations at which the 3S m (P+Q) ASME Code limit is exceeded, the program can perform either (or both) of two elastic-plastic fatigue life evaluations: 1) the method reported in ASME Paper 68-PVP-3, 2) the present method documented in Paragraph NB-3228.3 of the 1971 Edition of the ASME Section III Nuclear Vessel Code. The Program can accommodate up to 25 transient stress stat es on as many as 20 structural locations.

4.1.4.1.9.2 Program Version and Computer. The present version of FAP-71 was completed by L. Young of GE/NED in 1971 (Reference 4.1-16). The program currently is on the NED Honeywell 6000 computer.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-15 4.1.4.1.9.3 History of Use. Since its completion in 1971, the program has been applied to several design analyses of GE BWR vessels.

4.1.4.1.9.4 Extent of Use. The program is used in conjuncti on with several shell analysis programs in determining the fatigue life of BWR mechanical components subject to thermal transients.

4.1.4.1.10 CREEP/PLAST

4.1.4.1.10.1 Program Description. A finite element progr am is used for the analysis of two-dimensional (plane and axisymmetric) problems under conditions of creep and plasticity. The creep formulation is based on the memory theory of creep in which the constitutive relations are cast in the form of heredi tary integrals. The material creep properties are built into the program and they represent annealed 304 stainle ss steel. Any other cr eep properties can be included if required.

The plasticity treatment is based on kinemetic hardening and von Mises yield criterion. The hardening modulus can be constant or a function of strain.

4.1.4.1.10.2 Progr am Version and Computer. The program can be used for elastic-plastic analysis with or without the presence of creep. It can also be used for creep analysis without the presence of instantaneous plasticity. A detailed description of theory is given in Reference 4.1-17. The program is operative on UNIVAC-1108.

4.1.4.1.10.3 History of Use. This program was developed by Y. R. Rashid (Reference 4.1-17) in 1971. It underwent extensive program te sting before it was put on production status.

4.1.4.1.10.4 Extent of Application. The program is used at GE/NED in the channel cross section mechanical analysis.

4.1.4.2 Fuel Rod Thermal Analysis

Thermal design analyses of the fuel and core we re performed to verify that design criteria are met (see References 4.1-1, 4.1-4 and 4.1-5). 4.1.4.3 Reactor Systems Dynamics The analysis techniques used in reactor systems dynamics are de scribed in Sec tions S.1.3 and S.4 of Reference 4.1-1. A complete stability analysis for the reactor coolant system is provided in Section 4.4.4.2. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-16 4.1.4.4 Nuclear Engineering Analysis

The analysis techniques are described in the fuel design reports (see Reference 4.1-1). 4.1.4.5 Neutron Flue nce Calculations

See Section 4.3.2.8. 4.1.4.6 Thermal Hydraulic Calculations

The digital computer program uses a parallel fl ow path model to perform the steady-state BWR reactor core thermal-hydraulic an alysis. Program input includes the core geometry, operating power, pressure, coolant flow rate , inlet enthalpy, and the power distribution within the core. Output from the program includes core pressure drop, coolant fl ow distribution, critical power ratio, and axial variations of quality, density, and enthalpy for each fuel type.

4.

1.5 REFERENCES

4.1-1 General Electric Sta ndard Application for Reactor Fuel, NEDE-24011-P-A, and Supplement for United States, NED E-24011-P-A-US (most recent approved version referenced in COLR).

4.1-2 Supplemental Reload Licensing Repor t for Columbia (m ost recent version referenced in COLR).

4.1-3 Fuel Bundle Information Report for Columbia (most recent approved version referenced in COLR).

4.1-4 "GNF2 Advantage Generic Compliance with NEDE-24011-P-A (GESTAR II)," NEDC-33270P, (most recent vers ion referenced in COLR).

4.1-5 "GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II)," NEDC-32868P, (most recent vers ion referenced in COLR). 4.1-6 Deleted. 4.1-7 Crowther, R. L., Xenon Considerations in Design of Boiling Water Reactors, APED-5640, June 1968.

4.1-8 Deleted. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-17

4.1-9 Beitch, L., Shell Structures Solved Numerically by Using a Network of Partial Panels, AIAA Journal, Volume 5, No. 3, March 1967.

4.1-10 E. L. Wilson, A Dig ital Computer Program For the Finite Element Analysis of Solids With Non-Linear Material Proper ties, Aerojet General Technical, Memo No. 23, Aerojet General, July 1965. 4.1-11 I. Farhoomand and E. L. Wilson, Non-Line ar Heat Transfe r Analysis of Axisymmetric Solids, SESM Report SESM 71-6, University of California at Berkeley, Berkeley, California, 1971.

4.1-12 J. E. McConnelee, Finite-Users Manual, Gene ral Electric TIS Report DF 69SL206, March 1969.

4.1-13 R. W. Clough and C. P. Johnson, A Finite Element Approximation For the Analysis of Thin Shells, International Journal Solid Structures, Vol. 4, 1968.

4.1-14 A Computer Program For the Structural Analysis of Arbitrary Three-Dimensional Thin Shells, Report No. GA-9952, Gulf General Atomic.

4.1-15 Burgess, A. B., User Guide and Engineering Description of HEATER Computer Programs, March 1974.

4.1-16 Young, L. J., FAP-71 (Fatigue Analysis Program) Computer Code, GE/NED Design Analysis Unit R. A. Report No. 49, January 1972.

4.1-17 Rashid, Y. R, Theory Report for Creep-P last Computer Program, GEAP-10546, AEC Research and Development Report, January 1972.

FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.960690.95 Steam Separator 4.1-1Wet Steam ReturningWaterSteam Water MixtureTurning Vanes (Inlet Nozzle) Standpipe Core Discharge Plenum ReturningWaterWater Level Columbia Generating Station Final Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.98Steam Dryer Panel 4.1-2SteamFlowSteamFlowColumbia Generating StationFinal Safety Analysis Report FigureAmendment 61 December 2011 Form No. 960690 LDCN-10-029 Draw. No. Rev.910402.33 4.1-3Columbia Generating Station Final Safety Analysis Report DELETED COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-1 4.2 FUEL SYSTEM DESIGN

See Appendix A, Secti on A.4.2 of Reference 4.2-1. 4.2.1 DESIGN BASES

General Electric BWR fuel as sembly and channel design base s, analytical methods, and evaluation results are de scribed in Reference 4.2-1 (Appendix A, subsection A.4.2.1), Reference 4.2-6 and Reference 4.2-25. 4.2.1.1 Fuel System Damage Limits

4.2.1.1.1 Stress/Strain Limits

See subsection 2.2.1. 1.2 of Reference 4.2-1. 4.2.1.1.2 Fatigue Limits

See subsections 2.2. 1.2.2 of Reference 4.2-1. 4.2.1.1.3 Fretting Wear Limits

Fretting wear is considered in the mechanical design analysis of the assembly. See subsection 2.2.1.3. 2 of Reference 4.2-1. 4.2.1.1.4 Oxidation, Hydriding, and Corrosion Limits

See subsection 2.2.1. 4.2.2 of Reference 4.2-1 for the hydriding limit. Oxidation and corrosion are considered in the mechanical design analysis. See subsec tion 2.2.1.4.1.2 of Reference 4.2-1. 4.2.1.1.5 Dimensiona l Change Limits

See Reference 4.2-6 and subsection 2.2. 1.5.2 of Reference 4.2-1. 4.2.1.1.6 Internal Gas Pressure Limit See subsection 2.2.1. 6.2 of Reference 4.2-1 .

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-2 4.2.1.1.7 Hydraulic Loads Limits

See subsection 2.2.1. 7.2 of Reference 4.2-1. 4.2.1.1.8 Control Rod Reactivity Limits

See Section 3.2 and 3.3 of Reference 4.2-1 and Reference 4.2-7. 4.2.1.2 Fuel Rod Failure Limits

4.2.1.2.1 Hydriding Limits

See subsection 2.2. 2.1 of Reference 4.2-1. 4.2.1.2.2 Cladding Collapse Limits

See subsection 2.2.2. 2.2 of Reference 4.2-1. 4.2.1.2.3 Fretting Wear Limits

See subsection 2.2.1. 3.2 of Reference 4.2-1. 4.2.1.2.4 Overheating of Cladding Limits

See subsections 2.2.2.4 and 4.3.1 of Reference 4.2-1. 4.2.1.2.5 Overheating of Pellet Limits

See subsection 2.2.2. 5.2 of Reference 4.2-1. 4.2.1.2.6 Excessive Fuel Enthalpy Limits

See subsection 2.2. 2.6 of Reference 4.2-1. 4.2.1.2.7 Pellet-Claddi ng Interaction Limits

See subsection 2.2.2. 7.2 of Reference 4.2-1. 4.2.1.2.8 Bursting Limits

See subsections 2.2.2.8 a nd 2.2.3.4 of Reference 4.2-1. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-3 4.2.1.2.9 Mechanical Fracturing Limits

See subsection 2.2.2. 9.2 of Reference 4.2-1. 4.2.1.3 Fuel Coolability Limits

4.2.1.3.1 Cladding Embrittlement Limits

See Reference 4.2-10, subsection 2.2.3.1 of Reference 4.2-1. 4.2.1.3.2 Violent Expul sion of Fuel Limits

See subsection 2.2. 3.2 of Reference 4.2-1. 4.2.1.3.3 Generalized Cladding Melt Limits

Same as Section 4.2.1.3.1 and subsection 2.2. 3.3 of Reference 4.2-1. 4.2.1.3.4 Fuel Rod Ballooning Limits

Same as Section 4.2.1.2.8 . 4.2.1.3.5 Structural Deformation Limits

See subsection 2.2. 3.5 of Reference 4.2-1. 4.2.2 DESCRIPTION AN D DESIGN DRAWINGS

See References 4.2-2 and 4.2-3. 4.2.2.1 Control Rods

The control rods (typical configuration shown in Figures 4.2-1.1 , 4.2-1.2, and 4.2-1.3) perform the dual function of power shaping and reactivity control. Power distribution in the core is controlled during operation of the reactor by manipulating selected patterns of control rods. Control rod withdrawal tends to counterba lance steam void effects at the top of the core and results in significant axial power flattening.

The original control rods consists of a sheathed cruciform array of stainless steel tubes filled with boron-carbide (B 4C) powder. The control rods are 9.88 in. in total span and are separated uniformly throughout the core on a 12-in. pitch maximum. Each control rod is surrounded by four fuel assemblies.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 4.2-4 The main structural member of a control rod is made of type 304 stainles s steel and consists of a top handle, an original bottom casting with a velocity limiter and cont rol rod drive coupling, a vertical cruciform center post, and four U-shaped absorber tube sheaths. The top handle, bottom casting, and center post are welded into a single skeletal structure. The U-shaped sheaths are resistance welded to the center post, handle, and casti ngs to form a rigid housing to contain the boron-carbide-filled absorber rods. Rollers at the t op and bottom of the control rod guide the control rod as it is inserted and withdrawn from th e core. The control rods are cooled by the core bypass flow. The U-shaped sh eaths are perforated to allow the coolant to circulate freely about the absorber tubes. Op erating experience has sh own that control rods constructed as desc ribed above are not susceptible to dimensional distortions.

The boron-carbide (B 4C) powder in the absorber tubes is compacted to about 70% of its theoretical density. The boron-car bide contains a minimum of 76.5% by weight natural boron. The boron-10 (B-10) minimum content of the boron is 18% by weight. Absorber tubes are made of type 304 stainless steel . Each absorber tube is 0. 188-in. O.D. and has a 0.025-in. wall thickness. Absorber tubes are sealed by a plug welded into each end. The boron-carbide is longitudinally separated in to individual compartments by stainless steel balls at approximately 16-in. intervals. The steel balls are held in place by a slight crimp of the tube. Should boron-carbide tend to sint er in service, the steel balls will keep the resulting void spaces distributed over the le ngth of the absorber tube.

Some of the control rods have been replaced with Duralife 215 or Marathon control rods. The main structural member of the Duralife 215 cont rol rod design is made of stainless steel and consists of a top handle, a tie rod, a bottom control rod driv e coupling, and four sheaths containing the neutron absorber. The top handle, tie rod, velocity limiter, and sheaths are welded into a single structure. The neutron absorber in each wing of the sheath consists of 18 high-purity stainless-steel tube s filled with boron-carbide, three hafnium rods at the edge of the wing, and a hafnium plate at the top.

The sheaths of the Duralife 215 bl ades are attach ed to the structure w ith full fusion corner welds to the handle, tie rod, and velocity limiter to form a rigid housing. In conel X750 rollers at the top and bottom of the cont rol rod guide the control rod as it is inserted and withdrawn from the core. These rollers ro tate on PH 13-8 Mo pins. The sheaths are perforated and the hafnium absorber plate has coolan t grooves to allow the coolant to circulate freely about the absorber and flush the joint between the sheath and handle.

The number of boron carbide absorber rods in each wing has been changed from 19 rods with an I.D. of 0.138 in. to 18 rods with an I.D. of 0.148 in. Th e outside diameter remains the same. The length of the absorb er column in these rods has been reduced from 143 in. to 137 in. to accommodate a top 6-in.-high hafnium plate. In addition, three 0.188 in. O.D. hafnium rods have been added to the edge of each wing.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 4.2-5 The Marathon control rod blade consists of a top handle, a segmented tie rod (for weight savings), a bottom control rod coupling/velocity limiter and four wings consisting of an array of square tubes. The square tubes each have four lobes to allow adjacent tubes to be welded to each other. The absorber tubes are welded lengthwise to form the four wings of the control rod. Each wing is comprised of 17 absorber tubes. The four wi ngs are then welded to the tie rod to form the cruciform-shaped member of the control rod. The square tubes are circular inside and are loaded with either B 4C or hafnium. The combination of absorbers and abso rber tubes is based on the needed initial reactivity worth. In addition, empty capsules are used in some absorber tubes to provide a plenum for helium released during B 4C burnup.

A comparison of the original, the Duralife 215 and the Marathon control rod dimensions and materials is given in Table 4.2-1 . 4.2.2.2 Velocity Limiter

The control rod velocity limiter (see Figure 4.2-2 ) is an integral part of the bottom assembly of each control rod. This feature protects against a high reactivity insertion rate by limiting the control rod velocity in the event of a control rod drop accident. It is a one-way device in that the control rod scram velocity is not significantly affected but the control rod dropout velocity is reduced to a permissible limit.

The velocity limiter is in the form of two nearly mated conical elements that act as a large clearance piston inside the control rod guide tube. The lower conical element is separated from the upper conical element by four radial spacers 90 degrees apart.

The hydraulic drag forces on a control rod are approximately proportional to the square of the rod velocity and are negligible at normal rod withdrawal or rod inser tion speeds. However, during the scram stroke the rod reaches high velocity, and the drag forces must be overcome by the drive mechanism.

To limit control rod velocity dur ing dropout but not during scram, the velocity limiter is provided with a streamlined profile in the scram (upward) direction. Thus, when the control rod is scrammed water flows over the smooth su rface of the upper conical element into the annulus between the guide tube and the limiter. In the dropout direction, however, water is trapped by the lower conical el ement and discharged through the annulus between the two conical sections. Because this water is forced in a partially reversed direction into water flowing upward in the annulus, a severe turbulence is created, and this sl ows the descent of the control rod assembly to less than 5 ft/sec.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-6 4.2.3 DESIGN EVALUATION

See Appendix A, subsecti on A.4.2.3 of Reference 4.2-1. 4.2.3.1 Fuel System Damage Evaluation

4.2.3.1.1 Stress/Strain Evaluation

Fuel rod internal pressure has been shown to remain below system pressure for rod peak burnups well beyond anticipated ach ieved burnup. For GNF fuel see section 2.2.1.1.3 of Reference 4.2-1. 4.2.3.1.2 Fati gue Evaluation

See subsection 2.2.1. 2.3 of Reference 4.2-1. 4.2.3.1.3 Fretting Wear Evaluation

See Reference 4.2-12, subsection 2.2.1.3.3 of Reference 4.2-1. 4.2.3.1.4 Oxidation, Hydriding, and Corrosion Evaluation

See subsections 2.2.1.4.1.3 and 2.2.1.4.2.3 of Reference 4.2-1. 4.2.3.1.5 Dimensiona l Change Evaluation

See Reference 4.2-6, subsection 2.2.1.5.3 of Reference 4.2-1. 4.2.3.1.6 Internal Ga s Pressure Evaluation

See subsection 2.2. 6 of Reference 4.2-3 and Section 3.2. 6 of reference 4.2-2. The internal pressure is used in conjuncti on with other loads on the fuel rod cladding when calculating cladding stresses and comparing these stresses to the design criteria. The analysis results show that the calculated cladding stresses are below allowable limits even with internal gas pressure and other loads at end of life normal and transient conditions, respectively.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-7 4.2.3.1.7 Hydraulic Load Evaluation

See subsection 2.2.1. 7.3 of Reference 4.2-1, 4.2-12 and Section 3.9. 4.2.3.1.8 Control Rod Reactivity Evaluation

See Appendix A, subsecti on A.4.3.2 of Reference 4.2-1. Energy Northwest calculates the fluence of each control blade us ing an appropriate c onversion factor for fuel exposures adjacent to the control blade. Control blade shuffling or replacement is based on the calculated blade fluence as compared to vendor allowed values (Reference 4.2-22). The vendor allowed values account for the reduction in cont rol blade worth due to a comb ination of boron-10 depletion and boron loss resulting from crack ing of the absorber tubes.

4.2.3.2 Fuel Rod Failure

4.2.3.2.1 Hydriding Evaluation

See Section 4.2.3.1.4 . 4.2.3.2.2 Cladding Collapse Evaluation

See subsection 2.2. 8 of Reference 4.2-3 and Section 3.2.8 of Reference 4.2-2. 4.2.3.2.3 Fretting Wear Evaluation

See Section 4.2.3.1.3 . 4.2.3.2.4 Overheating of Cladding Evaluation

See section 2.6 of Reference 4.2-3 and Section 3.6 of Reference 4.2-2. 4.2.3.2.5 Overheating of Pellet Limits

See subsection 2.2. 9 of Reference 4.2-3 and Section 3.2.9 of Reference 4.2-2. 4.2.3.2.6 Excessive Fuel Enthalpy Evaluation

See Section 15.4.9 and subsection 2.12 of Reference 4.2-3 and Section 3.12 of Reference 4.2-2. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-8 4.2.3.2.7 Pellet-Cladding Interaction Evaluation

Calculated results do not exceed the 1% plastic strain or minimum critical power ratio (MCPR) fuel cladding integrity safety limits; thus fuel pellet melting does not occur. These are the most applicable genera l design criteria for pell et cladding interaction (PCI) phenomena. While PCI-induced fuel failures rema in a commercially undesirable pr oblem, they are not a safety concern. Boiling water reactors (BWRs) have been designed and licensed with provisions to accommodate operating with fuel cladding perforation, and field experience confirms that plants do indeed operate within radiological release limits.

Operation below the thermal-mechanical limits historically has resulted in very few pellet-cladding interaction (PCI) fuel failures. Furthermore power ma neuvering guidelines have been developed that have further reduced fuel failures due to the PCI mechanism.

4.2.3.2.8 Bursting Evaluation

See subsection 2.11.1 of Reference 4.2-3 and Section 3.11.1 of Reference 4.2-2. 4.2.3.2.9 Mechanical Fracturing Evaluation

See Reference 4.2-12 and subsection 2.2. 2.9.3 of Reference 4.2-1. 4.2.3.3 Fuel Coolability Evaluation

4.2.3.3.1 Cladding Embrittlement Evaluation

See Section 4.2.3.2.8 and subsection 2.2. 3.1 of Reference 4.2-1. 4.2.3.3.2 Violent Expulsi on of Fuel Evaluation

See Section 15.4.9 and subsection 2.12 of Reference 4.2-3 and Section 3.12 of Reference 4.2-2. 4.2.3.3.3 Generalized Cladding Melt Evaluation See Section 4.2.3.2.8 and subsection 2.11.2 of Reference 4.2-3 and Section 3.11.2 of Reference 4.2-2. 4.2.3.3.4 Fuel Rod Ballooning Evaluation

See Section 4.2.3.2.8 and subsection 2.11.1 of Reference 4.2-3 and Section 3.11.1 of Reference 4.2-2. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 4.2-9 4.2.3.3.5 Structural Deformation Evaluation See Section 4.2.3.2.9 . 4.2.4 TESTING, INSPECTION, AND SURVEILLANCE PLANS

4.2.4.1 Fuel Testing, In spection, and Surveillance

See Appendix A, subsecti on A.4.2.4 of Reference 4.2-1. 4.2.4.2 Online Fuel System Monitoring

Columbia Generating Station (CGS ) has two independent radiation detection systems that are directly capable of detecting fiss ion product releases from failed fu el rods in an online manner. The main steam line radiation (MSLR) monitors are described in Section 11.5.2.1.1 . Because the MSLR monitors are located relatively close to the reactor core, they are capable of sensing gross fission product rel eases in a few seconds.

The offgas system radiation (OGSR) monitors are capable of detecting low-level emissions of noble gases in 2 to 3 minutes af ter the gases leave th e fuel. The OGSR monitors are described in more detail in Section 11.5.2.2.1 . 4.2.4.3 Post-Irradiation Surveillance

The following fuel surveillance will be conducted after the refueling outage for the CGS unit on fuel discharged during the refueling outage that has given indication of gross cladding defects or anomalies during plant operation.

Scope The fuel surveillance program, de veloped to provide verification of the reliable performance of the CGS fuel design, will consist of the following insp ections and measurements:

a. Visual inspection of the peripheral rods will be perf ormed on discharged fuel, that has given indication of gross cla dding defects or anomalies during plant operation, after each refu eling outage. The examin ation will be capable of detecting and characterizi ng generic gross cladding defects or anomalies; and

b. If anomalous behavior of the fuel cla dding, components of the fuel assembly, or significant rod bow are detected by visual examination, further investigation, and measurements of such significant anomalies will be conducted after the refueling outages.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-038 4.2-10 Implementation

a. Onsite receiving inspection of all the initial core fuel asse mblies and subsequent reloads will be documented. Any significant anomalies detected will be documented;

b. Fuel performance histor y and related plant operationa l data will be monitored and analyzed during operation;

c. Assemblies discharged during each refueling outage that have given indication of gross cladding defects or anomalies dur ing plant operation will be selected for visual inspection. The vi sual examination of the pe ripheral rods will include observations for cladding de fects, fretting, rod bo wing, missing components, corrosion, crud deposition, and geometric distortions. The defects or anomalies

on the cladding surface area examined will be either vi deotaped or photographed to document and characterize the anomaly;

d. In the event that significant anomalies are observed during the refueling examination, all other discharged assemblies may also be visually inspected.

The results will be analyzed to determine fuel utilization strategy and possible safety implications in accordance with the operating procedures and applicable licensing requirements;

e. If unusual defects are obse rved, the fuel with the de fects and the applicable operational data will be investigated and further appr opriate tests and examination of the defected fuel will be performed; and

f. If defects of an unusual nature are detected, an oral report will be made to the NRC after the completion of the inspecti on activities. Under normal conditions, the report will contain visual examination summaries confirming the reliable performance of the fuel asse mblies. In the ev ent that significant anomalies or unusual defects are observed, the report w ill contain the description and related data of onsite receiving inspection a nd operational conditions

. Evaluation and studies to identify causes for any enc ountered anomalies or defects will be

assessed and the results w ill be reported to the NRC as they become available.

4.2.4.4 Channel Ma nagement Program

Fuel channels are subject to bulge, bow, and elongation when irradi ated in reactors. Excessive deformations (bow and bulge) c ould produce traversing in-core probe asymmetries and control blade frictional resistance.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-11 All new reload fuel will be lo aded with new channels. Energy Northwest has in the past reinserted requalified channels in CGS but has transitioned away from channel reuse (References 4.2-13, 4.2-14, and 4.2-15). The Safety Evaluation Report Re lated to the Operation of WPPSS Nuclear Project No. 2, Supplement 3 (Reference 4.2-16), discusses measurement of selected discharged fuel channels for deflection. The intent of this deflection measurement was to qualify channels for reuse. Because Energy Northwest no longe r reuses channels, the qualific ation of channel reuse has been discontinued.

In addition to the above cha nnel management program, Energy Northwest is taking a number of operational actions to monitor channel distortion in the core. These include Technical Specifications requirements for periodic scram testi ng and rod notch testing, which would provide an indication of pending driveline friction between control rod and bowed channels. Should either of these tests suggest a driveline friction problem, the tests described in NEDE-21354-P, Reference 4.2-6, would then be used to isolate the cause.

4.

2.5 REFERENCES

4.2-1 General Electric Compa ny, General Electric Standard Application for Reactor Fuel (NEDE-24011-P-A), and Supplement for United States (NEDE-24011-P-A-US) (most re cent approved version re ferenced in COLR).

4.2-2 "GNF2 Advantage Generic compliance with NEDE-24011-P-A (GESTAR II)," NEDC-33270P, (most recent vers ion referenced in COLR).

4.2-3 "GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II)," NEDC-32868P, (most recent vers ion referenced in COLR).

4.2-4 Deleted.

4.2-5 Deleted.

4.2-6 General Electric Co mpany, BWR Fuel Channel Mechanical Design and Deflection, NEDE-21354-P, September 1976. 4.2-7 General Electric Co mpany, Control Blade Life time with Potential B 4C Loss, NEDO-24226 and S upplement 1.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-12 4.2-8 Deleted.

4.2-9 Deleted.

4.2-10 General Electric Company, Analytical Model for Loss-of-Coolant Analyses in Accordance with 10 CFR 50 Appendix K, NEDO-20566-A, September 1986.

4.2-11 Deleted.

4.2-12 General Electric Company, GE Duralife 215 Control Rod Safety Evaluation, GENE-778-028-0790, Revision 2, July 1992. 4.2-13 Letter and Attachment from G. C. Sorensen, Ma nager, Regulatory Programs, Supply System to NRC,

Subject:

Nuclear Plant No. 2, Operating License NPF-21, Modification to WNP-2 Cycle Reload Submittal and Response to NRC

Bulletin 90-02: Loss of Thermal Margin Caused by Channel Box Bow, GO2-90-075, April 13, 1990.

4.2-14 Letter from G. C. Sorensen, Mana ger, Regulatory Progra ms, Supply System to NRC,

Subject:

Nuclear Plant No. 2, Operating License NPF-21, Final Response to NRC Bulletin 90-02; Loss of Thermal Margins Caused by Channel Box Bow, GO2-90-162, September 28, 1990.

4.2-15 Letter and Attachments from P. L. Eng., Project Manager, NRC to G. C. Sorensen, Manager, Regulatory Programs, Suppl y System, Evaluation of Response to NRC Bulletin 90-92; Loss of Thermal Margins Caused by Channel Box Bow (TAC No. 76354), April 22, 1991.

4.2-16 Nuclear Regulatory Commission, Sa fety Evaluation Repo rt Related to the Operation of WPPSS Nuclear Project No. 2, NUREG-0892, Supplement 3, Washington, D.C., May 1983.

4.2-17 Deleted.

4.2-18 Deleted. 4.2-19 Deleted.

4.2-20 General Electric Company, GE Marathon Control Rod Assembly (NEDE-31758P-A), October 1991. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-13 4.2-21 Deleted.

4.2-22 General Electric Company, GE BWR Control Rod Lifetime, NEDE-30931 (most recent revision specified in CVI 768-00,91).

4.2-23 Deleted.

4.2-24 Deleted. 4.2-25 General Electric Co mpany, Fuel Assembly Eval uation of Combined Safe Shutdown Earthquake (SSE) and Loss-of -Coolant Accident (LOCA) Loadings, NEDE-21175-3-P, July 1982. 4.2-26 Deleted.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-022 4.2-15 Table 4.2-1 Control Rod Parameters Original Equipment Duralife 215 Marathon Control rod weight, lb (kg) 186 (84.4) 204 (92.5) 197 (89.4) Absorber rod - boron-car bide Number per control rod 76 72 52 Length, in. (mm) 143 (3632) 137 (3480) 143.7 (3650) Inside diameter, in. (mm) 0.138 (3.51) 0.148 (3.76) 0.189 (4.80) Density, gr ams/cm3 1.76 (Nomi nal) 1.76 (Nomi nal) 1.76 (70% Theoretical) Absorber tube Cladding ma terial Stainless steel High purity stainless steel 304S O.D., in. (mm) 0.188 (4.78) 0.188 (4.78) 0.246 (6.248) Wall thickness, in. (mm) 0.025 (0.635) 0.020 (0.508) 0.021 (0.533) Absorber rods - hafnium Number per control rod

- 12 16 Length, in. (mm)
- 143 (3632) 143.4 (3642) Diameter, in. (mm)
- 0.188 (4.78) 0.188 (4.78) Density, gr ams/cm3  13.1 13.0 Absorber plate - hafnium Number per control rod Length, in. (mm)
- 6 (152) - Width, in. (mm)
- 3.42 (86.87) - Thickness, i

n. (mm) - 0.188 (4.78) - Density, gr ams/cm3 - 13.1 - Sheath thick ness, in. (mm) 0.030 (0.762) 0.034 (0.864) - Stiffener Yes No - Pin material Haynes Alloy 25 PH 13-8 MO PH 13-8 MO Roller material Stellite 3 Inconel X750 Inconel X750

FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.960690.96Original Equipment (OEM) Control Rod Blade Assembly4.2-1.1Columbia Generating StationFinal Safety Analysis Report LDCN-02-022 ABSORBER ROD 16 in. BETWEEN BALLS (TYPICAL) 1/2 in. (TYPICAL) 6.5"143 in. ACTIVE POISON LENGTH 9.88 in.HANDLESHEATHBLADENEUTRON ABSORBER

RODSUPPER GUIDE ROLLER TYPICAL 4 PLACES COUPLING SOCKETLOWER GUIDE

ROLLER TYPICAL 4 PLACESVELOCITY LIMITER COUPLING RELEASE

HANDLEWELDED END PLUG FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.010126.54DuraLife 215 Control Rod Blade Assembly 4.2-1.2Columbia Generating StationFinal Safety Analysis Report LDCN-02-022 Zone 2Zone 1Solid Hafnium Rods Solid Hafnium Plate Zone 2Zone 1Solid Hafnium Rods Standard B 4C Absorberwith Improved Tubing Material FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.010126.55Marathon Control Rod Blade Assembly 4.2-1.3Columbia Generating StationFinal Safety Analysis Report LDCN-02-022 HANDLEBLADENEUTRON ABSORBER RODSCOUPLING RELEASE HANDLEVELOCITY LIMITER COUPLING SOCKET FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.010126.56Marathon Control Rod Blade Absorber Details 4.2-1.4Columbia Generating StationFinal Safety Analysis Report LDCN-02-022SQUARE TYPEABSORBER TUBE ABSORBER CAPSULE B4C Placement in Capsules and Absorber Tubes GAPLOBEBORON CARBIDE POWDERAbsorber Tubes(Before Welding)Absorber Tubes Welded to Tie Rods FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.010126.57Marathon Control Rod Blade Absorber Placement 4.2-1.5LDCN-02-022CONTROL ROD CROSS PARTIAL SECTIONTOPBOTTOMTYPE 1TYPE 1HAFNIUMB4C ABSORBER CAPSULEEMPTY CAPSULE TYPE 1ABSORBER MATERIAL CONTAINED IN TUBESTYPE 2TYPE 3 TYPE 3TYPE 2TYPE ABSORBER LOADING1 ONE 143.1" LONG HAFNIUM ROD 2 FOUR 35.77" LONG B4C CAPSULES 3 THREE 35.77" LONG B4C CAPSULES ONE 23.85" LONG B4C CAPSULE ONE 11.925" LONG EMPTY CAPSULE Columbia Generating StationFinal Safety Analysis Report FigureAmendment 57 December 2003Form No. 960690.veR.oN .warD 960690.97 Control Rod Velocity Limiter 4.2-2CouplingCore Support Plate OrificeVelocity LimiterGuide Tube Control Rod Drive HousingStub TubeReactor Vessel10.420 In.148-7/16 In. 144 In.StrokeControl RodFuel Support Casting Rollers22-1/16 In. To Active Fuel Zone Columbia Generating Station Final Safety Analysis Report LDCN-02-022 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-1 4.3 NUCLEAR DESIGN

4.3.1 DESIGN BASES

See Appendix A, subsecti on A.4.3.1 of Reference 4.3-4. 4.3.1.1 Reactivity Basis

See Appendix A, subsection A.4.3.1.1 of Reference 4.3-4. 4.3.1.2 Overpower Bases

See Appendix A, subsection A.4.3.1.2 of Reference 4.3-4. 4.3.2 DESCRIPTION

See Appendix A, subsecti on A.4.3.2 of Reference 4.3-4. 4.3.2.1 Nuclear Design Description

See Appendix A, subsection A.4.3.2.1 of Reference 4.3-4. The reference core loading pattern is provided in Reference 4.3-7. See Table 4.3-2 , Table 4.3-3 and Reference 4.3-9. 4.3.2.2 Power Distribution

See Appendix A, subsection A.4.3.2.2 of Reference 4.3-4. 4.3.2.2.1 Power Distri bution Calculations

See References 4.3-7 and 4.3-3. 4.3.2.2.2 Power Distri bution Measurements

See Appendix A, subsection A.4.3.2.2.2 of Reference 4.3-4. 4.3.2.2.3 Power Distribution Accuracy

See Appendix A, subsection A.4.3.2.2.3 of Reference 4.3-4. 4.3.2.2.4 Power Dist ribution Anomalies

See Appendix A, subsection A.4.3.2.2.4 of Reference 4.3-4. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-2 4.3.2.3 Reactivity Coefficients

See Appendix A, subsection A.4.3.2.3 of Reference 4.3-4. 4.3.2.4 Control Requirements

See Appendix A, subsection A.4.3.2.4 of References 4.3-4. 4.3.2.4.1 Shutdown Reactivity

See Appendix A, subsection A.4.3.2.4.1 of Reference 4.3-4. The cold shutdown margin for the referen ce core loading pattern is provided in Reference 4.3-7. As discussed in Section 4.6.3.1.1.5 , the shutdown margin with the highest worth control rod withdrawn shall be analytically de termined to be at least 0.38% k/k or shall be determined by test to be at least 0.28% k/k. To ensure that the safety design basis for shutdown margin is satisfied, additional design margin is adopted during desi gn development so that a shutdown margin of at least 1.00% k/k is calculated with the highest worth control rod fully withdrawn.

4.3.2.4.2 Reactivity Variations

See Appendix A, subsection A.4.3.2.6 of Reference 4.3-4. The excess reactivity de signed into the core is contro lled by the control rod system supplemented by gadolinia-ura nia fuel rods (Reference 4.3-3). Control rods are used during the cycle partly to compensate for burnup and partly to control the power distribution.

Reactivity balances are not used in describing BWR beha vior because of the strong interdependence of the individua l constituents of reactivity. Therefore, th e design process does not produce components of a reactiv ity balance at the conditions of interest. Instead, it gives the keff representing all effects combined. Further, any listing of components of a reactivity balance is quite ambiguous unl ess the sequence of the cha nges is clearly defined.

4.3.2.5 Control Rod Patter ns and Reactivity Worths See References 4.3-1, 4.3-2 and 4.3-3. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-3 4.3.2.6 Criticality of Re actor During Refueling

See Appendix A, subsection A.4.3.2.6 of Reference 4.3-4. Compliance with Technical Specification shutdown margin re quirements is demonstrated through plant procedures and reactivity anal yses performed for reload specific refueling activities.

4.3.2.7 Stability

See Appendix A, subsection A.4.3.2.7 of Reference 4.3-4. 4.3.2.7.1 Xenon Transients

See Appendix A, subsection A.4.3.2.7.1 of Reference 4.3-4. 4.3.2.7.2 Thermal Hydraulic Stability

See Appendix A, subsection A.4.3.2.7.2 of Reference 4.3-4. 4.3.2.8 Vessel Irradiations

The reactor pressure vessel (RPV ) irradiation calculation provides a best-estimate prediction of the fluence rather than a conservative prediction as was the case with earlier methods. The methodology for the neutron flux calculation conforms to Licensing Topical Report (LTR) NEDC-32983-P-A (Reference 4.3-10). In general, the method ology described in the LTR adheres to the guidance in Regulatory Guide 1.190 for neutron flux evaluation and was approved by the U.S. NRC in th e Safety Evaluation Report (SER ) for referencing in licensing actions.

The fluence calculations are perf ormed with the DORTG01V discre te ordinates transport code. The LTR provides a description of the DORT cal culation used to determine the RPV fluence, as well as the calculations used to predict the measured dosimetry and validate the transport model. The calculational model includes a repres entation of the periphera l fuel assemblies and the core-internals, downcomer and vessel geomet ry. Calculations are performed to determine the bundle-average power distribution in the peri pheral fuel bundles for input to the DORT core neutron source. Calculati ons employ a relatively fine (r, , z) spatial mesh and are carried out using an S 12 angular quadrature set. The eighty-group MATXS cross section library is the basic nuclear data set. The cross secti on data used in these calculations is based on the ENDF/B-V nuclear data except for iron, hydrogen and oxygen. Since the cr oss sections for these elements have changed significantly in the more recent ENDF/B-VI data set, ENDF/B-VI cross sections were used for oxygen, hydrogen, and individua l iron isotopes. The cross section library is used in performing the energy and spatial self -shielding and removal COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-029 4.3-4 calculations. The scattering cross se ctions are represented using a P 3 Legendre expansion. The calculations are performed in azimuthal (r, ) and axial (r, z) geometries. A synthesis technique is used to determine the th ree-dimensional fluence distribution.

Figure 4.3-1 shows a quadrant of the core and the vess el internal component s that are relevant to the flux calculation (Reference 4.3-5). The reactor core is divided into three radial zones, based on the geometric layout of the bundles and their relative contribution to the shroud and RPV flux. The (r, ) analysis used the polar coordinates to define the calculation model as a planar sector between pre-selected reactor azimuths (typical ly 0° and 90°). Since the surveillance capsule is centered close to the midplane elevation of the core, core midplane data is assumed for the analysis. The model includes several material regions radially: three in-core regions, the bypass water region, shroud, downcomer water, jet-pump riser, jet-pump inlet mixer, surveillance capsule holder/bracket, and the RPV claddi ng and base metal.

The core model for the axial (r ,z) calculation is a cylinder simulating the cross-sectional area of the core at a pre-selected azimuth. For the capsule flux calcu lation, the (r,z) calculation was performed at the 300° azimuth, where the capsu le is located. For the shroud/RPV flux calculation, the azimuth of 24° was selected becaus e it is near the peak shroud flux and peak RPV flux. The core cylinder contains the afor e-mentioned three radial zones for each of the 25 axial fuel nodes. Each axial fuel node is sub-divi ded into bundle-depende nt radial regions so that each core region is modeled with its respective wate r density, structure material density, and actinide concentra tion. Similar to the (r, ) model, there are bypass water, shroud, downcomer water, a nd RPV regions beyond the core. Table 4.3-1 summarizes the neutron fluence results (Reference 4.3-5). Two sets of fluence data are presented: at th e end of 40 years (33.1 EFPY ), and at the end of 60 years (51.6 EFPY). Note EFPY is defined as 3323 MW t based effective full power years. The calculation of 33.1 EFPY factors in the uprated power (3486 MWt) from Cycle 11 through end of life (Reference 4.3-5). Fluence projections after Cycl e 17 include a 10% adder to bound potential variation in future cycles.

The RPV peak fluence (at 33.1 EFPY) given in Table 4.3-1 is used for development of the P-T limit curves. The peak 1/ 4 T fluence values (n/cm

2) used for P-T curve development are: 1.75E+17 for lower shell #1, 5.11E+17 for lo wer-intermediate sh ell #2, 2.81E+17 for N6 nozzle and 2.13E+17 for girth weld be tween shell #1 and shell #2 (Reference 4.3-6). The 1/4 T fluences were calculated in accordance with RG 1.99, Revision 2.

4.3.3 ANALYTICAL METHODS

See Appendix A, subsecti on A.4.3.3 of Reference 4.3-4. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-5 4.3.4 CHANGES

See Appendix A, subsecti on A.4.3.4 of Reference 4.3-4. 4.

3.5 REFERENCES

4.3-1 "GNF2 Advantage Generic complian ce with NEDE-24011-P-A (GESTAR II)," NEDC-33270P, (most recent vers ion referenced in COLR).

4.3-2 "GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II)," NEDC-32868P, (most recent vers ion referenced in COLR).

4.3-3 Reference Loading Pattern (most recent version referenced in COLR).

4.3-4 General Electric Sta ndard Application for Reactor Fuel, NEDE-24011-P-A, and Supplement for United States, NED E-24011-P-A-US (most recent approved version referenced in COLR).

4.3-5 GE Nuclear Energy, Washington Public Power Supply System WNP-2 RPV Surveillance Materials Testing and Analysis, Document No. GE-NE-B1301809-01, March 1997. GE Nuclear Energy, "Energy Northwest Columbia Generati ng Station Neutron Flux Evaluation," GE-NE-0000-0 023-5057-R0, April 2004.

4.3-6 GE Nuclear Energy, "Pressure-Temperature Curves for Energy Northwest Columbia," NEDC-33144-P (CVI CAL 1012-00,3).

4.3-7 Supplemental Reload Licensing Re port for Columbia (m ost recent version referenced in COLR).

4.3-8 Fuel Bundle Information Report for Co lumbia (most recent version referenced in COLR). 4.3-9 "Global Nuclear Fuels Fuel Bundle Designs," NED E-31152P, Revision 9, May 2007. 4.3-10 GE Nuclear Energy, "Licensing Topical Report, General Electric Methodoloty for Reactor Pressure Vessel Fast Neut ron Flux Evaluati ons," NEDC-32983-P-A, Revision 2, January 2006.

4.3-11 Deleted. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-6 4.3-12 GE Nuclear Energy, Washington Public Power Supply System Nuclear Project 2, "WNP-2 Power Uprate Transient Analysis Task Report,"

GE-NE-208-08-0393, September 1993.

4.3-13 GE Nuclear Energy, "Licensing Topical Report, General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations," NEDC-32983-P-A, December 2001.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 4.3-7 Table 4.3-1

Summary of Neutron Fluence Results Flux (n/cm 2-s) Fluence (n/cm

2) Cycle 10 Representative Future Cycle 40-year (33.1 EFPY)*

60-year (51.6 EFPY)* RPV At Midplane 6.92E+08 5.75E+08 6.77E+17 1.03E+18 At Peak Elevation 7.60E+08 6.27E+08 7.41E+17 1.12E+18 Peak/Midplane 1.10 1.09 1.09 1.09 Elevation for 10 17 fluence (inches above BAF) Bottom -3.3 -7.0 Top 156.2 160.0 Shroud At Midplane 1.81E+12 1.54E+12 1.80E+21 2.75E+21 At Peak Elevation 2.07E+12 1.73E+12 2.02E+21 3.06E+21 Peak/Midplane 1.15 1.12 1.12 1.11 Top Guide 2.08E+13 1.91E+13 2.15E+22 3.31E+22 Core Plate 3.39E+11 3.04E+11 3.46E+20 5.31E+20

• EFPY is defined as 3323 MWt ba sed effective full power years.

The calculation of 33.1 and 51.6 EFPY factors in the uprated power (3486 MWt) from Cycle 11 through End of Life (Reference 4.3-5). COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-8 Table 4.3-2

Reload Fuel Neutronic Design Values GE14 & GNF2 1 Fuel pellet Fuel material Density, g/cm 3 % of T.D. Diameter Enriched fuel Natural fuel Fuel rod Fuel length, full, in. Fuel length, partial, in. Cladding material Clad I.D., in. Clad O.D., in. Fuel assembly Number of fuel rods, full length Number of fuel rods, partial length Number of inert water rods Fuel rod enrichments Reference 4.3-8 Fuel rod pitch, in. Fuel assembly loading, kg uranium Reference 4.3-8 1 GNF2 and GE14 design values are provided in Table 2-1 of Reference 4.3-1. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-9 Table 4.3-3

Neutronic Design Values

Parameter Value Core data Number of fuel assemblies 764 Rated power, MWt 3486 Rated core flow, Mlbm/hr 108.5 Core inlet enthalpy, Btu/lbm 528.7 Reactor dome pressure, psia 1035 Fuel assembly pitch, in. 6.00 Control rod data a Absorber material B 4C Total blade span, in. 9.75 Total blade support span, in. 1.58 Blade thickness 0.260 Blade face-to-face internal dimension, in. 0.200 Absorber rods per blade 76 Absorber rods outside diameter, in. 0.188 Absorber rods inside diameter, in. 0.138 Absorber density, % of theoretical 70.0 a Original equipment control rods. Some of the control blades are replaced with Duralife 215 and Marathon control blades.

16304560090Shroud3RPVCapsuleJ/P RiserJ/P Mixer17181920212223242627252830I 151413121110987654321333333333333333333333333333233333333222222222222 222 222 222 222 222 222222 222222 221111111 11111111111 11111111111 11111111111 11111111111111 1111111111 111111111 11111111111 1111111 11111111111111111 111129960690.10 3JColumbia Generating Station Final Safety Analysis Report Core Layout and Vessel Internal ComponentsDraw. No.Rev.FigureAmendment 58 December 2005 4.3-1Form No. 960690FH LDCN-04-005 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-1 4.4 THERMAL-HYDRAULIC DESIGN

4.4.1 DESIGN BASES

4.4.1.1 Safety Design Bases

See Appendix A, subsection A.4.4.1.1 of Reference 4.4-1. 4.4.1.2 Requirements for Steady-State Conditions

See Appendix A, subsection A.4.4.1.2 of Reference 4.4-1. For purposes of maintaining adequate thermal margin during normal steady-state operation, the minimum critical power ratio (MCPR) must not be less than the required MCPR operating limit, and the maximum linear he at generation rate (MLHGR) mu st be maintained below the design linear heat generation rate (LHGR) for the plant. This does not specify the operating power nor does it specify peaking factors. These parameters are determined subject to a number of constraints including th e thermal limits given previously . The core and fuel design basis for steady-state operation (i.e., MCPR and LHGR limits) ha ve been defined to provide margin between the steady-state operating conditions and any fuel damage condition to accommodate uncertainties and to ensure that no fuel damage results even during the worst anticipated transient cond ition at any time in life.

4.4.1.3 Requirements for Anticipated Operational Occurrences (AOOs)

See Appendix A, subsection A.4.4.1.3 of Reference 4.4-1. 4.4.1.4 Summary of Design Bases

See Appendix A, subsection A.4.4.1.4 of Reference 4.4-1, and Reference 4.4-4. 4.4.2 DESCRIPTION OF THERMAL-HYDRAULIC DESIGN OF REACTOR CORE

See Appendix A, subsecti on A.4.4.2 of Reference 4.4-1. 4.4.2.1 Summary Comparison An evaluation of plant performa nce from a thermal and hydraulic standpoint is provided in Section 4.4.3. A tabulation of thermal and hydraulic parameters of the core is given in Table 4.4-1 . COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-2 4.4.2.2 Critical Power Ratio

See Appendix A, subsection A.4.4.2.2 of Reference 4.4-1, Reference 4.2-2 and Reference 4.2-3. 4.4.2.3 Linear Heat Generation Rate

See Appendix A, subsection A.4.4.2.3 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.2.4 Void Fraction Distribution

The void fraction exit values are provided in Table 4.4-2 . 4.4.2.5 Core Coolant Flow Dist ribution and Orificing Pattern

Correct distribution of core coolant flow among the fuel assemblies is accomplished by the orifices fixed at the inlet of each fuel assembly in the fuel support pieces . The orifices control the flow distribution and, hen ce, the coolant conditions within prescribed bounds throughout the design range of core operation. The sizing and design of the orifices ensure stable flow in each fuel assembly during normal operating conditions.

The core is divided into two or ifice flow zones. The outer z one is a narrow, reduced-power region around the core periphery. The inner zone is the core centr al region. No other flow or steam distribution, other than that provided by adjus ting power distribution with control rods, is used or needed.

4.4.2.5.1 Flow Distribution Data Comparison

Design core flow calculations were made using th e design power distributions. The flow distribution to the fuel assemblies was calcul ated based on the assump tion that the pressure drop across all of the fuel assemblies is the same. This a ssumption has been confirmed by measuring the flow distribution in BWRs. Therefore, there is a reasonable assurance that the calculated flow distribution throughout the core is in close agreement with the actual flow distribution (Reference 4.4-1). 4.4.2.5.2 Effect of Cha nnel Flow Uncertainties on the MCPR Uncertainty

The channel flow uncertainty has been inherently considered in its contribution to the MCPR

uncertainty when evaluating the probability of a fuel rod subject to a boiling transition in establishing the safety limit MCPR.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-3 The channel flow uncertainty is not an independent parameter cont ributing to the MCPR

uncertainty. Its effect has b een included in evaluating the pr obability of a boiling transition during a core wide power and flow calculation.

4.4.2.6 Core Pressure Drop and Hydraulic Loads

See Appendix A, subsection A.4.4.2.6 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.2.7 Correlation a nd Physical Data

See Appendix A, subsection A.4.4.2.7 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.2.8 Thermal Effects of Operational Transients

See Appendix A, subsection A.4.4.2.8 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.2.9 Uncertainties in Estimates

See Appendix A, subsecti on A.4.4.2.9 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-03-003 4.4-4 4.4.2.10 Flux Tilt Considerations

See Appendix A, subsection A.4.4.2.10 of Reference 4.4-1. 4.4.3 DESCRIPTION OF THE THERMA L AND HYDRAULIC DESIGN OF THE REACTOR COOLANT SYSTEM

4.4.3.1 Plant Configuration Data 4.4.3.1.1 Reactor Coolan t System Configuration The reactor coolant system is described in Section 5.4 and shown in isometric perspective in Figure 5.4-1 . The piping sizes, fittings , and valves are listed in Table 5.4-2 . 4.4.3.1.2 Reactor Coolant Syst em Thermal Hydraulic Data

The steady-state distribution of temperature, pressure, and flow rate for each flow path in the reactor coolant system is shown in Figure 5.1-1 . 4.4.3.1.3 Reactor Coolant System Geometric Data

Coolant volumes of regions and components within the reactor vessel are shown in

Figure 5.1-2 . Table 4.4-3 provides the flow path le ngth, height, liquid level, minimum elevations, and minimum flow areas for each major flow path volume within the reactor vessel and recirculation loops of the reactor coolant systems.

Table 4.4-4 provides the lengths and sizes of all safety injection lines to the reactor coolant system.

4.4.3.2 Operating Restrictions on Pumps

Expected recirculation pump performance curves are shown in Figures 5.4-2 and 5.4-7. These curves are valid for all conditions with a normal operating range varying from approximately 25% to 105% of rated pump flow.

The pump characteristics, including considerations of net positive suction head (NPSH) requirements, are the same for the conditions of two-pump and one-pump operation as described in Section 5.4.1. Subsection 4.4.3.3 gives the operating limits imposed on the recirculation pumps by cavitation, pump loads, bearing design flow starvation, and pump speed.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 4.4-5 4.4.3.3 Power-Flow Operating Map

4.4.3.3.1 Limits for Normal Operation

The power-flow operating map for the pow er range of operation is shown in Figure 4.4-1 . The boundaries of this map are as follows.

a. Natural circulation line: The operating state of the reactor moves along this line for the normal control rod withdrawal sequence in the absence of recirculation pump operation,

b. Maximum Extended Load Line Limi t Analysis (MELLLA)

Boundary: The line passes through 100% power at 80.7% core flow,

c. Rated power line: Constant 100% power line,

d. ICF line: Constant 106% increased core flow line, and

e. Pump cavitation interlock line: This line is required to protect either the recirculation pumps or the jet pumps from cavitation damage.

4.4.3.3.2 Regions of the Power-Flow Map

a. Region I This region defines the syst em startup operationa l capability with the recirculation pumps and motors being driven by the adjustable speed drives (ASDs). Flow is controlled by the variable speed pump, and power changes during normal startup and shutdown will be in this region;

b. Region II This is the low power area of the operating map where cavitation can be expected in the recirculation pumps and jet pumps.

Operation within this region is precluded by system interlocks that run back the pumps to minimum speed; and

c. Region III This represents the normal operating zone of the map where power changes can be made by either control rod movement or

by core flow changes through us e of the variable speed pumps. 4.4.3.3.3 Design Features for Power-Flow Control

The following limits and design features are employed to mainta in power-flow conditions to the required values shown in Figure 4.4-1

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 4.4-6 a. Minimum power limits at intermediate and high core flows. To prevent cavitation in the recirculation pumps and jet pumps, the recirculating system is provided with an interlock to run back the pump speed to 15 Hz if the difference between steam line temperature and recirculation pump inlet temperature is less than a preset value (10.7°F). This ac tion is initiated el ectronically through a time delay.

b. Minimum power limit at low core flow. During low power, low loop flow operations, the temperature differential interlock provides cav itation protection. Activation of the temperature differential interlock will run back the pump speed to 15 Hz. The ASD output speed/freque ncy is measured by instrumentation provided for monitoring the ASD. The speed change action is electronically initiated.

c. Pump bearing limit. For pumps as la rge as the recirculation pumps, practical limits of pump bearing desi gn require that minimum pu mp flow be limited to 25% of rated. To ensure this minimum flow, the system is designed so that the minimum pump speed will al low this rate of flow.

d. Valve position. To prevent structural or cavitation damage to the recirculation pump due to pump suction flow starvati on, the system is provided with an interlock to prevent starting the pumps or to trip the pumps if the suction or discharge block valves are at less than 90% open position. This circuit is activated by a position limit switch and is active before the pump is started, during individual loop manual control mode, or during ganged loop manual control.

The cavitation limits are establis hed for two-pump opera tion, but will not protect the jet pumps and recirculation pumps on one-pu mp operation. Therefore, a dditional procedural operational limits are established to prevent cavitation damage during th e single loop operation. One-pump operation is restricted to the Extended Load Line Limit Analysis (108% rodline) boundary because extended operation in the MELLLA domain has not been evaluated. The procedural operational limits are shown in Figure 4.4-2 . Flow Control. The principal modes of normal operation with ASD flow control are summarized as follows: The recirculation pumps are started when the suction and discharge block valves are full open; with the pump speed at 15 Hz the reactor heatup and pressurization can commence. When operating pressure has been established, reactor power can be increased. This power-flow increase will follow a line within Region I of the flow control map shown in Figure 4.4-1 . When reactor power is greater than approximately 20% of rated, the steam line to recirculation pump inlet differential temperature low feedwater flow interlock is cleared and the main

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 4.4-7 recirculation pump speed can be manually increased from 15 Hz. The system is then brought to the desired power-flow level within the normal operating area of the map (Region III) by individual loop control or manual ganged control of the ASD sy stem output frequency and by withdrawing control rods.

Recirculation pump speed increa ses resulting from ASD system output frequency increases toward 63 Hz with constant c ontrol rod position will result in power/flow changes along, or nearly parallel to, the 100% rod line.

4.4.3.4 Temperature-Po wer Operating Map Not applicable.

4.4.3.5 Load-Following Characteristics

The automatic load following featur e has been deleted from the system. All load increases or decreases on CGS are manually controlled by the operator.

4.4.3.6 Thermal and Hydraulic Characteristics Summary Table

The thermal-hydraulic charact eristics are provided in Table 4.4-1 for the core and tables of Section 5.4 for other portions of the reactor coolant system.

4.4.4 EVALUATION

See Appendix A, subsections A.4. 4.4 - A.4.4.4.5 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.4.1 Bypass Flow

Table 4.4-5 shows the bypass flows for the two cases of the GE14 and GNF2 core.

4.4.4.2 Thermal Hydraulic Stability Analysis

Core thermal-hydraulic analyses are performed in accordance with the Long-Term Stability Solutions Option III methodology descri bed in Reference 4.4-1. The analysis supporting the OPRM System Period Based Detec tion Algorithm (PBDA) setpoints is presented in Reference 4.4-4. A backup stability protection may be used on an interim basis as allowed by Technical Specifications. The analysis supporting the backup stability protection is presented in Reference 4.4-4, and the methods used in the backup stab ility protection analysis are presented in Reference 4.4-1. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-8 4.4.5 TESTING AND VERIFICATION

See Appendix A, subsecti on A.4.4.5 of Reference 4.4-1. 4.4.6 INSTRUMENTATION REQUIREMENTS

See Appendix A, subsecti on A.4.4.6 of Reference 4.4-1. 4.4.6.1 Loose Parts

The instrumentation for online monitoring for loose parts in the reactor vessel has been deactivated.

See Section 7.7.1.12 for further information.

4.

4.7 REFERENCES

4.4-1 General Electric Compa ny, General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A, and Supp lement for United States, NEDE-24011-P-A-US (most recent approved version re ferenced in COLR).

4.4-2 "GNF2 Advantage Generic Compliance with NEDE-24011-P-A (GESTAR II)," NEDC-33270P, (most recent vers ion referenced in COLR).

4.4-3 "GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II)," NEDC-32868P, (most recent vers ion referenced in COLR).

4.4-4 Supplemental Reload Licensing Repor t for Columbia (m ost recent version referenced in COLR).

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-029 4.4-9 4.4-9 GEXL97 Correlation Applicable to ATRIUM-10 Fu el, NEDC-33419P, Revision 0, June 2008.

4.4-10 Methodology and Uncertainties for Safety Limit MCPR Evaluations, NEDC-32601P-A, August 1999.

4.4-11 Power Distribution Uncertainties for Safety Limit MCPR Evaluations, NEDC-32694P-A, August 1999. 4.4-12 Fuel Bundle Information Report for Columbia (most recent version referenced in COLR).

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 4.4-11 Table 4.4-1 Thermal and Hydraulic Design Characteristics of the Reactor Core

General Operating C onditions Parameter Reference design thermal output, MWt 3486 Power level for engineered safety features, MWt 3716 Steam flow rate, at 421.2F final feedwater temperature, millions lb/hr 15.01 Core coolant flow rate range, millions lb/hr 87.6-115 Feedwater flow rate, millions lb/hr 14.98 System pressure, nominal in steam dome, psia 1035 Core exit pressure, nominal, psia 1047 Coolant saturation temperatur e at core design pressure, F 550 Average power density, kW/liter 51.56 Average linear heat generation rate, kW/ft 4.05 Core total heat transfer area, ft 2 86,099 Average heat flux, Btu/hr-ft 2 132,790 Design operating minimum critical power ratio (MCPR) (see COLR) a Core inlet enthalpy at 421.2F FFWT, Btu/lb 528.7 Core inlet temperature, at 421.2F FFWT, F 533.9 Power assembly exit void fraction, % (RPF=1.0) 71.2 Assembly flow, klbm/hr 120.4 b Core pressure drop, psid 23.437 b a Core Operating Limits Report. b Based on full core of GE14, (1035 psia dome pressure, 3486 MWt (100%) power and 108.5 Mlbm/hr (100% of rated core flow).

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-12 Table 4.4-2

Mixed Core Thermal Hydraulic Analysis Results a GE14 GNF2 Assembly flow (Klb/hr) 109.69 115.12 Exit quality (active region) 0.259 0.259 Exit void fraction 0.824 0.824 Critical power ratio b 1.575 1.671 a Core ~1/3 GNF2 fuel and 2/3 GE14 fuel 3545 MWt core power and 10 8.5 Mlbm/hr core flow. Values for a high power assembly

1.40 radial peaking factor.

b Estimates obtained using the GEXL critical power correlation (References 4.4-2 and 4.4-3). COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.4-13 Table 4.4-3 Reactor Coolant System Geometric Data

Flow Path Length (in.) Height and Liquid Level (in.) Elevation of Bottom of Each Volume a Minimum Flow Areas (ft2) Lower plenum 216 216 216 -172.5 71.5 Core 164 164 164 44.0 142.0 Upper plenum and

separators 178 178 178 208.0 49.5 Dome (above normal

water level) 312 312 0 386.0 343.5 Downcomer area 321 321 321 -51.0 79.5 Recirculation loops and

jet pumps (one loop) 108.5 ft 403 403 -394.5 132.5 in2 a Reference point is recircu lation nozzle outlet centerline.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.4-14 Table 4.4-4 Lengths and Sizes of Safety Injection Lines

Line O.D. (in.) Line Length (ft) HPCS line Pump discharge to valv ea 16 319 From HPCS-V-4 inside con tainment to RPV 12.75 108 Total 427 LPCI lines Loop A 1. Pump d ischarge to reducer 18 421 2. Reducer to injection valve, a RHR-V-42A 14 6 3. From RHR-V-42A to RPV 14 94 Total 521 Loop B 1. Pump d ischarge to reducer 18 394 2. Reducer to inject ion valve RHR-V-42B 14 6

3. Inside containment to RPV 14 93 Total 493 Loop C 1. Pump d ischarge to reducer 18 71

2. Reducer to inject ion valve RHR-V-42C 14 138

3. Inside containment to RPV 14 99 Total 308 LPCS line Pump discharge to valv ea 16 222 Inside containment to RPV 12.75 117 Total 339 a Injection valve located as near as possible to outside of c ontainment wall.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-15 Table 4.4-5 a,b Core Pressure Drop and Leakage Flow Results for Core Configurations Case Core Pressure Drop (psid) Core Bypass Flow (%) 1: All GE14 core 24.403 11.7 2: All GNF2 core 23.626 11.1 a Core power: 3545 MWt; core flow: 108.5 Mlb/hr. b Including both leakage flow and water rod flow.

FigureAmendment 63 December 2015 Form No. 960690 LDCN-10-004 Draw. No. Rev.960690.03 4.4-11Columbia Generating Station Final Safety Analysis Report Power-Flow Operating Map Two Loop Operation 0010203040506070809010011012040003500CDEFGHBAI300025002000150010005000102030405060 Core Flow (% of Rated) Core Flow (Mlbm/hr)7080901001101200102030405060708090100110120130Thermal Power (% of Rated) Thermal Power (MWt) Region IJet Pump Cavitation InterlockMinimumPump Speed Increased Core Flow RegionNatural Circulation Flow Line MELLLABoundaryRegion IIIRegion II100% Power = 3486 Mwt100% Core Flow = 108.5 Mlbm/hr A: B: C: D: E: F: G: H: I:49.4% Power/ 23.8% Flow 57.5% Power/ 32.3% Flow100.0% Power/ 80.7% Flow100.0% Power/100.0% Flow 100.0% Power/106.0% Flow65.1% Power/106.0% Flow 60.4% Power/100.0% Flow33.0% Power/ 65.4% Flow 14.6% Power/ 30.4% Flow FigureAmendment 59 December 2007 Form No. 960690 LDCN-07-011 Draw. No. Rev.060108.05 4.4-2Columbia Generating Station Final Safety Analysis Report Power-Flow Operating Map Single Loop Operation 01020 30 40 506070 8090010203040506070Percent Thermal Power(Rated Thermal Power = 3486 MWth)Percent Core Flow (Rated Core Flow = 108.5 Mlb/hr)NaturalCirculationFlow LineMinimum Pump S peedPump Cavitati on Interlock LineExtended Load Line Limit(108% Rod Line)Procedural Operati on Limit(Jet Pump Nozzle Cavitati on Line) COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-086 4.5-1 4.5 REACTOR MATERIALS

4.5.1 CONTROL ROD SYSTEM STRUCTURAL MATERIALS

4.5.1.1 Material Specifications

The following material listing applies to the c ontrol rod drive (CRD) mechanism supplied for this application. The position indicator and minor nonstructural items are omitted.

a. Cylinder, tube, and flange assembly Flange ASME SA 182 grade F304

Housing cap screws ASME SA 540 g rade B23, CL4 or SA 193 grade B7

Plugs ASME SA 182 grade F304

Cylinder ASTM A269 grade TP 304

Outer tube ASTM A269 grade TP 304

Tube ASTM A269 grade TP 304

Spacer ASTM A269 grade TP 304 or ASTM A511 grade MT 304

b. Piston tube assembly Piston tube ASTM A269 grade TP 304 or ASTM A479 grade XM-19

Stud ASTM A276 type 304

Head/base ASME SA 182 grade F304

Indicator tube ASME SA 312 type 316

Cap ASME SA 182 grade F304 or TP 316

c. Drive assembly Coupling spud Inconel X-750

Index tube ASTM A269 grade TP 304 or ASTM A479 grade XM-19 COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-086 4.5-2 Piston head Armco 17-4 PH

Coupling ASME SA 312 grade TP 304 or ASTM A511 grade MT 304

Magnet housing ASME SA 312 grade TP 304 or ASTM A511 grade MT 304

d. Collet assembly Collet piston ASTM A269 grade TP 304 or ASME SA 312 grade TP 304

Finger Inconel X-750

Retainer ASTM A269 grade TP 304 or ASTM A511 grade MT 304

Guide cap ASTM A269 grade TP 304

e. Miscellaneous parts Stop piston ASTM A276 type 304

Connector ASTM A276 type 304

O-ring spacer ASME SA 240 type 304

Piston tube nut ASME SA 194 grade B8 or B8A or SA 479 grade XM-19

Barrel ASTM A269 grade TP 304 or ASME SA 312 grade TP 304 or ASME SA 240 type 304

Collet spring Inconel X-750

Ring flange ASME SA 182 grade F304

Ring flange cap ASME SA 193 grade B6 screws The materials listed under ASTM specification numbers are all in the annealed condition (with

the exception of the outer tube in the cylinder, tube, and flange assemb ly), and their properties COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-086 4.5-3 are readily available. The outer tube is appr oximately 1/8 hard and ha s a tensile strength of 90,000/125,000 psi, yield strength of 50,000/85, 000 psi, and minimu m elongation of 25%.

The coupling spud, collet fingers, and collet spri ng are fabricated from Inconel X-750 in the annealed or equalized condition and heat treat ed to produce a tensile strength of 165,000 psi minimum, yield of 105,000 psi minimum, and elongation of 20% minimum. The piston head is Armco 17-4 PH in condition H-1100, with a tensile strength of 140, 000 psi minimum, yield of 115,000 psi minimum, and elongation of 15% minimum.

These are widely used materials, whose prope rties are well known. The parts are readily accessible for inspection and replacement if necessary.

4.5.1.2 Special Materials

No cold-worked austenitic stainless steels with a yield strength greater than 90,000 psi are employed in the CRD system. Armco 17-4 PH (p recipitation hardened stainless steel) is used for the piston head. This material is aged to the H-1100 condition to produce resistance to stress corrosion cracking in the BWR environments. Armco 17-4 PH (H-1100) has been

successfully used in the past in BWR drive mechanisms. Th e only hardenable martensitic stainless steel used is the ring flange cap screws. The material is TP 410 in the H-1100 condition.

4.5.1.3 Processes, Inspections, and Tests

All austenitic stainless steel used in the CRD sy stem is solution annealed material with one exception, the outer tube in the cylinder, tube, and flange assembly (see Section 4.5.1.1). Proper solution annealing is verified by testing per ASTM A262, "Recommended Practices for

Detecting Susceptibility to Intergranul ar Attack in Stainless Steels."

Two special processes are employed which subject selected components to temperatures in the

sensitization range. These processes are perf ormed on austenitic stainless steel, including XM-19.

a. The cylinder (cylinder, tube, and fla nge assembly) and the retainer (collet assembly) are hard surfaced with Colmonoy 6.

b. The following components are nitrided to provide a wear resistant surface:

1. Tube (cylinder, tube

, and flange assembly) 2. Piston tube (piston tube assembly)

3. Index tube (drive line assembly)

4. Collet piston and guide cap (collet assembly)

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 4.5-4 Colmonoy hard-surfaced component s have performed successfully in the past in drive mechanisms. Nitrided compone nts have accumulated many years of BWR service. It is normal practice to remove some CRDs periodica lly during refueling outages. At this time, both the Colmonoy hard-surfaced parts and n itrided surfaces are accessible for visual examination. In addition, dye penetrant ex aminations have been performed on nitrided surfaces of the longest service drives. This inspection program is adequate to detect any incipient defects before they could become serious enough to cause operating problems. All austenitic stainless steel is required to be in the solution heat treated condition. Welding is performed in accordance with Section IX of the ASME Boiler and Pressure Vessel (B&PV) Code. Heat input for stainless-steel welds is restricted to a maximum of 50,000 joules/in. and interpass temperature to 350°F. Heating above 800°F (except for welding) is prohibited unless the welds are subsequently solution annealed. These controls are employed to avoid

severe sensitization and comply with the intent of Regulatory Guide 1.44.

4.5.1.4 Control of De lta Ferrite Content

All type 308 weld metal is required to comply with a specification which requires a minimum of 5% delta ferrite. This amount of ferrite is adequate to prevent any micro-fissuring (hot

cracking) in austenitic stainless steel welds. (See Section 4.5.2.4.) 4.5.1.5 Protection of Materials During Fabrication, Shipping, and Storage

All the CRD parts listed in Section 4.5.1.1 are fabricated under a process specification which limits contaminants in cutting, gr inding, and tapping cool ants and lubricants. It also restricts all other processing materials (marking inks, tape, etc.) to those which are completely removable by the applied cleaning process. All contaminants are then required to be removed by the appropriate cleaning process prior to any of the following:

a. Any processing which increases part temperature above 200°F, b. Assembly which results in decr ease of accessibility for cleaning, and c. Release of parts for shipment.

The specification for packaging and shi pping the CRD provides for the following:

The drive is rinsed in hot deionized water and dried in preparation for shipment. The ends of

the drive are then covered with a vapor tight ba rrier with desiccant. Packaging is designed to protect the drive and prevent damage to th e vapor barrier. The planned storage period considered in the design of the container and packaging is 2 years. This packaging has been in use for a number of years. Periodic audits have indicated satisfactory protection. The degree of surface cleanliness required by th ese procedures meets the requirements of Regulatory Guide 1.37. COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-11-040 4.5-5 Site or warehouse storage specifications require in side heated storage comp arable to level B of ANSI 45.2.2. After the second year, a yearly inspection of 10% of the humidity indicators (packaged with the drives) is required to verify that the units are dry.

4.5.2 REACTOR INTERNAL MATERIALS

4.5.2.1 Material Specifications

Materials used for the core support structure:

a. Shroud support - Nickel chrome iron alloy, ASME SB166 or SB168,

b. Shroud, core plate (and aligners),

top guide (and aligne rs), and internal structures welded to these compone nts, ASME SA240, SA182, SA479, SA312, SA249, or SA213 (all type 304, except the shroud which is 304L),

c. Peripheral fuel s upports - SA312 type 304,

d. Core plate studs and nuts. SA193 grade B8, SA194 grade 8 (all type 304),

e. Control rod drive housing. AS ME SA312 type 304, SA182 type 304,

f. Control rod drive guide tube. AS ME SA351 type CF8, SA358. SA312, SA249 (type 304), and

g. Orificed fuel support. ASME SA351 type CF8.

Materials used in the steam separators and steam dryers:

a. All materials are type 304 stainless steel,

b. Plate, sheet, and strip ASTM A240, type 304,

c. Forgings ASTM A182, grade F304,

d. Bars ASTM A479, type 304,

e. Pipe ASTM A312, grade TP 304,

f. Tube ASTM A269, grade TP 304,

g. Bolting material ASTM A193, grade B8,

h. Nuts ASTM A194, grade 8, and

i. Castings ASTM A351, grade CF8.

Materials used in the jet pump assemblies:

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-06-000 4.5-6 The components in the jet pump assemblies are a ri ser, restrainer brackets, inlet-mixers, slip joint clamps, diffusers, and a riser brace. Materials used for these components are to the

following specifications:

a. Castings ASTM A351 grade CF 8 and ASME SA351 grade CF3,

b. Bars ASTM A276 type 304 and ASTM A370 grade E38 and E55,

c. Bolts ASTM A193 grade B8 or B8M,

d. Sheet and plate ASTM A240 t ype 304, ASTM A276 type 304, ASTM A358, and ASME SA240 type 304L,

e. Tubing ASTM A269 grade TP 304,

f. Pipe ASTM A358 type 304 and ASME SA312 grade TP 304,

g. Welded fittings ASTM A403 grade WP304, and

h. Forgings ASME SA182 grade F304, ASTM B166, and ASTM A637 grade 688.

Materials in the jet pump assemblies which are not type 304 stainless steel are listed below:

a. The inlet mixer adapter casting, the wedge casting, bracket casting adjusting screw casting, and the diffuser collar cas ting are type 304 hard-surfaced with Stellite 6 for slip fit joints;

b. The diffuser is a bimetallic component made by welding a type 304 forged ring to a forged Inconel 600 ring, ma de to Specification ASTM B166;

c. The inlet-mixer contains a pin, inse rts and beam made of Inconel X-750 to Specification ASTM B637 grade UNS N07750 (Beam), and ASTM A370 grade

E38 and E55 (pin and insert);

d. The jet pump beam bolt is type 316L stainless steel;

e. The jet pump slip joint clamp body is fabricated from solution heat-treated ASTM A-182/ASME SA-182 Grade F XM-19 stainless steel with a maximum of 0.04% carbon;

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-06-000 4.5-7 f. The jet pump slip joint clamp adjustable bolt, bolt retainer, pins, and ratchet lock spring are fabricated from ASTM B-637/ASME SB-637 UNS N07750

Type 3 (Alloy X-750); and

g. All components of jet pump restrainer bracket auxiliary wedge assemblies are fabricated from ASTM B-637 UNS N07750 Type 3 (Alloy X-750), except for

the frame.

All core support structures are fabricated from ASME specified materi als and designed using ASME Code Section III, Appendix I allowable st resses, and ASME Code Section III, Class I, reactor vessel design rules as guides. The othe r reactor internals are fabricated from ASTM specification materials. Material requirements in the ASTM specificati ons are identical to requirements in corresponding ASME material specifications. The allowable stress levels

specified in ASME Code Section III, Appendix I, are used as a guide in the design of all internal structures in the reactor.

4.5.2.2 Controls on Welding

For core support structures and other internals, weld procedures and welders are qualified in accordance with the ASME B&PV Code, Section IX.

4.5.2.3 Nondestructive Examination of Wrought Seamless Tubular Products

Wrought seamless tubular products are used in the fabrication of the CRD housing. This

ASME Code Section III component is designed to the rules of S ubsection NB, and the material specified is ASME SA-312 supplemented by GE specifications which invoke Subsection NB requirements. This material meets the requi rements of NB-2550 and meets the intent of Regulatory Guide 1.66. The CRD housings are built to the 1971 Edition, Summer 1971 Addenda of the code.

Other internal non-code safety and non-safety components are optionally fabricated from wrought seamless tubular products. This material is supplied in accordance with the applicable ASTM material specifications and is nondestructively examined to th e extent specified therein. In addition, the specification for tubular produc ts employed for CRD housings external to the

reactor pressure vessel (RPV) meet requirement s of paragraph NB-2550 which meets the intent of Regulatory Guide 1.66.

Other internals are non-coded, and wrought seamless tubular products were supplied in accordance with the applicable AS TM material specifications. These specifications require a hydrostatic test on each length of tubing.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 4.5-8 4.5.2.4 Fabrication and Pro cessing of Austenitic Stainless Steel - Regulatory Guide Conformance Regulatory Guide 1.31, Control of Stainless Steel Welding All austenitic stainless steel weld filler materi als were supplied with a minimum of 5% delta ferrite. This amount of ferrite is considered adequate to prevent micro-fissuring in austenitic stainless steel welds. An extensive test program performed by Gene ral Electric Company, with the concurrence of the Regulatory Staff, has demonstrated that controlling weld filler metal ferrite at 5% minimum produces produc tion welds which meet the requirements of Regulatory Guide 1.31. A total of approxima tely 400 production welds in five BWR plants were measured and all welds met the require ments of the Interim Regulatory Position to Regulatory Guide 1.31.

Regulatory Guide 1.34, Control of Electroslag Weld Properties.

Electroslag welding is not empl oyed for any reactor internals.

Regulatory Guide 1.36, Nonmetallic Thermal Insulation for Austenitic Stainless Steel.

Nonmetallic thermal insulation is not employed fo r any components in the reactor vessel. For external applications, all nonmetallic insu lation meets the requirements of Regulatory Guide 1.36.

Regulatory Guide 1.44, Control of th e Use of Sensitized Stainless Steel.

All wrought austenitic stainless steel was solu tion heat treated. Heating above 800°F was prohibited (except for welding) unless the stainl ess steel was subsequently solution annealed. Purchase specifications restricted the maximum weld heat input to 110,000 joules per in., and the weld interpass temperature to 350°F maximum. Welding was performed in accordance

with Section IX of the ASME B&PV Code S ection IX. These controls were employed to avoid severe sensitization a nd comply with the intent of Regulatory Guide 1.44.

Regulatory Guide 1.71, Welder Qualifi cation for Areas of Limited Accessibility

Welder qualification for areas of limited accessibility is discussed in Sections 1.8.2 and 1.8.3. 4.5.2.5 Contamination, Pr otection, and Cleaning of Austenitic Stainless Steel

Exposure to contaminant was avoided by caref ully controlling all cleaning and processing materials which contact stainless steel during manufacture and constructi on. Any inadvertent surface contamination was removed to avoid potential detrimental effects.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 4.5-9 Special care was exercised to ensure removal of surface contaminants prior to any heating operation. Water quality for ri nsing, flushing, a nd testing was contro lled and monitored. The degree of cleanliness required by these procedures meets the requirements of Regulatory

Guide 1.37.

4.5.3 CONTROL ROD DRIVE HOUSING SUPPORTS

The American Institute of Steel Construc tion (AISC) Manual of Steel Construction, "Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings," was

used in designing the CRD housing support system . However, to provide a structure that absorbs as much energy as practical without yielding, the allowa ble tension and bending stresses used were 90% of yield and the shear stress used was 60% of yield. These design stresses are 1.5 times the AISC allowable stre sses (60% and 40% of yield, respectively).

For purposes of mechanical design, the postulated failure resulting in the highest forces is an instantaneous circumferential se paration of the CRD housing from the reactor vessel, with the reactor at an operating pressure of 1086 psig (a t the bottom of the vessel) acting on the area of the separated housing. The weight of the se parated housing, CRD, and blade, plus the pressure of 1086 psig acting on the area of the separated housing, gives a force of approximately 32,000 lb. This force is used to calculate the impact force, conservatively assuming that the housing travels through a 1-in . gap before it contacts the supports. The impact force (109,000 lb) is then treated as a static load in design. The CRD housing supports are designed as Seismic Category I e quipment in accordance with Section 3.2. All CRD housing support subassemblies are fabricated of ASTM A36 structural steel, except

for the following items:

a. Grid ASTM A441,

b. Disc springs Schne rr, type BS-125-71-8, c. Hex bolts and nuts ASTM A307, and d. 6 x 4 x 3/8 tubes ASTM A500 grade B.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-1 4.6 FUNCTIONAL DESIGN OF REACTIVITY CONTROL SYSTEMS Functional design of the contro l rod drive (CRD) system is discussed below. Functional designs of the recirculation flow control syst em and the standby liqui d control (SLC) system are described in Sections 5.4.1 and 9.3.5, respectively.

4.6.1 INFORMATION FOR THE CONTROL ROD DRIVE SYSTEM

4.6.1.1 Control Rod Drive System Design

4.6.1.1.1 Design Bases

4.6.1.1.1.1 Safety Design Bases . The CRD mechanical system meets the following safety design bases:

a. The design provides for a sufficiently rapid control rod insertion that no fuel damage results from any a bnormal operating transient.

b. The design includes positioning devices, each of which individually supports and positions a control rod.

c. Each positioning device

1. Prevents its control ro d from initiating withdrawal as a result of a single malfunction,

2. Is individually operated so that a failure in one positioning device does not affect the operation of any other positioning device, and

3. Is individually energized when ra pid control rod insertion (scram) is signaled so that failure of power sources external to the positioning device does not prevent other positi oning devices' control rods from being inserted.

4.6.1.1.1.2 Power Ge neration Design Basis. The CRD system design provides for positioning the control rods to control power generation in the core.

4.6.1.1.2 Description

The CRD system controls gross changes in co re reactivity by incrementally positioning neutron absorbing control rods within the reactor core in response to manua l control signals. It is also required to quickly shut down the reactor (scram) in emergency situations by rapidly inserting withdrawn control rods into the core in response to a manual or automatic signal. The CRD COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-2 system consists of locking piston CRD mechanisms, and the CRD hydraulic system (including power supply and regulation, hydraulic cont rol units (HCUs), interconnecting piping, instrumentation and electrical controls).

4.6.1.1.2.1 Control Rod Drive Mechanisms . The CRD mechanis m (drive) used for positioning the control rod in the reactor core is a double-acting, mechanically latched, hydraulic cylinder using w ater as its operating f luid (see Figures 4.6-1 through 4.6-4). The individual drives are mounted on the bottom head of the reactor pressure vessel (RPV). The drives do not interfere with refueling and are operative even when the head is removed from the RPV.

The drives are also readily accessible for inspection and servic ing. The bottom location makes maximum utilization of the water in the reactor as a neutron shie ld and gives the least possible neutron exposure to the drive components. Using water from the condensate treatment system and/or condensate storage tanks as the operating fluid eliminates the need for special hydraulic fluid. Drives are able to utilize simple pi ston seals whose leakage does not contaminate the reactor water but provides cooling for the drive mechanisms and their seals.

The drives are capable of inserting or withdrawing a control rod at a slow, controlled rate, as well as providing rapid inserti on when required. A mechanism on the drive locks the control rod at 6-in. increments of str oke over the length of the core.

A coupling spud at the t op end of the drive index tube (piston rod) engages and locks into a mating socket at the base of th e control rod. The weight of the control rod is sufficient to engage and lock this coupling. Once locked, the drive and rod form an inte gral unit that must be manually unlocked by specific procedures before the components can be separated.

The drive holds its control rod in distinct latch positions until the hydr aulic system actuates movement to a new position. Withdrawal of each rod is limited by a seating of the rod in its guide tube. Withdrawal beyond this position to the over-travel limit can be accomplished only if the rod and drive are uncoupled. Withdrawal to the over-travel lim it is annunciated by an alarm.

The individual rod indicators, grouped in one control panel display, correspond to relative rod locations in the core. A separate, smaller display is located ju st below the large display on the vertical part of the benchboard. This display presents the positi ons of the control rod selected for movement and the other rods in the affected rod group.

For display purposes the control r ods are considered in groups of four adjacent rods centered

around a common core volume. Each group is monitored by four local power range monitor (LPRM) strings (see Section 7.6.1.4). Rod groups at the periphery of the core may have less than four rods. The small rod display shows th e positions, in digital form , of the rods in the COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-3 group to which the selected rod belongs. A white light indicates which of the four rods is the one selected for movement.

4.6.1.1.2.2 Drive Components . Figure 4.6-2 illustrates the op erating principle of a drive. Figures 4.6-3 and 4.6-4 illustrate the drive in more detail. The main components of the drive and their functions ar e described below.

4.6.1.1.2.2.1 Drive Piston . The drive piston is mounted at the lower end of the index tube. This tube functions as a pist on. The drive piston and index tube make up the main moving assembly in the drive. The drive piston ope rates between positive end stops, with a hydraulic cushion provided at the upper e nd only. The piston has both insi de and outside seal rings and operates in an annular space between an inne r cylinder (fixed piston tube) and an outer cylinder (drive cylinder). Because the type of inner seal used is effective in only one direction, the lower sets of seal rings are m ounted with one set sea ling in each direction.

A pair of nonmetallic bushings prevents metal-to-metal contact between the piston assembly and the inner cylinder surface. The outer pist on rings are segmented step-cut seals with expander springs holding the segm ents against the cylinder wall. A pair of split bushings on the outside of the piston preven ts piston contact with the cyli nder wall. The effective piston area for down-travel or withdrawal is approximately 1.2 in. 2 versus 4.1 in. 2 for up-travel or insertion. This difference in driving area tends to balance the control rod weight and ensures a higher force for insertion than for withdrawal.

4.6.1.1.2.2.2 Index Tube. The index tube is a long hollow shaft made of nitrided stainless steel. Circumferentia l locking grooves, spaced every 6 in. along the outer surface, transmit the weight of the control rod to the collet assembly.

4.6.1.1.2.2.3 Collet Assembly. The collet assembly serves as the index tube locking mechanism. It is located in the upper part of the drive unit. This assembly prevents the index tube from accidentally moving downward. The assembly consists of the collet fingers, a return spring, a guide cap, a collet housing (par t of the cylinder, tube, and flange), and the collet piston.

Locking is accomplished by fingers mounted on the collet piston at the top of the drive cylinder. In the locked or latched position the fingers engage a locki ng groove in the index tube.

The collet piston is normally held in the latc hed position by a force of approximately 150 lb supplied by a spring. Metal pist on rings are used to seal the collet piston from reactor vessel pressure. The collet assembly will not unlatch until the collet fingers are unloa ded by a short, automatically sequenced, drive-in signal. A pressure, approxim ately 180 psi force, slide the collet up against the conical surfac e in the guide cap, and spread the fingers out so they do not engage a locking groove. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-4 A guide cap is fixed in the upper end of the drive assembly. This member provides the unlocking cam surface for the collet fingers and serves as the upper bushi ng for the index tube.

If reactor water is used durin g a scram to supplement accumu lator pressure, it is drawn through a filter on the guide cap.

4.6.1.1.2.2.4 Piston Tube. The piston tube is an inner cylinder, or column, extending upward inside the drive piston and index tube. Th e piston tube is fixed to the bottom flange of the drive and remains stationary. Water is brought to the upper side of the drive piston through this tube. A buffer shaft, at the uppe r end of the piston tube , supports the stop piston and buffer components.

4.6.1.1.2.2.5 Stop Piston . A stationary piston, called the stop piston, is mounted on the upper end of the piston tube. This piston provides the seal between reactor vessel pressure and the space above the drive piston. It also functi ons as a positive end stop at the upper limit of control rod travel. Piston ri ngs and bushings, simila r to those used on the drive piston, are mounted on the upper portion of the stop piston. The lower end of the stop piston is threaded on to the top of the piston tube forming a spac e for a set of spring washers which serve to protect both the drive piston and the stop piston from damage as the dr ive piston reaches its end of travel. The upper end of the piston tube has a series of orific es which hydraulically dampen the drive piston motion as the inner seals (or buffer seals) slide past them, effectively cutting off the exhaust path for the over-piston water. The high pressu res generated in the buffer are confined to the cyli nder portion of the stop piston, a nd are not applied to the stop piston and drive piston seals.

The center tube of the drive mechanism forms a well to contain the position indicator probe. The probe is an aluminum extrusion attached to a cast aluminum housing. Mounted on the extrusion are hermetically sealed, magnetically operated, positi on indicator switches. The entire probe assembly is protected by a thin-walled stainless steel tube. The switches are actuated by a ring magnet located at the bottom of the drive piston.

The drive piston, piston tube, and indicator t ube are all of nonmagnetic stainless steel, allowing the individual switches to be operated by the magnet as the piston passes. Two switches are located at each position corresponding to an index tube groove, thus allowing redundant indication at each la tching point. Two additional switches are located at each midpoint between latching points to indicate the intermediate positions during drive motion. Thus, indication is provi ded for each 3 in. of travel. Duplicate switches are provided for the full-in and full-out positions. Redundant over-travel switches are located at a position below the normal full-out position. Because the limit of down-travel is normally provided by the control rod itself as it reaches the backseat pos ition, the drive can pass this position and actuate the over-travel switches only if it is uncoupled from its contro l rod. A convenient means is COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-5 thus provided to verify that the drive and control rod are coupled after installation of a drive or at any time during plant operation.

4.6.1.1.2.2.6 Flange and Cylinder Assembly . A flange and cylinder a ssembly is made up of a heavy flange welded to the drive cylinder. A sealing surface on the upper face of this flange forms the seal to the drive housing flange. Th e seals contain reactor pressure and the two hydraulic control pressures. Tefl on coated, stainless steel rings ar e used for these seals. The drive flange contains the integral ball, or two-way, check (ball-shuttle ) valve. This valve directs either the reactor vessel pressure or the driving pressure , whichever is higher, to the underside of the drive piston. Reactor vessel pressure is admitted to this valve from the annular space between the drive and drive housing throug h passages in the flange.

Water used to operate the collet piston passes between the outer tube and the cylinder tube. The inside of the cylinder tube is honed to provide the surface required for the drive piston seals.

Both the cylinder tube and outer tube are welded to the drive flange. The upper ends of these tubes have a sliding fit to allow for different ial expansion.

4.6.1.1.2.2.7 Lock Plug . The upper end of the index tube is threaded to receive a coupling spud. The coupling (see Figure 4.6-1 ) accommod ates a small amount of angular misalignment between the drive and the control rod. Six spring fingers allow the coupling spud to enter the mating socket on the control rod. A plug th en enters the spud a nd prevents uncoupling.

Two means of uncoupling are provided. With th e reactor vessel head removed, the lock plug can be raised against the spring force of appr oximately 50 lb by a rod extending up through the center of the control rod to an unlocking handle located above the control rod velocity limiter. The control rod, with the lock plug raised, can then be lifted from the drive.

The lock plug can also be pushed up from below, if it is desired to uncouple a drive without removing the RPV head for access. In this case, the central por tion of the drive mechanism is pushed up against the uncoupling rod assembly, which raises th e lock plug and allows the coupling spud to disengage the socket as the drive piston and index tube are driven down.

The control rod is heavy enough to force the spud fingers to enter the so cket and push the lock plug up, allowing the spud to enter the socket completely and the plug to snap back into place. Therefore, the drive can be coupled to the control rod using only the weight of the control rod. However, with the lock plug in place, a force in excess of 50, 000 lb is required to pull the coupling apart.

4.6.1.1.2.3 Materi als of Construction. Factors that determine the choice of construction materials are discussed in the following subsections.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-6 4.6.1.1.2.3.1 Index Tube. The index tube must withstand the locking and unlocking action of the collet fingers. A compatible bearing combination must be provided that is able to withstand moderate misalignment forces. The reactor environment limits the choice of materials suitable for corrosion resi stance. The column and tensile loads can be satisfied by an annealed, single phase, nitrogen stre ngthened, austenitic stainless steel. The wear and bearing requirements are provided by malc omizing the complete tube. To obtain suitable corrosion resistance, a carefully controlled proces s of surface preparation is employed.

4.6.1.1.2.3.2 Coupling Spud. The coupling spud is made of Inconel 750 that is aged for maximum physical strength and the required corrosion resistance. Because misalignment tends to cause chafing in the semispherical contact area, the part is protected by a thin chromium plating (electrolized). This pl ating also prevents galling of th e threads attaching the coupling spud to the index tube.

4.6.1.1.2.3.3 Collet Fingers. Inconel 750 is used for the colle t fingers, which must function as leaf springs when cammed open to the unlocked position. Colmonoy 6 hard facing provides a long-wearing surface, adequate for design life, to the area contacting the index tube and unlocking cam surface of the guide cap.

Experience at some operating boili ng water reactors (BWR) indicates that failures can occur in the collet fingers of the CRD mechanism. To resolve this problem, some BWR facilities installed a revised collet retainer design. However, CGS does not ha ve the revised collet retainer design. General Elec tric (GE) has demons trated by testing a nd operating experience that the existing CRDs meet all safety and licensing requirements and are expected to give full life performances. However, as a result of examining operating driv es, GE has discovered evidence of intergranular stre ss corrosion cracking (IGSCC) in some CRD drive components and has made design impr ovements to preclude IGSCC in the future. The spare parts for CRD components purchased by Energy Northwest incorpor ate this revised design. Along with the other parts of the drive, the collet retainer t ube, piston tube, and index tube will be routinely checked and changed out, if necessary, with the parts incorporating the revised design.

4.6.1.1.2.3.4 Seals and Bushings. Carbon Graphite material is selected for seals and bushings on the drive piston and stop piston. The material is inert, has a low friction coefficient when water-lubricated and is resist ant to degradation at high temperatures. The Carbon Graphite material is relatively soft, wh ich is advantageous when an occasional particle of foreign matter reaches a seal. The resulting scratches in the seal redu ce sealing effici ency until worn smooth, but the drive design can tolerate considerable water leakage past the seals into the reactor vessel.

4.6.1.1.2.3.5 Summary. All drive components exposed to reac tor vessel water are made of austenitic stainless steel except the following:

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-7 a. Seals and bushings on the drive piston and stop piston are Carbon Graphite

material,

b. All springs and members requiring spri ng action (collet fingers, coupling spud, and spring washers) are made of Inconel-750,

c. The ball check valve is a Ha ynes Stellite cobalt-base alloy,

d. Elastomeric O-ring s eals are ethylene propylene,

e. Metal piston rings are Haynes 25 alloy,

f. Certain wear surfaces are hard faced with Colmonoy 6,

g. Nitriding by a proprietary new malcomizing process and chromium plating are used in certain areas where resistance to abrasion is necessary, and

h. The drive piston head is made of Armco 17-4 PH.

Pressure containing porti ons of the drives are designed and fabricated in accordance with requirements of the American Society of Mech anical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section III.

4.6.1.1.2.4 Control Rod Drive Hydraulic System. The CRD hydr aulic system (Figure 4.6-5) supplies and controls the pressure and flow to and from the drives through hydraulic control

units (HCU). The water discharged from the drives during a scram flows through the HCU to the scram discharge volume (SDV). The water discharged from a drive during a normal control rod positioni ng operation flows through the HCU, th e exhaust header, and is returned to the reactor vessel vi a the HCUs of nonmoving drives. E ach CRD has an associated HCU.

4.6.1.1.2.4.1 Hydrau lic Requirements. Th e CRD hydraulic system design is shown in Figures 4.6-5 and 4.6-6. The hydraulic requirements, identified by the function they perform, are as follows:

a. An accumulator hydraulic charging pressure of approximately 1400 to 1500 psig is required. Flow to the accumulators is required only during scram reset or system startup;

b. Drive water header pressure of a pproximately 260 psi a bove reactor vessel pressure is required. A fl ow rate of approximately 4 gpm to insert a control rod and 2 gpm to withdraw a control rod is required;

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-8 c. Cooling water to the drives is required at a flow rate of approximately 0.34 gpm per drive unit. (Cooling water to a drive can be interrupted for short periods without damaging the drive);

d. The SDV is sized to receive and contain all the water discharged by the drives during a scram; a minimum volume of 3.

34 gal per drive is required (excluding the instrument volume);

e. Purge water flow to the RPV level inst rumentation reference leg backfill system at a flow rate from 0.

6 gal/hr to 2.4 gal/hr.

4.6.1.1.2.4.2 System Desc ription. The CRD hydraulic systems provide the required functions with the pumps, filter, valves, instrumentation, and piping shown in Figure 4.6-5 and described in the following.

Duplicate components are included, where necessary, to ensure c ontinuous system operation if an inservice component requires maintenance.

4.6.1.1.2.4.2.1 Supply Pump. One supply pump pressurizes th e system with water from a condensate supply header, which ta kes suction from the condensa te treatment system and/or condensate storage tanks depending on plant operation. One installed spare pump is provided for standby. A discharge check valve prevents backflow through the nonoperating pump. A portion of the pump discharge fl ow is diverted through a minimum flow bypass line to the condensate storage tank. This flow is controlled by an orifi ce and is sufficient to prevent immediate pump damage if the pump di scharge is inadvertently closed.

Condensate water is processed by two filters in the system. The normal CRD pump suction flow path includes a 25- filter with a 250- Y-strainer upstream of th e filter. Th e filtration capacity of these two in-series elements is limited by and therefore characterized by, the 25- filter (see Figure 4.6-5).

The filters used on the CRD system are of a r ugged design and failure of the filters are not considered likely. Alarms are provided to give an early warning to the operator that maintenance is required.

The only known mode of failure of the filter element is for it to collapse due to high differential pressure. The CR D pump suction filter can with stand a maximum differential pressure of 20 psi and an alarm indicates in the control room high su ction filter differential pressure at 8 psi. The filter element is additionally protected and strengthened by a stainless steel, perforated center tube. The CRD pump discharge filter can withstand a maximum

differential pressure of 300 psi and an alarm indicates in the control room high differential pressure at 20 psi. The filter element is constructed entirely of stainless steel. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-9 If the CRD systems pump suction and discharg e filters were bypassed completely, possible presence of corrosion particles would not affect the reliability of the scram function of the CRD system. The presence of corrosion particles may accelerate wear of the drive components over a period of time. However, such wear is not a safety concern since this degradation in drive performance already occurs during normal r od operations and is detectable.

4.6.1.1.2.4.2.2 Accumulator Charging Pressure . Accumulator charging pressure is established by the discharge pre ssure of the system supply pu mp. During scram the scram inlet (and outlet) valves open and permit the stored energy in the accumu lators to discharge into the drives. The resulting pressure decrease in the charging water header allows the CRD supply pump to "run out" (i.e., flow rate to increase substan tially) into the CRDs via the charging water header. The flow sensing system upstream of the accumu lator charging header detects high flow and closes the flow control valve. This action maintains increased flow through the charging water header.

Pressure in the charging header is monitored in the control room with a pressure indicator and low pressure alarm. Charging water header pre ssure is not essential to successfully scram the plant. Each of the accumulato rs are prevented from leaking b ack to the charging water header by a check valve. Therefore, the pressure required to scram each rod is maintained. The integrity and leaktightness of thes e check valves are routinely test ed as part of the surveillance test program. In addition, when the reactor is at rated pressure, no accumulator pressure is necessary to scram the plant.

During normal operation the flow control valve maintains a constant system flow rate. This flow is used for drive flow, driv e cooling, and system stability.

4.6.1.1.2.4.2.3 Drive Water Pressure . Drive water pressure requi red in the drive header is maintained by the drive/cooling wa ter pressure control valve, which is manually adjusted from the control room. A flow rate of approximately 6 gpm (the sum of the flow rate required to insert and withdraw a control rod) normally pa sses from the drive water pressure stage through two solenoid-operated stabilizing va lves (arranged in parallel) a nd then goes into the cooling water header. The flow through one stabilizing valve equals the drive insert flow; that of the

other stabilizing valve equals the drive withdraw al flow. When operating a drive, the required flow is diverted to that drive by closing the appropriate stabilizing valve while at the same time opening the drive directional control and exhaust solenoid valv es. Thus, flow through the drive/cooling water pressure cont rol valve is always constant.

Flow indicators in the drive water header and in the line downstream from the stabilizing valves allow the flow rate through the stabili zing valves to be adjusted when necessary. Differential pressure between the reactor vessel and the drive pressure stage is indicated in the control room.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 LDCN-14-026 4.6-10 4.6.1.1.2.4.2.4 Coolin g Water Header. The cooling water header is located downstream from the drive/cooling water pres sure valve. The drive/cooling water pressure control valve is manually adjusted from the control room to produce the required drive/cooling water pressure

balance.

The flow through the flow control valve is virt ually constant. Therefore, once adjusted, the drive/cooling water pressure cont rol valve will maintain the corr ect drive pressure and cooling water pressure, independent of reactor vessel pressure. Changes in setting of the pressure control valve are required only to adjust for cha nges in the cooling requir ements of the drives, as drive seal characteristics change with time. A flow indicator in th e control room monitors cooling water flow. A different ial pressure indicator in th e control room indicates the difference between reactor vesse l pressure and drive/cooling water pressure. Although the drives can function without cooling water, temperatures a bove 350°F can result in fluid flashing and measurable delays in scram times. The temperature of each drive is monitored by a temperature recorder.

4.6.1.1.2.4.2.5 Scram Discharge Volume. The CGS SDV header system is designed as a continually expanding path from the 185 individual 0.75-in. scram discharge (withdrawal) lines to one of two integrated scram discharge volume/instrument volume (SDV/IV) systems (one system per approximately half the drives). Each integrated SDV/IV system consists of a continuously downsloping piping run expanding from the SDV (consisting of seven 6-in. Return headers from the indivi dual HCU banks to an 8-in. comb ined return h eader) to the 12-in. vertically oriented IV. The only location where blockage need be assumed (piping less than 2-in. diameter) is in the 0.75 in. discharge line from the individual HCU. Blockage here would only cause failure of one control rod to insert. This is an acceptable consequence for a single failure and has been evalua ted as part of the plant design basis. The header piping is sized to receive and contain all the water discharged by the driv es during a full scram (3.34 gal per drive) independent of the IV.

During normal plant operation each SDV is empty and vented to the atmosphere through its open vent and drain valve. When a scram occurs on a signal from the safety circu it, these vent and drain valves are closed to conserve reactor water. Redundant vent and drain valves are incorporated in the design of the SDV to ensure that no single failure can result in uncontrolled loss of reactor coolant. Lights in the cont rol room indicate the pos ition of these valves. During a scram, the SDV partly fills with wa ter discharged from a bove the drive pistons. After scram is completed, the CRD seal leakage from the reactor continues to flow into the SDV until the discharge volume pressure equals the reactor vessel pressure. A check valve in each HCU prevents reverse flow from the scram discharge header volume to the drive. When the initial scram signal is cleared from the reactor protection system (RPS), the SDV signal is overridden with a key lock override switch, and the SDV is drained and returned to atmospheric pressure.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 LDCN-14-026 4.6-11 Remote manual switches in the pilot valve solenoid circuits allow the discharge volume vent and drain valves to be tested without disturbing the RPS. Closing the SDV valves allows the outlet scram valve seats to be leak tested by timing the accumulation of leakage inside the SDV.

Six liquid-level switches and two level transmi tters directly connected to each instrument volume monitor the volume for abnormal water level. They provide redundant and diverse input to the RPS scram functi on and control room annunciation and contro l rod withdrawal block function. They are set at three different levels. At the lowest level, a level switch actuates to indicate that the volume is not comp letely empty during post-scram draining or to indicate that the volume starts to fill through leakage accu mulation at other times during reactor operation. At the sec ond level, one level sw itch produces a rod withdrawal block to prevent further withdrawal of any control rod, when leakage accumulate s to half the capacity of the instrument volume. The remaining four switches are interconnected with trip channels of the RPS and will initiate a reactor scram on high water level while sufficient volume for a full scram still exists within the SDV. Two of these switches ar e actuated by level transmitters to provide diversity of signals to the RPS.

In the event of a slow or partial loss of air pressure, the hi gh-level scram se tpoint and the SDV/IV system capacity ensure that scram capability is main tained even in the event of maximum inleakage into the SDV prior to a scram. Analysis, assuming the maximum inleakage of 5 gpm and using th e actual calculation piston-over area to determine the scram volume requirements, shows that adequate scram discharge volume will remain in the SDV system at the time that a scram is initiated.

A partial loss of air pressure does not result in the uncontrolled release of reactor coolant to the reactor building should all or most of the scram discharge valves lift. When the water buildup reaches scram initiation leve l in the IV, a scram signal is produced. This will cause the air supply to the vent and dr ain valves to vent, thereby en suring that the vent and drain valves close and isolate. For leakage rates that do not result in buildup in the IV, the leak will drain to the reactor building equipment drain system.

4.6.1.1.2.4.3 Hydraulic Control Units. Each HCU furnishe s pressurized water, on signal, to a drive unit. The drive then pos itions its control rod as required. Operation of the electrical system that supplies scram and normal control rod positioning signa ls to the HCU is described in Section 7.7.1.2. The basic components in each HCU are manual, pneumatic, and electrical valves; an accumulator, related piping, elec trical connections, filters, and instrumentation (see Figures 4.6-5, 4.6-6, and 4.6-7). The components and their functions are described in the following. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-12 4.6.1.1.2.4.3.1 Insert Drive Valve . The insert drive valve 123 is solenoid operated and opens on an insert signal. The valve supplies drive water to the bottom side of the main drive piston. 4.6.1.1.2.4.3.2 In sert Exhaust Valve . The insert exhaust solenoi d valve 121 also opens on an insert signal. The valve disc harges water from above the dr ive piston to the exhaust water header.

4.6.1.1.2.4.3.3 Withdraw Drive Valve. The withdraw drive va lve 122 is solenoid operated and opens on a withdraw signal. The valve supp lies drive water to the top of the drive piston.

4.6.1.1.2.4.3.4 Withdraw Exhaust Valve . The solenoid operated withdraw exhaust valve 120 opens on a withdraw signal and discharges water from below the main drive piston to the exhaust header. It also serves as the settle valve, which opens following any normal drive movement (insert or withdraw) to allow the control rod and its drive to settle back into the nearest latch position.

4.6.1.1.2.4.3.5 Sp eed Control Units. The insert drive valve and withdraw exhaust valve have a speed control unit. Th e speed control unit regulates the control rod insertion and withdrawal rates during normal operation. Th e manually adjustable flow cont rol unit is used to regulate the water flow to and from the volume beneath the main drive piston. A correctly adjusted unit does not require readjustment except to comp ensate for changes in drive seal leakage.

4.6.1.1.2.4.3.6 Scram Pilot Valves. The scram pilot valves are operated from the RPS. Two scram pilot valves control both the scram inlet valve and the sc ram exhaust valve. The scram pilot valves are identical, three-way, solenoid-operated, normally energized valv es. On loss of electrical signal to the pilot valves, such as the loss of external ac power, the inlet ports close and the exhaust ports op en on both valves. The pilot valves (Figure 4.6-5 ) are arranged so

that the trip system signal mu st be removed from both valves before air pr essure can be discharged from the scram valve operators.

This prevents the inadvertent scram of a single drive in the even t of a failure of one of the pilot valve solenoids.

4.6.1.1.2.4.3.7 Scram Inlet Valve. The scram inlet valve opens to supply pressurized water to the bottom of the drive piston. This quick opening globe valve is operated by an internal spring and system pressure. It is closed by air pressure applied to th e toe of its diaphragm operator. A position indicator switch on this valve energizes a light in the control room as

soon as the valve starts to open.

4.6.1.1.2.4.3.8 Sc ram Exhaust Valve . The scram exhaust valve opens slightly before the scram inlet valve, exhausting water from above the drive piston. The exhaust valve opens faster than the inlet valve because of the higher air pressure spring setting in the valve COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-13 operator. A position indicator switch on this valve energizes a light in the control room as soon as the valve starts to open.

4.6.1.1.2.4.3.9 Scram Accumulator. The scram accumulator stores sufficient energy to fully insert a control rod at lower vessel pressures. At higher vessel pressures the accumulator pressure is assisted or supplan ted by reactor vessel pressure. The accumulator is a hydraulic cylinder with a free-floating piston. The pist on separates the water on top from the nitrogen below. A check valve in the accumulator charging water line prevents loss of water pressure in the event supply pressure is lost.

During normal plant operation the accumulator piston is seated at the bottom of its cylinder. Loss of nitrogen decreases the nitrogen pressure, which actuat es a pressure switch and sounds an alarm in the control room.

To ensure that the accumulator is always able to produce a scram, it is continuously monitored for water leakage. A float type level switch actuates an alarm if water leaks past the piston barrier and collects in the accumu lator instrumentation block.

4.6.1.1.2.5 Control Rod Drive System Operation. The CRD system performs rod insertion, rod withdrawal, and scram. These opera tional functions are described below.

4.6.1.1.2.5.1 Rod Insertion . Rod insertion is initiated by a signal from the operator to the insert valve solenoids. This si gnal causes both insert valves to open. The insert drive valve applies reactor pressure plus approximately 90 psi to the bottom of the drive piston. The insert exhaust valve allows water from above the drive piston to discharge to the exhaust header.

As is illust rated in Figure 4.6-3 , the locking mechanism is a ratchet -type device and does not interfere with rod insertion. The speed at wh ich the drive moves is determined by the flow through the insert speed control valve, which is set for approximately 4 gpm for a shim speed (nonscram operation) of 3 in./sec. During normal insertion, the pressure on the downstream side of the speed control valve is 90 psi to 100 psi above reactor vessel pressure. However, if the drive slows for any reason, the flow through, and pressure drop across, the insert speed control valve will decrease; the full differential pressure (260 ps i) will then be available to cause continued insertion. W ith 260 psi differential pressure acting on the drive piston, the piston exerts an upward force of 1040 lb. 4.6.1.1.2.5.2 Rod Withdrawal . Rod withdrawal is by design more involved than insertion. The collet finger (latch) must be raised to reach the unlocked position (see Figure 4.6-3 ). The notches in the index tube and the collet fingers are shaped so that the downward force on the index tube holds the collet finge rs in place. The index tube mu st be lifted before the collet fingers can be released. This is done by opening the drive insert valves (in the manner described in the preceding paragraph) for approximately 1 sec. The withdraw valves are then opened, applying driving pressure above the driv e piston and opening the area below the piston COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-035 4.6-14 to the exhaust header. Pressure is simultaneously applied to the collet piston. As the piston raises, the collet fingers are cammed outward, away from the index tube, by the guide cap.

The pressure required to release the latch is set and maintained at a level high enough to overcome the force of the latch return spring plus the force of reactor pressure opposing

movement of the collet piston. When this occurs, the index tube is unlatched and free to move in the withdraw direction. Water displaced by the drive piston flows out through the withdraw

speed control valve, which is se t to give the control rod a shim speed of 3 in./sec. The entire valving sequence is automatically controlled an d is initiated by a single operation of the rod withdraw switch.

4.6.1.1.2.5.3 Scram . During a scram the scram pilot valves and scram valves are operated as previously described. With the scram valves open, accumulator pressure is admitted under the drive piston, and the area over the dr ive piston is vented to the SDV.

The large differential pr essure (initially approximately 1500 psi and al ways several hundred psi, depending on reactor vessel pressure) produces a large upward force on the index tube and control rod. This force gives the rod a high in itial acceleration and provid es a large margin of force to overcome friction. Afte r the initial accelerati on is achieved, the dr ive continues at a nearly constant velocity. This characteristic provides a high in itial rod insertion rate. As the drive piston nears the top of its stroke the piston seals close off the large passage (buffer orifices) in the stop piston tube, providing a hydraulic cushion at the end of travel.

Prior to a scram signal the accu mulator in the HCU has approxi mately 1450-1510 psig on the water side and 1050-1100 psig on the nitrogen side. As the in let scram valve opens, the full water-side pressure is available at the CRD acting on a 4.1 in. 2 area. As CRD motion begins, this pressure drops to the gas-side pressure less line losses between the accumulator and the CRD system; at low vessel pressures the accumu lator completely discharges with a resulting gas-side pressure of approxima tely 575 psi. The CRD accumula tors are required to scram the control rods when the reactor pressure is low, and the accumulators retain sufficient stored energy to ensure the complete insertion of the control rods in the required time.

The ball check valve in the driv e flange allows reactor pressure to supply the scram force whenever reactor pressure exce eds the supply pressure at the drive. This occurs due to accumulator pressure decay and inlet line losses during all scrams at higher vessel pressures. When the reactor is close to or at fully operating pressure, reac tor pressure alone will insert the control rod in the required time, although th e accumulator does prov ide additional margin at the beginning of the stroke.

The CRD system provides the following performance at full power operation and with accumulators. The scram insertion time is measured from the instant the scram pilot valve solenoids are deenergized.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-035 4.6-15 Position inserted from 45 39 25 5

fully withdrawn

Tech Spec scram insertion 0.528 0.866 1.917 3.437 time (sec)

4.6.1.1.2.6 Instrumentation. The instrumentation for both the control rods and CRDs is defined by that given for the manual control system. The objective of the reactor manual control system is to provide the operator with the means to make change s in nuclear reactivity so that reactor power level and power distribution can be contro lled. The syst em allows the operator to manipul ate control rods.

The design bases and further discussion are contained in Chapter 7 . 4.6.1.2 Control Rod Drive Housing Supports

4.6.1.2.1 Safety Objective

The CRD housing supports prevent any significant nuclear transient if a drive housing breaks or separates from the bottom of the reactor vessel.

4.6.1.2.2 Safety Design Bases

The CRD housing supports shall meet the following safety design bases:

a. Following a postulated CRD housing failure, control rod downward motion shall be limited so that a ny resulting nuclear transient could not be sufficient to cause fuel damage, and

b. The clearance be tween the CRD housings and the s upports shall be sufficient to prevent vertical contact stresses caused by thermal expansion during plant operation.

4.6.1.2.3 Description

The CRD housing supports are shown in Figure 4.6-8. Horizontal beams are installed immediately below the bottom head of the reactor vessel, between the rows of CRD housings. The beams are supported by brackets welded to the steel form liner of the drive room in the reactor support pedestal.

Hanger rods, approximately 10 ft long and 1.75 in. in diameter, are supported from the beams on stacks of disc springs. These springs comp ress approximately 2 in. under the design load.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-16 The support bars are bolted between the bottom ends of the hanger rods. The spring pivots at the top and the beveled, loos e fitting ends on the support ba rs prevent substantial bending moment in the hanger rods if the support bars are overloaded. Individual grids rest on the support bars between adjacent beams. Because a single piece grid would be difficult to handle in the limited work space and because it is necessary that CRDs, position indicators, and in-core instrumentation components be accessible for inspection and maintenance, each grid is designed for in-place assembly or disassembly. Each grid assembly is made from two grid plates, a clamp, and a bolt. The top part of the clamp guides the grid to its correct position directly below the respec tive CRD housing that it would support in the postulated accident.

When the support bars and grid s are installed, a gap of approximately 1 in. at room temperature (approximately 70°F) is provided between the grid and the bottom contact surface of the CRD flange. During system heatup, th is gap is reduced by a net downward expansion of the housings with respect to the supports . In the hot operating condition, the gap is approximately 0.25 in.

In the postulated CRD housing failure, the CRD housing supports are loaded when the lower contact surface of the CRD flange contacts the grid. The resulting load is then carried by two grid plates, two support bars, four hanger rods, their disc sp rings, and two adjacent beams.

For purposes of mechanical design, the postulate d failure resulting in the highest forces is an instantaneous circumferential separation of the CRD housing from the reactor vessel, with an internal pressure of 1250 psig (reactor vesse l design pressure) acting on the area of the separated housing. The we ight of the separated hous ing, CRD, and blade, plus the pressure of 1250 psig acting on the area of the separated housi ng, gives a force of approximately 35,000 lb. This force is multip lied by a factor of three for impact, conservatively assuming that the housing travels through a 1-in. gap before it contacts the supports. The total force (105,000 lb) is then treated as a static load in design.

All CRD housing support subassemblies are fabricated of commonly available structural steel, except for the disc springs, whic h are Schnorr, Type BS-125-71-8.

4.6.2 EVALUATION OF THE CONTROL ROD DRIVES Safety evaluation of the contro l rods, CRDs, and CRD housing supports is described below. Further description of control rods is contained in Section 4.2. The evaluation of the effects of pipe breaks on the CRDs may be found in Section 3.6. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-17 4.6.2.1 Control Rods 4.6.2.1.1 Materials Adequacy Throughout Design Lifetime

The adequacy of the materials throughout the design life was evaluated in the mechanical design of the control rods. The primary materials, B 4C powder, hafnium, and type 304 austenitic stainless steel, have been found suitable in me eting the demands of the BWR environment.

4.6.2.1.2 Dimensional a nd Tolerance Analysis Layout studies are done to ensure that, given th e worst combination of extreme detail part tolerance ranges at assembly, no interference exis ts which will restrict the passage of control rods.

The italicized information is historical and was provided to support the application for an operating license.

In addition, during initial preoperational testing, an observer who is in direct communication with the control room will observe the operation of each individual control rod and verify that there is no binding or restric tion to rod motion and will liste n for any scr aping or binding noises which may signify rod misalignment. In addition, the function of each CRD line will be measured as indicated by the differential pr essure developed across the CRD piston during notch withdrawal. These differential pressure traces will be co mpared to reference traces to proper operation and the absen ce of abnormal friction.

4.6.2.1.3 Thermal Analysis of the Tendency to Warp

The various parts of the contro l rod assembly remain at approximately the same temperature during reactor operation, negating the problem of distortion or warpage. What little differential thermal growth could exist is allowed for in the mechanical design. A minimum axial gap is maintained between absorber rod tubes and the cont rol rod frame assembly for the purpose. In addition, dissimilar metals are avoided to further this end.

4.6.2.1.4 Forces for Expulsion An analysis has been performed that evaluates the maximum pr essure forces which could tend to eject a control rod from the core. The results of this analysis are given in Section 4.6.2.2.2.2. In summary, if the collet were to rema in open, which is un likely, calculations indicate that the steady-state control rod w ithdrawal velocity w ould be 2 ft/sec for a pressure-under line break, the lim iting case for rod withdrawal.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-18 4.6.2.1.5 Functional Failure of Critical Components The consequences of a functional failure of critical components have been evaluated and the results are discussed in Section 4.6.2.2.2 . 4.6.2.1.6 Precluding Excessive Rates of Reactivity Addition

To preclude excessive rates of reactivity add ition, analysis has been performed both on the velocity limiter device and the effect of probable contro l rod failures (see Section 4.6.2.2.2 ). 4.6.2.1.7 Effect of Fuel Rod Failure on Control Rod Channel Clearances

The CRD mechanical design ensures a sufficiently rapid insertion of control rods to preclude the occurrence of fuel rod fa ilures that could hinder reactor shutdown by causing significant distortions in channel clearances.

4.6.2.1.8 Mechanical Damage

Analysis has been performed for all areas of the control system showing that system mechanical damage does not affect the capability to continuous ly provide reactivity control.

In addition to the analysis performed on the CRD (see Sections 4.6.2.2.2 and 4.6.2.2.3 ) and the control rod blade, the following discussion summarizes the analys is performed on the control rod guide tube.

The guide tube can be subjected to any or all of the following loads:

a. Inward load due to pressure differential, b. Lateral loads due to flow across the guide tube,

c. Dead weight,

d. Seismic (vertical and horizontal), and

e. Vibration.

In all cases analysis was perf ormed considering both a recircul ation line break and a steam line break. These events result in the largest hydraulic loadings on a control rod guide tube.

Two primary modes of failure were considered in the guide tube analysis: exceeding allowable stress and excessive elastic deformation. It was found that the allowable stress limit will not be exceeded and that the elastic deforma tions of the guide tube never are great enough to cause the free movement of the control rod to be jeopardized.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-19 4.6.2.1.9 Evaluation of Cont rol Rod Velocity Limiter The control rod velocity limiter limits the free fa ll velocity of the contro l rod to a value that cannot result in nuclear system process barrier damage. This ve locity is evaluated by the rod drop accident analysis in Chapter 15 .

4.6.2.2 Control Rod Drives

4.6.2.2.1 Evaluati on of Scram Time The rod scram function of the CRD system provi des the negative reactivity insertion required by safety design basis Section 4.6.1.1.1.1 . The scram time shown in the description is adequate as shown by the transient analyses in Chapter 15 . 4.6.2.2.2 Analysis of Malfunction Relating to Rod Withdrawal

There are no known single malfunctions that cause the unplanned withdrawal of even a single

control rod. However, if multip le malfunctions are postulated, st udies show that an unplanned rod withdrawal can occur at withdrawal speeds th at vary with the combination of malfunctions postulated. In all cases the subsequent withdrawal speeds are less than that assumed in the rod drop accident analysis as discussed in Chapter 15 . Therefore, the physical and radiological consequences of such rod withdrawals are less than those anal yzed in the rod drop accident.

4.6.2.2.2.1 Drive Housing Fails at Attachment Weld . The bottom head of the reactor vessel has a penetration for each CRD location. A dr ive housing is raised in to position inside each penetration and fastened by welding. The drive is raised into the drive housing and bolted to a flange at the bottom of the housi ng. The housing material is seam less, type 304 stainless-steel pipe with a minimum tensile stre ngth of 75,000 psi. The basic failure considered here is a complete circumferentia l crack through the housing wall at an elevation just below the J-weld.

Static loads on the housing wall include the weight of the drive and the control rod, the weight of the housing below the J-weld, and the reactor pressure acting on the 6-in.-diameter cross-sectional area of the housing and the drive. Dynamic loading results from the reaction force during drive operation.

If the housing were to fail as described, the following sequence of even ts is foreseen. The housing would separate from the vessel. Th e CRD and housing would be blown downward against the support structure by reactor pressure acting on the cross-sectional area of the housing and the drive. The downward motion of the drive and associated parts would be determined by the gap between the bottom of the drive and the suppor t structure and by the deflection of the support structure under load. In the current design, maximum deflection is approximately 3 in. If the collet were to remain latched, no further control rod ejection would occur (Reference 4.6-1); the housing would not drop fa r enough to clear the vessel COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-20 penetration. Reactor water would leak at a rate of approximately 220 gpm through the 0.03-in.-diametral clearan ce between the housing and the vessel penetration. If the basic housing failure were to occur while the control rod is being withdrawn (this is a small fraction of the total drive operating time) and if the collet were to stay unlatched, the following sequence of events is foreseen. The housing would sepa rate from the vessel. The drive and housing would be blown downward agai nst the CRD housing supp ort. Calculations indicate that the steady-state rod withdrawal velocity would be 0.3 ft/sec. During withdrawal, pressure under the collet piston would be approx imately 250 psi greater than the pressure over it. Therefore, the collet would be held in the unlatched pos ition until driving pressure was removed from the pressure-over port.

4.6.2.2.2.2 Rupture of Hydraulic Line(s) to Drive Housing Flange. There are three types of possible rupture of hydraulic lines to the driv e housing flange: (1) pressure-under line break; (2) pressure-over line break; and (3) coin cident breakage of both of these lines.

4.6.2.2.2.2.1 Pre ssure-Under Line Break . For the case of a pr essure-under line break, a partial or complete circumferential opening is postulated at or near the point where the line enters the housing flange. Failure is more likely to occur after another basic failure wherein the drive housing or housing flange separates from the reactor vessel. Failure of the housing, however, does not necessarily lead dir ectly to failure of the hydraulic lines.

If the pressure-under line were to fail and if the collet were latched, no control rod withdrawal would occur. There would be no pressure differential across the collet piston and, therefore, no tendency to unlatch the collet. Consequently, the associated control rod could not be withdrawn, but if reactor pressure is greater than 600 psig, it will in sert on a scram signal.

The ball check valve is designe d to seal off a broken pressure-under line by using reactor pressure to shift the check ball to its upper seat. If the ball ch eck valve were prevented from seating, reactor water w ould leak to the atmosphere. Becaus e of the broken line, cooling water could not be supplied to the drive involved. Loss of cooling water would cause no immediate damage to the drive. However, prolonged exposure of the drive to temperatures at or near reactor temperature could lead to deterioration of material in the seals. Temperature is monitored by a temperature reco rder. A second indication woul d be high cooling water flow. If the basic line failure were to occur while the control rod is being withdrawn, the hydraulic force would not be sufficient to hold the colle t open, and spring force normally would cause the collet to latch and stop rod withdrawal. However, if the collet were to remain open, calculations indicate that the steady-state contro l rod withdrawal veloci ty would be 2 ft/sec. 4.6.2.2.2.2.2 Pre ssure-Over Line Break . The case of the pressure-over line breakage considers the complete breakage of the line at or near the poi nt where it enters the housing flange. If the line were to br eak, pressure over the drive pi ston would drop from reactor COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-21 pressure to atmospheric pressure . Any significant reactor pressure (approximately 600 psig or greater) would act on the bottom of the drive piston and fully insert the drive. Insertion would occur regardless of the operational mode at the time of the failure. After full insertion, reactor water would leak past the stop piston seals. This leakage would exha ust to the atmosphere through the broken pressure-over line. The leakage rate at 1000 psi reactor pressure is estimated to be 4 gpm nominal but not mo re than 10 gpm, ba sed on experimental measurements. If the reactor were hot, driv e temperature would increase. This situation would be indicated to the reactor operator by the drift alarm, by the fully inserted drive, by a high drive temperature, and by operation of the drywell sump pump. 4.6.2.2.2.2.3 Simulta neous Breakage of the Pressure -Over and Pressure-Under Lines . For the simultaneous breakage of th e pressure-over and pressure-under lines, pressures above and below the drive piston would drop to zero, a nd the ball check valve would close the broken

pressure-under line. Reactor water would flow from the annulus outside the drive, through the vessel ports, and to the space belo w the drive piston. As in the case of pressure-over line breakage, the drive would then insert (approximately 600 psig or greater) at a speed dependent on reactor pressure. Full insertion would occur regardless of the operational mode at the time of failure. Reactor water would leak past the drive seals and out the broken pressure-over line to the atmosphere, as described above. Drive temperature would increase. Indication in the control room would include the drift alarm, th e fully inserted drive, and operation of the drywell sump pump.

4.6.2.2.2.3 All Drive Fla nge Bolts Fail in Tension. Each CRD is bolted to a flange at the bottom of a drive housing. The flange is welded to the drive housing. Bolts are made of AISI-4140 steel, with a minimum te nsile strength of 125, 000 psi. Each bolt has an allowable load capacity of 15,200 lb. Capa city of the eight bolts is 121, 600 lb. As a result of the reactor design pressure of 1250 psig, the major load on all eight bolts is 30,400 lb.

If a progressive or simultaneous failure of all bo lts were to occur, th e drive would separate from the housing. The cont rol rod and the drive would be blown downward against the support structure. Impact velocity and support structure loading would be slightly less than that for drive housing failure because reactor pr essure would act on the drive cross-sectional area only and the housing would remain attached to the reactor vessel. The drive would be isolated from the cooling water supply. Reactor water would flow downw ard past the velocity limiter piston, through the large drive filter, and into the annular sp ace between the thermal sleeve and the drive. For worst-case leakage calculations, the large filt er is assumed to be deformed or swept out of the way so it would o ffer no significant flow restriction. At a point near the top of the annulus, where pressure w ould have dropped to 35 0 psi, the water would flash to steam and cause choke-flow conditions. Steam would flow down the annulus and out the space between the housing and the drive flanges to the drywell. Steam formation would limit the leakage rate to approximately 840 gpm.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-22 If the collet were latched, control rod ejection would be limited to the distance the drive can drop before coming to rest on th e support structure. There woul d be no tendency for the collet to unlatch, because pressure below the collet piston would drop to zero. Pressure forces, in fact, exert 1435 lb to hold the collet in the latched position. If the bolts failed during control rod withdrawal, pressure below the collet piston would drop to zero. The collet, with 1650-lb return force, would latch and stop rod withdrawal.

4.6.2.2.2.4 Weld Jo ining Flange to Housing Fails in Tension . The failure considered is a crack in or near the weld that joins the flange to the housing. This crack extends through the wall and completely aro und the housing. The flange material is forged, type 304 stainless steel, with a minimum tensile st rength of 75,000 psi. The hous ing material is seamless, type 304 stainless steel pipe, with a minimum tensile strength of 75,000 psi. The conventional, full penetration weld of type 308 stainless steel has a minimum tensile strength approximately the same as that for the parent metal. The design pressure and temperature are 1250 psig and 575°F. Reactor pressure acting on the cross-sec tional area of the drive; the weight of the control rod, drive, and flange

and the dynamic reaction force during drive operation result in a maximum tensile stress at the weld of approximately 6000 psi.

If the basic flange-to-housing joint failure occurred, the flange a nd the attached drive would be blown downward against the support structure. The support structure loading would be slightly less than that for drive housing failure because reactor pressure would act only on the drive cross-sectional area. Lack of differential pressure across the collet piston would cause the collet to remain latched a nd limit control rod motion to a pproximately 3 in. Downward drive movement would be small; therefore, most of the drive would remain inside the housing. The pressure-under and pressu re-over lines are flexible enough to withstand the small displacement and remain attached to the flange. Reactor water would follow the same leakage path described above for the fl ange-bolt failure, except that exit to the drywell would be through the gap between the lower end of the housing and the top of the flange. Water would flash to steam in the annulus surrounding the driv

e. The leakage rate would be approximately 840 gpm.

If the basic failure were to occur during control rod withdraw al (a small fraction of the total operating time) and if the collet were held unlatched, the flange would separate from the housing. The drive and flange would be blown downward against the su pport structure. The calculated steady-state rod withdrawal velocity would be 0.13 ft /sec. Because pressure-under and pressure-over lines re main intact, driving water pressure would continue to the drive, and the normal exhaust line restriction would exist. The pressure be low the velocity limiter piston would drop below normal as a result of leak age from the gap between the housing and the flange. This differential pre ssure across the velocity limiter piston would result in a net downward force of approximately 70 lb. Leakage out of the housing would greatly reduce the pressure in the annulus surrounding the drive. Thus, the net downward force on the drive piston would be less than normal. The overall effect of these events would be to reduce rod COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-23 withdrawal to approximately one-half of norma l speed. With a 560 psi differential across the collet piston, the collet woul d remain unlatched; however, it should relatch as soon as the drive signal is removed.

4.6.2.2.2.5 Housing Wall Ruptures . This failure is a vertical split in the drive housing wall just below the bottom head of the reactor vessel. The flow area of the hole is considered equivalent to the annular area between the driv e and the thermal sleeve. Thus, flow through this annular area, rather than flow through the hole in the housing, would govern leakage flow. The housing is made of type 304 stainless-steel seamless pipe, with a minimum tensile strength of 75,000 psi. The maximum hoop stress of 11,900 psi results primarily from the reactor design pressure (1250 psig) acting on the inside of the housing.

If such a rupture were to occur, reactor water would flash to steam and leak through the hole in the housing to the drywell at approximately 1030 gp

m. Choke-flow conditions would exist, as described previously for the flange-bolt failure. However, leakage flow would be greater because flow resistance would be less; that is, the leaking water and steam would not have to flow down the length of the housing to reach the drywell. A critical pressure of 350 psi causes the water to flash to steam.

No pressure differential across the collet piston would tend to unlatch the collet, but the drive would insert as a result of loss of pressure in the drive housing causing a pressure drop in the space above the drive piston.

If this failure occurred during control rod withdrawal, drive w ithdrawal would stop, but the collet would remain unlatched . The drive would be stoppe d by a reduction of the net downward force action on the drive line. The net force reduction would occur when the leakage flow of 1030 gpm reduces the pressu re in the annulus outside the drive to approximately 540 psig, thereby reducing the pressure acting on to p of the drive piston to the same value. A pressure differential of approxima tely 710 psi would ex ist across the collet piston and hold the collet unlatched as long as the operator held the withdraw signal.

4.6.2.2.2.6 Flange Plug Blows Out . To connect the vessel ports with the bottom of the ball check valve, a hole of 0.75-in. diameter is drille d in the drive flange. The outer end of this hole is sealed with a plug of 0.812-in. diamet er and 0.25-in. thickness . A full-penetration, type 308 stainless steel weld hol ds the plug in place. The postulated failure is a full circumferential crack in this weld and subsequent blowout of the plug.

If the weld were to fail, the plug were to blow out, and the collet remained latched, there would be no control rod motion. There would be no pressure differential acr oss the collet piston acting to unlatch the collet. Reactor water would leak past the velocity limiter piston, down the annulus between the drive and the thermal sleeve, through the vessel ports and drilled passage, and out the open plug hole to the drywell at approximately 320 gpm. Leakage calculations assume only liquid flows from the fl ange. Actually, hot re actor water would flash COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-24 to steam, and choke-flow conditions would exist. Thus, the expected leakage rate would be lower than the calculated value.

If this failure were to occur during control rod withdrawal and if the collet were to stay unlatched, calculations indicate that control rod withdrawal speed would be approximately 0.24 ft/sec. Leakage from the ope n plug hole in the flange would cause reactor water to flow downward past the velocity limit er piston. A small differential pressure across the piston would result in an insignificant driving force of approximately 10 lb, tending to increase withdraw velocity. A pressure differential of 295 psi across the collet piston w ould hold the collet unlatched as long as the driving signal was maintained.

Flow resistance of the exhaust path from the drive would be normal because the ball check valve would be seated at the lower end of its travel by pressure under the drive piston.

4.6.2.2.2.7 Ball Check Valve Plug Blows Out. As a means of access for machining the ball check valve cavity, a 1.25-in.-diameter hole has been drilled in the flange forging. This hole is sealed with a plug of 1.31-in. diameter a nd 0.38-in. thickness. A full-penetration weld, using type 308 stainless steel filler, holds the plug in place. The failure postulated is a circumferential crack in this weld leading to a blowout of the plug.

If the plug were to blow out while the drive was latched, there would be no control rod motion. No pressure differential would exist across the collet piston to unlatch the collet. As in the previous failure, reactor water would flow past the velocity limiter, down the annulus between the drive and thermal sleeve, through the vessel ports and drilled passage, through the ball check valve cage and out the open plug hole to the drywell. The leakage calculations indicate the flow rate would be 350 gpm. This calculation assu mes liquid flow, but flashing of the hot reactor water to steam would reduce this rate to a lower valu

e. Drive temperature would rapidly increase.

If the plug failure were to occur during control rod withdrawal (it would not be possible to unlatch the drive after such a fa ilure), the collet would relatch at the first locking groove. If the collet were to stick, calculations indicat e the control rod withdrawal speed would be 11.8 ft/sec. There would be a large retarding force exerted by the velocity limiter due to a 35 psi pressure differential across the velocity limiter piston.

4.6.2.2.2.8 Drive/Cooling Wate r Pressure Control Valve Failure . The pressure to move a drive is generated by the pressure drop of practically the full system flow through the drive/cooling water pressure control valve. This valve is eith er a motor-operated valve or a standby manual valve; either one is adjusted to a fixed opening. The normal pressure drop across this valve develops a pressure 260 psi in excess of reactor pressure.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-25 If the flow through the drive/coo ling water pressure control valv e were to be stopped, as by a valve closure or flow blockage, the drive pressure would increase to the shut off pressure of the supply pump. The occurrence of this condition during withdrawal of a drive at zero vessel pressure will result in a drive pressure increase from 260 psig to no more than 1750 psig. Calculations indicate that the drive would accelerate from 3 in./sec to approximately 6.5 in./sec. A pressure different ial of 1670 psi across the colle t piston would hold the collet unlatched. Flow would be upward past the velo city limiter piston, but retarding force would be negligible. Rod movement would stop as soon as the driving signal was removed. Conversely, if the PCV were to fail to a full open position, the cooling water pr essure would increase and the drive water pressure would decrease. The resulting cooling water pressure increase could cause control rods to drift inward. The existe nce of rod drifts would be alarmed to the control room operator for appropriate action. The resu lting drop in drive water pressure would make normal c ontrol rod notch movements impossi ble but would not affect the ability of the scram function.

In both of the cases described above, the manually operated bypass PC V in conjunction with

the isolation gate valves located upstream and downstream of the PCV would enable the operators to take corrective action.

In conclusion, although th e failure to the full open or full cl osed position of the drive/cooling water PCV will cause perturbation in the CRD sy stem operation, it does not present a safety problem to affect the scram capability of the CRD system.

4.6.2.2.2.9 Ball Check Valve Fails to Close Passage to Vessel Ports . Should the ball check valve sealing the passage to the vessel ports be dislodged and prev ented from reseating following the insert portion of a drive withdr awal sequence, water below the drive piston would return to the reactor th rough the vessel ports and the a nnulus between the drive and the housing rather than through the speed control valve. Because the fl ow resistance of this return path would be lower than normal, the calculated withdrawal speed would be 2 ft/sec. During withdrawal, differential pressure across the co llet piston would be a pproximately 40 psi. Therefore, the collet would te nd to latch and would have to stick open befo re continuous withdrawal at 2 ft/sec, could occur. Water would flow upward past the velocity limiter piston, generating a small retarding fo rce of approximately 120 lb. 4.6.2.2.2.10 Hydraulic C ontrol Unit Valve Failures . Various failures of the valves in the HCU can be postulated, but none could produ ce differential pressure s approaching those described in the preceding paragraphs and none alone coul d produce a high velocity withdrawal. Leakage through eith er one or both of the scram va lves produces a pressure that tends to insert the control rod rather than to withdraw it. If the pressure in the SDV should exceed reactor pressure following a scram, a check valve in the line to the scram discharge header prevents this pressure from operating the drive mechanisms.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-26 4.6.2.2.2.11 Collet Fingers Fail to Latch. The failure is presumed to occur when the drive withdraw signal is removed. If the collet fails to latch, the dr ive continues to withdraw at a fraction of the normal speed. Th is assumption is made because there is no known means for the collet fingers to become unlocked without so me initiating signal. B ecause the collet fingers will not cam open under a load, accidental application of a down signal does not unlock them. (The drive must be given a short insert signal to unload the fingers and cam them open before the collet can be driven to the unlock position.) If the drive withdrawal valve fails to close following a rod withdrawal, the co llet would remain open and the drive continue to move at a reduced speed. 4.6.2.2.2.12 Withdrawal Speed Control Valve Failure. Normal withdrawal speed is determined by differential pressures in the drive and is set for a nominal value of 3 in./sec. Withdrawal speed is maintained by the pressure regulating valve and is independent of reactor vessel pressure. Tests have s hown that accidental opening of the speed control valve to the full-open position produces a velocity of approximately 6 in./sec.

The CRD system prevents unplanned rod withdr awal and it has been shown above that only multiple failures in a drive unit and its control unit could cause an unpl anned rod withdrawal.

4.6.2.2.2.13 Slow or Partial Loss of Air to the Scram Discharge Valves. The CGS IV is adequately hydraulically coupled to the SDV, i.e., the IV is connected directly to the SDV with piping of a diameter equal to or greater than the diameter of th e SDV headers. This allows for direct detection of liquid buildup so that the ab ility to scram is ensured.

The basis of the instrument volume high level scram setpoint and the SDV/IV physical arrangement provides for scram action before significant SDV reduction occurs which could affect scram capability.

The high-level scram setpoint and the SDV/IV sy stem capacity ensure th at scram capability is maintained even in the event of maximum inl eakage into the SDV prior to a scram. Analysis, assuming the maximum inleakage of 5 gpm and using the actual calculated piston-over area to determine the scram volume require ments, shows that adequate SDV will remain in the SDV system at the time that a scram is initiated.

The partial loss of air pressure does not result in the uncontrolled release of reactor coolant to the reactor building. The vent and drain valves tends are spring to close-held open by air. Flow through the valve tends to close it. As air pressure decreases the valves will begin to close to limit coolant inventory loss. When the water buildup reaches scram initiation level in the IV, a scram signal is produced.

This will cause the air supply to the vent and dr ain valves to vent, thereby ensuring that the vent and drain valves close and isolate. For leakage rates whic h do not result in buildup in the IV, the leak will drain to the reactor building equipment drain system. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-27 4.6.2.2.3 Scram Reliability

High scram reliability is the result of a number of features of the CRD system. For example

a. Two reliable sources of scram energy are used to insert each control rod: individual accumulators at low reactor pr essure, and the reactor vessel pressure itself at power;

b. Each drive mechanism ha s its own scram and pilot va lves so only one drive can be affected if a scram valve fails to open. Two pilot valves are provided for each drive. Both pilot valves must be deenergized to initiate a scram;

c. The RPS and the HCUs are designed so that the scram si gnal and mode of operation override all others;

d. The collet assembly and index tube ar e designed so they will not restrain or prevent control rod inse rtion during scram; and

e. The SDV is monitored for accumulated water and the reactor will scram before the volume is reduced to a point that could interfere with a scram.

4.6.2.2.4 Control Rod Support and Operation

Each control rod is independen tly supported and cont rolled as required by the safety design bases.

4.6.2.3 Control Rod Drive Housing Supports

Downward travel of the CRD housing and its control rod following the postulated housing failure equals the sum of these distances: (1) the compression of the disc springs under dynamic loading, and (2) the initi al gap between the grid and the bottom contact surface of the CRD flange. If the reactor were cold and pressurized, the downward motion of the control rod would be limited to the spring compre ssion (approximately 2 in.) plus a gap of approximately 1 in. If the reactor were hot and pressurized, the gap would be approximately 0.25 in. and the spring compression would be slightly less than in the cold condition. In either case, the control rod movement following a housing failure is s ubstantially limited below one drive "notch" movement (6 in.). Sudden withdraw al of any control rod through a distance of one drive notch at any position in the core does not produce a transient sufficient to damage any radioactive material barrier. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-28 The CRD housing supports are in place during pow er operation and when the reactor coolant system is pressurized. If a control rod is ejected during shutdown, the reactor remains subcritical because it is desi gned to remain subcritical w ith any one control rod fully withdrawn at any time.

At plant operating temperature, a gap of approximately 0.25 in. exists between the CRD housing and the supports. At lower temperatures the gap is greater. B ecause the supports do not contact any of the CRD housing except duri ng the postulated acciden t condition, vertical contact stresses are prevented. 4.6.3 TESTING AND VERIFICATION OF THE CONTROL ROD DRIVES

4.6.3.1 Control Rod Drives

4.6.3.1.1 Testing and Inspection

4.6.3.1.1.1 Development Tests . The development drive (prototype) testing included more than 5000 scrams and approximately 100,000 latching cycles. One prototype was exposed to simulated operating cond itions for 5000 hr. These test s demonstrated the following:

a. The drive easily withsta nds the forces, pressures, and temperatures imposed;

b. Wear, abrasion, and corros ion of the nitrided stainl ess parts are negligible.

Mechanical performance of th e nitrided surface is superior to that of materials used in earlier operating reactors;

c. The basic scram speed of the drive has a satisfact ory margin above minimum plant requirements at any reactor vessel pressure; and

d. Usable seal lifetimes in excess of 1000 scram cy cles can be expected.

4.6.3.1.1.2 Factory Quality Control Tests. Quality control of welding, heat treatment, dimensional tolerances, ma terial verification, a nd similar factors is maintained throughout the manufacturing process to ensure reliable performance of the mechanic al reactivity control components. Some of the quality control tests performed on the control rods, CRD mechanisms, and HCU are listed below:

a. Control rod drive mechanism tests

1. Pressure welds on the drives are hydrostatically tested in accordance with ASME codes;

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-29 2. Electrical components ar e checked for elect rical continuity and resistance to ground;

3. Drive parts that cannot be visually inspected for dirt are flushed with filtered water at high velocity. No significant foreign material is permitted in effluent water;

4. Seals are tested for leakage to demonstrate correct seal operation;

5. Each drive is tested for shim motion, latching, and control rod position indication; and

6. Each drive is subjected to cold scram tests at various reactor pressures to verify correct scram performance.

b. Hydraulic control unit tests

1. Hydraulic systems are hydrostatica lly tested in accordance with the applicable code;

2. Electrical components and systems are tested for electric al continuity and resistance to ground;

3. Correct operation of the accumulator pressure and level switches is verified;

4. The unit's ability to perform its part of a scram is demonstrated; and

5. Correct operation and adjustment of the insert and withdrawal valves is demonstrated.

4.6.3.1.1.3 Operational Tests. After installation, all rods and drive mechanisms can be tested through their full stroke for operability.

During normal operation each time a control rod is withdrawn a notch, the operator can observe the in-core monitor indications to verify that the control rod is following the drive mechanism. All control rods th at are partially withdrawn from the core can be tested for rod-following by inserting or withdrawing the ro d one notch and returning it to its original position, while the operator observes the in-core monitor indications.

To make a positive test of control rod to CRD coupling integrity , the operator can withdraw a control rod to the end of its travel and then attempt to withdraw the drive to the over-travel position. Failure of the drive to over-travel demonstrates rod-to-drive coupling integrity. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-09-034 4.6-30 Hydraulic supply subsystem pres sures can be observed from in strumentation in the control room. Scram accumulator pressures can be observed on the nitrogen pressure gages.

4.6.3.1.1.4 Acceptance Tests . Criteria for acceptance of th e individual CRD mechanisms and the associated control and protection systems were incorporated in specifications and test procedures covering three distinct phases: (1) pre-installation, (2) after installation prior to

startup, and (3) during startup testing.

The pre-installation spec ification defined criteria and acceptable ranges of such characteristics as seal leakage, friction, and scram performance under fixed test conditions whic h must be met before the component was shipped.

The after installation, prestartup tests (Section 14.2) included normal and scram motion and were primarily intended to verify that piping, valves, electrical components and instrumentation were properly installed. The test specifications included criteria and acceptable ranges for drive speed , time settings, scram valve response times, and control pressures. These tests were intended more to document system condition than as tests of performance.

As fuel was placed in the reactor, the startup test procedure ( Chapter 14 ) was followed. The tests in this procedure were intended to demonstrate that the initial operational characteristics meet the limits of the specifications over the range of primary cool ant temperatures and pressures from ambient to operating.

4.6.3.1.1.5 Surveillance Tests. The surveillance requirement s for the CRD system are as follows:

a. Prior to each in-vessel fuel movement during fuel loading sequence, the shutdown margin with the highest worth control rod withdrawn shall be analytically determined to be at least 0.38% k/k or shall be determined by test to be at least 0.28% k/k; b. Once within 4 hr after criticality foll owing fuel movement within the RPV or control rod replacement, the shutdown margin with the highest worth control

rod withdrawn shall be an alytically determined to be at least 0.38% k/k or shall be determined by test to be at least 0.28% k/k; c. Each withdrawn control r od shall be exercised one notch (i.e., inserted at least one notch and then may be returned to its original position) at least once every 31 days.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-020 4.6-31 The control rod exercise tests serve as a periodic check against deterioration of the control rod system and also verifies the ability of the CRD to scram. If a rod can be moved with drive pressure, it may be expected to scram since higher pressure is app lied during scram;

d. The coupling integrity shall be verified for each withdrawn control rod as follows:

1. When the rod is first withdrawn, observe discernible response of the nuclear instrumentation, and

2. When the rod is fully withdrawn each time, observe that the drive will not go to the over-travel position.

Observation of a response from the nuclear instrumentation during an attempt to withdraw a control rod indicates indirec tly that the rod and drive are coupled. The over-travel position feature provides a positive check on the coupling integrity, for only an uncoupled driv e can reach the over-travel position;

e. During operation, accumu lator pressure and level at the normal operating value shall be verified.

Experience with CRD systems of the same type indicates that weekly verification of accumulator pressure and level is sufficient to ensure operability of the accumulator portion of the CRD system;

f. At the time of each major refueling out age, each operable control rod shall be subjected to scram time tests from the fully withdrawn position.

Experience indicates that the scram times of the control rods do not significantly change over the time interval between re fueling outages. A test of the scram times at each refueling outage is sufficient to identify any significant lengthening of the scram times; and

g. A channel functional test of the accumulator leak detectors and a channel calibration of the accumulator pressure detectors, which verifies an alarm setpoint 940 psig on decreasing pressure, is performed at least once per 30 months.

4.6.3.1.1.6 Functional Tests . The functional tes ting program of the CRDs consists of the 5-year maintenance life and th e 1.5X design life test programs as described in Section 3.9.4.4. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 4.6-32 There are a number of failures th at can be postulated on the CRD but it would be very difficult to test all possible failures. A partial test program with pos tulated accident conditions and imposed single failures is available.

The following tests with imposed single failur es have been performed to evaluate the performance of the CRDs under these conditions:

a. Simulated ruptured scram line test,

b. Stuck ball check valve in CRD flange, c. HCU drive down inlet flow control valve (V122) failure, d. HCU drive down outlet flow control valve (V120) failure, e. CRD scram performan ce with V120 malfunction, f. HCU drive up outlet cont rol valve (V121) failure, g. HCU drive up inlet cont rol valve (V123) failure, h. Cooling water check valve (V138) leakage,

i. CRD flange check valve leakage,

j. CRD stabilization circuit failure,

k. HCU filter restriction,

l. Air trapped in CRD hydraulic system,

m. CRD collet drop test, and

n. CR qualification velo city limiter drop test.

Additional postulated CRD failure s are discussed in Sections 4.6.2.2.2.1 through 4.6.2.2.2.12 . 4.6.3.2 Control Rod Drive Housing Supports

CRD housing supports are removed for inspection and maintenance of the CRDs. The supports for one control rod can be removed during reactor shutdown, even when the reactor is pressurized, because all contro l rods are then inserted. When the support structure is reinstalled, it is inspected fo r correct assembly with particular attention to maintaining the correct gap between the CRD flange lower contact surf ace and the grid.

4.6.4 INFORMATION FOR COMBINED PERFORMANCE OF REACTIVITY CONTROL SYSTEMS

4.6.4.1 Vulnerability to Common Mode Failures The two reactivity control systems, the CRD and SLC systems, do not share any instrumentation or components. Thus, a common mode failure of the reactivity systems would be limited to an accident event which could damage essential equipment in the two independent systems.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 4.6-33 A seismic event or the postulated a ccident environments (see Section 3.11) are not considered potential common mode failures since the essen tial (scram) portions of the CRD system are designed to Seismic Category I standards and to operate as required und er postulated accident environmental conditions. The SLC system is also designed to Seismic Category I standards. No common mode power failure is considered credible. The scram function of the CRD system is "fail-safe" on a loss of power and is designed to ove rride any other CRD function. The SLC system has two independent power su pplies to its essential redundant pumps and valves. The power supplies to the SLC system are considered vital and as such are switched to the onsite standby diesels on a loss of normal power sources.

Essential components (including cabling and piping) for the SLC system are separated from essential CRD components in the secondary containment by phys ical barriers and/or by at least 40 ft of physical separa tion. The various safety studies performed by the architect-engineer verified that this separation is sufficient to prevent simultaneous failure of the reactivity systems due to pipe break and whip, credible fires, and all poten tial missiles. The location of the primary components of th ese systems is shown in Figures 1.2-7 through 1.2-12. The CRD insert and withdrawal lines penetrate at the bottom of the RPV whereas the SLC lines connect to the HPCS line which penetrates the RPV. Protection of the reactivity control systems from postulated events, such as pipe breaks, is discussed in Section 3.6. A fault tree analysis was completed for both of these systems, and the calculated unreliability is less than 10 -7/reactor year. This unreliability is an estimate of the failure to fully insert the control rods into the core, combin ed with a failure to inject bor on into the vessel by the SLC. Failure to insert control rods is defined to be noninsertion of the CRDs in the following manner: 50% in a "checkerboard pattern," 31 % in a random pattern, or 4% in a cluster.

4.6.4.2 Accidents Taking Credit for Multiple Reactivity Systems

There are no postulated accidents evaluated in Chapter 15 that take credit for two or more reactivity control systems preventing or mitigating each accident.

4.6.5 EVALUATION OF COMBINED PERFORMANCE

As indicated in Section 4.6.4.2, credit is not taken for multiple reactivity control systems for any postulated accidents in Chapter 15 . 4.6.6 ALTERNATE ROD INSERTION SYSTEM

4.6.6.1 System Description

The alternate rod insertion (ARI) system provides an alternate me ans to scram the control rods which is diverse and in dependent from the RPS. The ARI system may be actuated either COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 4.6-34 manually or automatically. The automatic signal to initiate ARI comes from high reactor vessel pressure or low reactor water level. The setpoints for ARI automatic initiation have been chosen such that a normal scram should already have been initiated by the above parameters prior to ARI initiation. The ARI system causes a scram by relieving the scram air header through four sets of solenoid valves. This, in turn, causes th e scram inlet and outlet valves to open. The CRD units then insert the control blades to shutdown the reactor. The ARI system has been designe d to ensure that rod motion be gins within sufficient time to ensure the ARI design objectives of Reference 4.6-2 are satisfied. These rod movement times are based on plant unique conditi ons and compliance with ARI desi gn objectives to ensure that plant safety considerations will be met.

4.6.6.2 Alternate Rod Insertion Redundancy

The ARI system constitutes a redundant back-up to the normal scra m system and is, therefore, not redundant in itself. That is , the ARI system is only one syst em with two divisions. Both divisions must function properly for the design basis rod in sertion times to be met.

The ARI system is, however, redunda nt in the aspect of preven ting spurious scrams. Each vent point for ARI in the scram air header consists of two valves in series (see Figure 4.6-5 ). The valves must be energized to vent the air header. This design is intended to prevent spurious scrams and unnecessary cycling of the power plant.

4.

6.7 REFERENCES

4.6-1 Benecki, J. E., "Impact Testing on Collet Assembly for Control Rod Drive Mechanism 7RD B144A," General El ectric Company, Atomic Power Equipment Department, APED-5555, November 1967.

4.6-2 NEDE-31096-P, "Licen sing Topical Report, Anticip ated Transient Without Scram," Response to NRC ATWS Ru le 10 CRF 50.62, February 1987. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.99Control Rod to Control Rod Drive Coupling 4.6-1Control Rod Assembly Unlocking Handle (Shown Raised

Against Spring

Force)Coupled View SpudUnlocking Lock plugTubeIndex Tube - DriveActuating

ShaftLock Plug Return Springs SocketVelocity Limiter Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Control Rod Drive Unit 960222.99 4.6-2Piston Tube Coupling Spud Guide Cap Fixed Piston (Stop Piston) Latch (Collet Fingers)Index Tube Moving Piston (Main Drive Piston) Drive Withdraw Line Bottom ofReactor Vessel DriveHousingCollet Piston Return Spring Collet Piston Drive Cylinder Drive Insert Line PRBall CheckValveArrows show water flow

when the drive is in the

withdrawal mode of

operation. Pressures shown are maximum.PR = Reactor Pressure Columbia Generating StationFinal Safety Analysis Report Tube Head FigureAmendment 53 November 1998Form No. 960690.veR.oN .warD Control Rod Drive Unit (Schematic)3-6.469.222069 ReactorPressureVesselReactorPressureVesselPressureOverPortHousingFlangeCircumferential ScreenOuter Tube Inner Tube PistonCoolingOrificeDriveMainFlangeRod Piston Information Detector ProbeBuffer Hole GuideCapControl RodGuide Tube StopPistonColl. Pist. Index Tube SpudPressureUnderPortOuter Tube Inner Tube Thermal Sleeve Piston Tube Inst Tube Index Tube Piston Tube Thermal Sleeve Coll. Pist. Outer Filter Outer Filter Index Tube Index Tube HousingFlangeDrive PistonDrive PistonDrive HousingDrive Housing Inner FilterGuideCapColumbia Generating Station Final Safety Analysis Report Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 4.6-5.179M528-1Control Rod Drive Hydraulic SystemRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 4.6-5.29M528-2Control Rod Drive Hydraulic SystemRev.FigureDraw. No.

Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 4.6-6.3302C12-04,26,2Control Rod Drive System (Process Diagram)Rev.FigureDraw. No. Control Rod Drive Hydraulic Control Unit 900547.25 4.6-7FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Charging Water RiserIsolation Valve Withdrawal RiserIsolation ValveDrive Water Riser Junction BoxWiring Trough Assembly Unit Interconnecting CableDirectional ControlValve (Withdraw)Shutoff Valve Water Accumulation DrainScram Accumulation N2 Cylinder Accumulator N 2Cartridge Valve

Accumulator N 2 Charging Accumulator

Instrumentation

AssemblyIsolation ValveScram Valve Pilot AirIsolation ValveExhaust Water RiserIsolation Valve Insert RiserIsolation Valve Scram Discharge RiserOutlet Scram ValveInlet Scram Valve Directional ControlValve (Insert) ManifoldDirectional Control Valve (Withdraw and Settle)Scram Water Accumulator FrameDirectional Control Valve (Insert)Isolation ValveCooling Water RiserScram Pilot Valve

AssemblyPressure Indicator Columbia Generating StationFinal Safety Analysis Report Control Rod Drive Housing Support 900547.26 4.6-8FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.BracketSteel Form LinerCRDHousingHangerRodReactor Vessel

Support PedestalCRD Flange Support Bar Grid Clamp Grid Bolt Grid Plates Disc SpringsBeamsWasherJam NutNutColumbia Generating StationFinal Safety Analysis Report COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS Section Page 5-i 5.1 SUMMARY DESCRIPTION............................................................5.1-1 5.1.1 SCHEMATIC FLOW DIAGRAM...................................................5. 1-3 5.1.2 PIPING AND INSTRUMENTATION DIAGRAM............................... 5.1-3 5.1.3 ELEVATION DRAWING.............................................................5.1-3 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY...........5.2-1 5.2.1 COMPLIANCE WITH CO DES AND CODE CASES...........................5.2-1 5.2.1.1 Compliance with 10 CFR Part 50, Section 50.55a..............................5.2-1 5.2.1.2 Applicable Code Cases...............................................................5.2-1 5.2.2 OVERPRESSURIZATION PROTECTION........................................5.2-2 5.2.2.1 Design Bases...........................................................................5.2-2 5.2.2.1.1 Safety Design Basis.................................................................5.2-2 5.2.2.1.2 Power Genera tion Design Bases.................................................5.2-2 5.2.2.1.3 Di scussion............................................................................5.2-3 5.2.2.1.4 Safety Valve Capacity..............................................................5.2-3 5.2.2.2 Design Evaluation.....................................................................5.2-4 5.2.2.2.1 Method of Analysis.................................................................5.2-4 5.2.2.2.2 System Design.......................................................................5.2-4 5.2.2.2.3 Evaluati on of Results...............................................................5.2-5 5.2.2.2.3.1 Safety Valve Capacity...........................................................5.2-5 5.2.2.2.3.2 Pressure Dr op in Inlet and Discharge.........................................5.2-6 5.2.2.2.3.3 Reload Speci fic Confirmatory Analysis......................................5.2-6 5.2.2.3 Piping and Instrument Diagrams....................................................5.2-6 5.2.2.4 Equipment and Component Description...........................................5.2-6 5.2.2.4.1 Desc ription...........................................................................5.2-6 5.2.2.4.2 Design Parameters..................................................................5.2-9 5.2.2.4.2.1 Safety/Relief Valve..............................................................5.2-9 5.2.2.5 Mounting of Pressure Relief Devices..............................................5.2-10 5.2.2.6 Applicable Codes and Classification...............................................5.2-10 5.2.2.7 Material Specification................................................................5.2-10 5.2.2.8 Process Instrumentation..............................................................5.2-10 5.2.2.9 System Reliability.....................................................................5. 2-10 5.2.2.10 Inspection and Testing..............................................................5.2-11 5.2.3 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS............5.2-16 5.2.3.1 Material Specifications...............................................................5.2-16 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-02-046 5-ii 5.2.3.2 Compatibility with Reactor Coolant................................................5.2-16 5.2.3.2.1 Pressurized Water Reactor Chemistry of Reactor Coolant..................5.2-16 5.2.3.2.2 Boiling Water Reactor Ch emistry of Reacto r Coolant.......................5.2-16 5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant.............5.2-19 5.2.3.2.4 Compatibility of Constructi on Materials with External Insulation and Reactor Coolant................................................................ 5.2-20 5.2.3.3 Fabrication and Processing of Ferritic Materials and Austenitic Stainless Steels.........................................................................5.2-20 5.2.4 INSERVICE INSPECTION AND TESTING OF THE REACTOR COOLANT PRESSURE BOUNDARY.............................................5.2-21 5.2.4.1 System Boundary Subject to Inspection...........................................5.2-21 5.2.4.2 Arrangement of Systems and Components to Provide Accessibility.........5.2-22 5.2.4.2.1 Reactor Pr essure Vessel...........................................................5. 2-23 5.2.4.2.2 Piping, Pu mps, and Valves.......................................................5.2-24 5.2.4.3 Examination Techniques and Procedures.........................................5.2-24 5.2.4.3.1 Equipment for Inservice Inspection..............................................5.2-24 5.2.4.3.2 Coordination of Inspection Equipment With Access Provisions............5.2-25 5.2.4.3.3 Manual Examination...............................................................5.2-25 5.2.4.4 Inspection Intervals...................................................................5. 2-25 5.2.4.5 Examination Categories and Requirements.......................................5.2-25 5.2.4.6 Evaluation of Examination Results.................................................5.2-25 5.2.4.7 System Leakage and Hydrostatic Pressure Tests................................5.2-26 5.2.4.8 Inservice Inspection Commitment..................................................5.2-26 5.2.4.9 Augmented Inservice Inspecti on to Protect Against Postulated Piping Failures..................................................................................5.2-26 5.2.4.10 Augmented Inservice Inspection of Reactor Pressure Vessel Feedwater Nozzles.................................................................................5.2-27 5.2.4.10.1 Pr eservice Examination.......................................................... 5.2-27 5.2.4.10.2 Inservi ce Examination............................................................5.2-27 5.2.4.11 Augmented Inservice Inspec tion for Intergrannular Stress Corrosion Cracking................................................................................5.2-27 5.2.4.12 ASME Section XI Repairs/Replacements........................................5.2-27 5.2.5 DETECTION OF LEAKAGE THROUGH REACTOR COOLANT PRESSURE BOUNDARY............................................................. 5.2-28 5.2.5.1 Leakage Detection Methods.........................................................5.2-28 5.2.5.1.1 Detection of Abnormal Leakage Within the Primary Containment........5.2-28 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-02-046, 04-033 5-iii 5.2.5.1.2 Detection of Abnormal Leakage Outside the Primary Containment.......5.2-29 5.2.5.2 Leak Detection Devices..............................................................5.2-30 5.2.5.3 Indication in the Control Room.....................................................5.2-31 5.2.5.4 Limits for Reactor Coolant Leakage...............................................5.2-32 5.2.5.4.1 Total Leakage Rate.................................................................5.2-32 5.2.5.4.2 Normally Exp ected Leakage Rate................................................5.2-32 5.2.5.5 Unidentified Leakage Inside the Drywell.........................................5.2-33 5.2.5.5.1 Unidentified Leakage Rate........................................................5.2-33 5.2.5.5.2 Length of Through-Wall Flaw....................................................5.2-33 5.2.5.5.3 Criteria to Evaluate the Adequacy and Margin of the Leak Detection System....................................................................5.2-34 5.2.5.6 Safety Interfaces.......................................................................5. 2-34 5.2.5.7 Testing and Calibration...............................................................5.2-34 5.

2.6 REFERENCES

........................................................................... 5.2-34 5.3 REACTOR VESSEL......................................................................5.3-1 5.3.1 REACTOR VESS EL MATERIALS..................................................5.3-1 5.3.1.1 Materials Specifications..............................................................5.3-1 5.3.1.2 Special Processes Used for Manufacturing and Fabrication...................5.3-1 5.3.1.3 Special Methods for Nondestructive Examination...............................5.3-2 5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels...................5.3-2 5.3.1.5 Fracture Toughness...................................................................5.3-2 5.3.1.5.1 Compliance with Code Requirements...........................................5.3-2 5.3.1.5.2 Compliance with 10 CFR 50 Appendix G......................................5.3-2 5.3.1.5.2.1 Intent of Proposed Approach...................................................5.3-3 5.3.1.5.2.2 Operating Limits Based on Fracture Toughness............................5.3-3 5.3.1.5.2.3 Temperature Limits for Boltup.................................................5.3-5 5.3.1.5.2.4 Inservice Inspection Hydrostatic or Leak Pressure Tests..................5.3-5 5.3.1.5.2.5 Operating Limits During Heatup, Cool down, and Core Operation.....5.3-6 5.3.1.5.2.6 Reactor Vessel Annealing.......................................................5.3-6 5.3.1.6 Material Surveillance.................................................................5.3-6 5.3.1.6.1 Positioning of Surveillance Capsules and Method of Attachment for Plant-Specific Surveillance Program............................................5.3-7 5.3.1.6.2 Time and Number of Dosimetry Measurements...............................5.3-7 5.3.1.6.3 Neutron Flux and Fluence Calculations......................................... 5.3-8 5.3.1.7 Reactor Vessel Fasteners.............................................................5.3-8 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-04-033 5-iv 5.3.2 PRESSURE-TEMP ERATURE LIMITS.............................................5.3-9 5.3.2.1 Limit Curves...........................................................................5.3-9 5.3.2.2 Operating Procedures.................................................................5.3-9 5.3.3 REACTOR VESSEL INTEGRITY...................................................5.3-9 5.3.3.1 Design...................................................................................5.3-10 5.3.3.1.1 Desc ription...........................................................................5.3-10 5.3.3.1.1.1 Reactor Vessel....................................................................5. 3-10 5.3.3.1.1.2 Shroud Support...................................................................5. 3-10 5.3.3.1.1.3 Protec tion of Closure Studs.....................................................5.3-10 5.3.3.1.2 Safety Design Bases................................................................5.3-11 5.3.3.1.3 Power Genera tion Design Basis..................................................5.3-11 5.3.3.1.4 Reactor Ve ssel Design Data...................................................... 5.3-11 5.3.3.1.4.1 Vessel Support....................................................................5. 3-12 5.3.3.1.4.2 Control Rod Drive Housings...................................................5.3-12 5.3.3.1.4.2.1 Contro l Rod Drive Return Line.............................................5.3-12 5.3.3.1.4.3 In-Core Ne utron Flux Monitor Housings....................................5.3-12 5.3.3.1.4.4 Reactor Vessel Insulation.......................................................5.3-12 5.3.3.1.4.5 Reactor Vessel Nozzles.........................................................5.3-12 5.3.3.1.4.6 Materials and Inspection........................................................5.3-14 5.3.3.1.4.7 Reactor Vessel Schematic (BWR).............................................5.3-14 5.3.3.2 Material s of Construction............................................................5.3-14 5.3.3.3 Fabr ication Methods..................................................................5.3-15 5.3.3.4 Inspection Requirements.............................................................5.3-15 5.3.3.5 Shipment and Installation............................................................5.3-15 5.3.3.6 Operating Conditions.................................................................5.3-16 5.3.3.7 Inservice Surveillance................................................................5.3-16 5.

3.4 REFERENCES

........................................................................... 5.3-17 5.4 COMPONENT AND SUBSYSTEM DESIGN.......................................5.4-1 5.4.1 REACTOR RECIRC ULATION PUMPS...........................................5.4-1 5.4.1.1 Safe ty Design Bases...................................................................5.4-1 5.4.1.2 Power Ge neration Design Bases....................................................5.4-1 5.4.1.3 Description.............................................................................5.4-1 5.4.1.3.1 Recirculation System Cavitation Consideration...............................5.4-5 5.4.1.4 Safety Evaluation......................................................................5.4-5 5.4.1.5 Inspection and Testing................................................................5.4-6 COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-00-056, 01-009, 01-025 5-v 5.4.2 STEAM GENERA TORS (PWR).....................................................5.4-6 5.4.3 REACTOR COOLANT PIPING......................................................5. 4-7 5.4.4 MAIN STEAM LINE FLOW RESTRICTORS....................................5.4-7 5.4.4.1 Safe ty Design Bases...................................................................5.4-7 5.4.4.2 Description.............................................................................5.4-7 5.4.4.3 Safety Evaluation......................................................................5.4-8 5.4.4.4 Inspection and Testing................................................................5.4-8 5.4.5 MAIN STEAM LINE ISOLATION SYSTEM.....................................5.4-9 5.4.5.1 Safe ty Design Bases...................................................................5.4-9 5.4.5.2 Description.............................................................................5.4-10 5.4.5.3 Safety Evaluation......................................................................5. 4-12 5.4.5.4 Inspection and Testing................................................................5.4-13 5.4.6 REACTOR CORE ISOL ATION COOLING SYSTEM..........................5.4-14 5.4.6.1 Design Bases...........................................................................5.4-14 5.4.6.2 System Design.........................................................................5.4-16 5.4.6.2.1 General............................................................................... 5.4-16 5.4.6.2.1.1 Description........................................................................5. 4-16 5.4.6.2.1.2 Diagrams...........................................................................5.4-17 5.4.6.2.1.3 Interlocks..........................................................................5.4-18 5.4.6.2.2 Equipment and Co mponent Description........................................ 5.4-19 5.4.6.2.2.1 Design Conditions................................................................5.4-19 5.4.6.2.2.2 Design Parameters...............................................................5.4-20 5.4.6.2.2.3 Overpressure Protection.........................................................5.4-25 5.4.6.2.3 Applicable Codes and Classifications........................................... 5.4-27 5.4.6.2.4 System Reliab ility Considerations............................................... 5.4-27 5.4.6.2.5 System Operation...................................................................5. 4-28 5.4.6.2.5.1 Au tomatic Operation.............................................................5.4-28 5.4.6.2.5.2 Test Loop Operation.............................................................5.4-29 5.4.6.2.5.3 Steam Conden sing (Hot Standby) Operation................................5.4-29 5.4.6.2.5.4 Manual Actions...................................................................5. 4-30 5.4.6.2.5.5 Reactor Core Isolation Cooling Discharge Line Fill System.............5.4-30 5.4.6.3 Performance Evaluation..............................................................5.4-30 5.4.6.4 Preope rational Testing................................................................5.4-30 5.4.6.5 Safety Interfaces.......................................................................5. 4-30 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-04-027 5-vi 5.4.7 RESIDUAL HEAT REMOVAL SYSTEM.........................................5.4-30 5.4.7.1 Design Bases...........................................................................5.4-30 5.4.7.1.1 Functiona l Design Basis...........................................................5.4-31 5.4.7.1.2 Design Basis fo r Isolation of Residual Heat Removal System from Reactor Coolant System........................................................... 5.4-33 5.4.7.1.3 Design Basis for Pr essure Relief Capacity.....................................5.4-33 5.4.7.1.4 Design Basis With Respect to General Design Criterion 5..................5.4-36 5.4.7.1.5 Design Basis for Reliability and Operability................................... 5.4-36 5.4.7.1.6 Design Basis for Protect ion from Physical Damage..........................5.4-37 5.4.7.2 Systems Design........................................................................5. 4-37 5.4.7.2.1 System Diagrams...................................................................5. 4-37 5.4.7.2.2 Equipment and Co mponent Description........................................ 5.4-38 5.4.7.2.3 Controls a nd Instrumentation..................................................... 5.4-40 5.4.7.2.4 Applicable Codes and Classifications........................................... 5.4-40 5.4.7.2.5 Reliability Considerations......................................................... 5.4-41 5.4.7.2.6 Manual Action.......................................................................5. 4-41 5.4.7.3 Performance Evaluation..............................................................5.4-41 5.4.7.3.1 Shutdown Cooling With All Components Available..........................5.4-42 5.4.7.3.2 Shutdown Cooling With Most Limiti ng Failure...............................5.4-42 5.4.7.4 Preope rational Testing................................................................5.4-42 5.4.8 REACTOR WATER CLEANUP SYSTEM........................................5.4-43 5.4.8.1 Design Bases...........................................................................5.4-43 5.4.8.1.1 Safety Design Bases................................................................5.4-43 5.4.8.1.2 Power Genera tion Design Bases.................................................5.4-43 5.4.8.2 System Description....................................................................5. 4-44 5.4.8.3 System Evaluation.....................................................................5. 4-45 5.4.8.4 Demi neralizer Resins.................................................................5.4-46 5.4.8.5 Reactor Water Cleanup Water Chemistry.........................................5.4-46 5.4.8.5.1 Analy tical Methods.................................................................5. 4-46 5.4.8.5.2 Relationship of Filter-Demineralizer Condition to Water Chemistry......5.4-46 5.4.9 MAIN STEAM LINES AND FEEDWATER PIPING........................... 5.4-47 5.4.9.1 Safe ty Design Bases...................................................................5. 4-47 5.4.9.2 Power Ge neration Design Bases....................................................5.4-47 5.4.9.3 Description.............................................................................5.4-47 5.4.9.4 Safety Evaluation......................................................................5. 4-48 5.4.9.5 Inspection and Testing................................................................5.4-48 COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-01-009, 01-025 5-vii 5.4.10 PRESSURIZER......................................................................... 5.4-48 5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM.............................. 5.4-48 5.4.12 VALVES.................................................................................5.4-48 5.4.12.1 Safety Design Bases.................................................................5.4-48 5.4.12.2 Description............................................................................5.4-48 5.4.12.3 Safety Evaluation....................................................................5. 4-49 5.4.12.4 Inspection and Testing..............................................................5.4-49 5.4.13 SAFETY AND RELIEF VALVES.................................................5.4-50 5.4.13.1 Safety Design Bases.................................................................5.4-50 5.4.13.2 Description............................................................................5.4-50 5.4.13.3 Safety Evaluation....................................................................5. 4-50 5.4.13.4 Inspection and Testing..............................................................5.4-50 5.4.14 COMPONENT AND PIPING SUPPORTS.......................................5.4-50 5.4.14.1 Safety Design Bases.................................................................5.4-51 5.4.14.2 Description............................................................................5.4-51 5.4.14.3 Inspection and Testing..............................................................5.4-51 5.4.15 HIGH-PRESSURE CO RE SPRAY SYSTEM....................................5.4-52 5.4.16 LOW-PRESSURE CORE SPRAY SYSTEM.....................................5.4-52 5.4.17 STANDBY LIQUID CONTROL SYSTEM.......................................5.4-52 5.4.18 REFERENCES......................................................................... 5.4-52

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF TABLES

Number Title Page LDCN-02-000 5-viii 5.2-1 Exceptions to Conform ance to 10 CFR 50.55a

Reactor Coolant Pressure Boundary Components 5.2-37 5.2-2 Reactor Coolant Pressure Boundary Component Code Case Interpr etations 5.2-38

5.2-3 Nuclear Sy stem Safety/Relief Setpoints 5.2-39

5.2-4 Systems Which May Ini tiate During Safety Valve

Capacity Overpressure Event 5.2-40 5.2-5 Sequence of Events for Figure 5.2-2 5.2-41 5.2-6 Design Temperature, Pressure and Maximum T est Pressure for RCPB Components 5.2-42

5.2-7 Reactor Coolant Press ure Boundary M aterials 5.2-45

5.2-8 Water Sample Locations 5.2-48 5.2-9 IHSI Summary Prior to First Refueling GL 88-01 Category B Welds 5.2-49 5.2-10 IHSI Summary During First Refueling GL 88-01 Category B Welds 5.2-50 5.2-11 Main Steam Isolation Valv es Material Information 5.2-51 5.2-12 Summary of Isolation/Alarm of System Monitored and the Leak Detection Methods Used 5.2-52 5.3-1 10 CFR 50 Appendix G Matrix 5.3-19 5.3-2 Plate Material Cross Reference 5.3-23 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF TABLES (Continued)

Number Title Page LDCN-04-033 5-ix 5.3-3 Weld Material Cr oss Reference..............................................5.3-24 5.3-4 Plate Material.................................................................... 5.3-25 5.3-5 Weld Material...................................................................5.3-26

5.3-6 Vessel Beltli ne Plate............................................................5.3-29

5.3-7 Vessel Beltline Weld Material Chemistry..................................5.3-30 5.3-8 10 CFR 50 Appendi x H Matrix..............................................5.3-31

5.3-9 Reactor Vessel Beltline Minimum Wall Thickness and Diameter......5.3-33

5.4-1 Reactor Coolant Pressu re Boundary Pump and Valve Description.......................................................................5. 4-53 5.4-2 Reactor Recirculation System Design Characteristics....................5.4-58

5.4-3 Operating Experience of I ngersoll-Rand Emergency Core Cooling Systems Pumps........................................................5.4-60

5.4-4 Operating Experience of Sim ilar Ingersoll-Rand Pumps for BWR Projects Under Review..................................................5.4-61

5.4-5 Reactor Water Cleanup System...............................................5.4-62

5.4-6 Safety and Relief Valve for Piping Systems Connected to the Reactor Coolant Pressure Boundary................................. 5.4-63 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES

Number Title LDCN-15-011 5-x 5.1-1 Rated Operating Conditions of the Boiling Water Reactor 5.1-2 Coolant Volumes of the Boiling Water Reactor 5.2-1 Simulated Safety Relief Valve Spring Mode Characteristic Used for Capacity Sizing Analysis

5.2-2 MSIV Closure with Flux Scram - Nominal Safety Setpoint +3% 6 SRV Out-of-Service

5.2-3 Peak Vessel Pressure Versus Safety Valve Capacity

5.2-4 Time Response of Pressure Vessel For Pressurization Events

5.2-5 Nuclear Boiler System (P&ID)

5.2-6 Safety/Relief Valve Schematic Elevation

5.2-7 Safety/Relief Valve and Steam Line Schematic

5.2-8 Schematic of Safety Valve With Auxiliary Actuating Device

5.2-9 Safety Valve Lift Versus Time Characteristics

5.2-10 Conductance Versus pH as a Function of Chloride Concentration of Aqueous Solution at 25°C

5.2-11 Deleted

5.3-1 Pressure Temperature Limits - Cu rves A through C (Sheets 1 through 3)

5.3-2 Vessel Beltline Plate and Weld Seam Identification

5.3-3 Nominal Reactor Vessel Water Level Trip and Alarm Elevation Settings

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES (Continued)

Number Title 5-xi 5.3-4 Bracket for Holdin g Surveillance Capsule 5.3-5 Reactor Vessel

5.3-6 Feedwater Nozzle

5.3-7 Feedwater Sparger

5.4-1 Recirculation System Evaluation and Isometric

5.4-2 RRC Pump Dynamic Head - Flow Curve

5.4-3 RRC Pump Speed - Torque Curve

5.4-4 Recirculation Pump Head, NPSH, Flow and Efficiency Curves

5.4-5 Operating Principle of Jet Pump

5.4-6 Core Flooding Capability of Recirculation System

5.4-7 Reactor Recirculation System - P&ID (Sheets 1 and 2)

5.4-8 Main Steam Line Flow Restrictor Location

5.4-9 Main Steam Line Isolation Valve

5.4-10 Reactor Core Isolation Cooling Pump Performance Curve (Constant Flow) 5.4-11 Reactor Core Isolation Cooling System - P&ID

5.4-12 Reactor Core Isolation Cooling System Process Diagram

5.4-13 Reactor Core Isolation Cooling Pump Performance Curve

5.4-14 Typical Strainer

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES (Continued)

Number Title LDCN-12-036 5-xii 5.4-15 Residual Heat Removal Syst em - P&ID (Sheets 1 through 4) 5.4-16 Residual Heat Removal System Process Diagram

5.4-17 Residual Heat Removal System Process Data (Sheets 1 and 2)

5.4-18 Residual Heat Rem oval (LPCI) Pump Characteristics (S/N 0473113) P-2A

5.4-19 Residual Heat Rem oval (LPCI) Pump Characteris tics (S/N 0801MP004399-1) P-2B 5.4-20 Residual Heat Rem oval (LPCI) Pump Characteristics (S/N 0473112) P-2C

5.4-21 Vessel Coolant Temper ature Versus Time (Two Heat Exchangers Available)

5.4-22 Reactor Water Cleanup System - P&ID (Sheets 1 through 3)

5.4-23 Reactor Water Cleanup System Process Diagram (Sheets 1 and 2)

5.4-24 Filter/Deminera lization System P&ID

5.4-25 Vessel Coolant Temp erature Versus Time (One Heat Exchanger Available)

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.1-1 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

5.1 SUMMARY DESCRIPTION

The reactor coolant system includes those systems and components which contain or transport fluids coming from, or going to the reactor core. These systems form a major portion of the reactor coolant pressure boundary (RCPB). This chapter provides information regarding the reactor coolant system and pressure-containi ng appendages out to a nd including isolation valving. This grouping of components is defined as follows:

The RCPB includes all pressure -containing components such as pressure vessels, piping, pumps, and valves, which are

a. Part of the reactor coolant system, or

b. Connected to the reactor coolant system

, up to and including any and all of the following:

1. The outermost containment isolat ion valve in system piping that penetrates primary reactor containment,

2. The second of the two valves normally closed during normal reactor operation in system piping that doe s not penetrate primary reactor containment, and

3. The reactor coolant system safety/relief valves.

Section 5.4 discusses the various s ubsystems to the RCPB.

The nuclear system pressure relief system protects the reactor coolant pressure boundary from damage due to overpressure. To protect against overpressure, pr essure-operated relief valves are provided that can discharge steam from the nuclear system to the suppression pool. The pressure relief system also acts to automatically depre ssurize the nuclear system in the event of a loss-of-coolant accident (LOCA ) in which the high-pressure core spray (HPCS) system fails to maintain reactor vessel water level. Depressurization of the nuclear system allows the low-pressure core cooling systems to supply enough cooli ng water to adequately cool the fuel. Section 5.2.5 establishes the limits on nuclear system leakage inside th e drywell so that appropriate action can be taken before the integrity of the nuclear system process barrier is impaired.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.1-2 The reactor vessel and appurtenan ces are described in Section 5.3. The major safety consideration for the reactor vessel is concerned with the ability of the vessel to function as a radioactive material barrier. Various combinations of loadi ng are considered in the vessel design. The vessel meets the requirements of various applicable codes and criteria. The possibility of brittle fracture is considered, and suitable design, material selection, material surveillance activities, and operational limits are establishe d that avoid conditions where brittle fracture is possible.

The reactor recirculation system provides coolan t flow through the core. Adjustment of the core coolant flow rate changes reactor power output, thus providing a means of following plant load demand without adjusting control rods. The recirculation system is designed to provide a slow coast down of flow so that fuel thermal limits cannot be exceeded as a result of recirculation system malfunctions. The arrangement of the recircul ation system routing is such that a piping failure cannot compromise the integrity of th e floodable inner volume of the reactor vessel.

Main steam line flow restrictors of the venturi-type are installed in each main steam line inside the primary containment. The restrictors ar e designed to limit the loss-of-coolant resulting from a main steam line break outsi de the primary containment. The coolant loss is limited so that reactor vessel water level remains above the top of the core during the time required for the main steam isolation valves (MSIVs) to close. This action protects the fuel barrier.

The MSIVs automatically isolate the reactor coolant pressure boundary in the event a pipe break occurs downstream of the isolation valves . This action limits th e loss-of-coolant and the release of radioactive materials from the nuclear system. Two isolation valves are installed on each main steam line; one is located inside, and the other is located outside the primary containment. In the event that a main steam li ne break occurs inside the containment, closure of the other isolation valve outside the primary containment acts to seal the containment itself.

The reactor core isolation cooling (RCIC) system provides makeup water to the core during a reactor shutdown in which feedwater flow is not available. The system is started automatically upon receipt of a low reactor water level signal or manually by the operator. Water is pumped to the core by a turbine pum p driven by reactor steam.

The residual heat removal (RHR) system includes a number of pumps and heat exchangers that can be used to cool the nuclear system under a variety of situations. During normal shutdown and reactor servicing, the RHR system removes residual and decay heat. The RHR system allows decay heat to be removed whenever the main heat sink (main conde nser) is not available (e.g., hot standby). One mode of RHR operation allows the rem oval of heat from the primary containment following a LOCA. Another op erational mode of the RHR system is COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009 5.1-3 low-pressure coolant injection (LPCI). The LPCI operation is an engineered safety feature for use during a postulated LOCA. This operation is descri bed in Section 6.3. The low-pressure core spray (LPCS) system also provide s protection to the nuclear system.

The reactor water cleanup system recirculates a portion of reactor coolant through a filter-demineralizer subsystem to remove particulate and disso lved impurities fr om the reactor coolant. It also removes ex cess coolant from the reactor sy stem under controlled conditions.

5.1.1 SCHEMATIC FLOW DIAGRAM Schematic flow diagrams of the reactor coolant system denoting all major components, principal pressures, temperatur es, flow rates, and coolant volumes for normal steady-state operating conditions at rated power are presented in Figures 5.1-1 and 5.1-2. 5.1.2 PIPING AND INST RUMENTATION DIAGRAM

Piping and instrumentation diagrams covering the systems included within the reactor coolant system and connected systems are presented in the following:

a. The nuclear boiler, main steam, and feedwater systems shown in Figure 10.3-2

, b. Recirculation system shown in Figure 5.4-7 , c. RCIC system shown in Figure 5.4-11 , d. RHR system shown in Figures 5.4-16 and 5.4-17, e. Reactor water cleanup system shown in Figure 5.4-22 , f. HPCS system shown in Figure 6.3-4 , g. LPCS system shown in Figure 6.3-4 , and h. Standby liquid control system shown in Figure 9.3-14 . 5.1.3 ELEVATION DRAWING

An elevation drawing showing the principal dime nsions of the reactor and coolant system in relation to the containment is shown in Figures 1.2-11 and 1.2-12. 108.5 x 10

61. Core Inlet

2. Core Outlet

3. Separator Outlet (Steam Dome)

4. Steam Line (2nd Isolation Valve)

5. Feedwater Inlet (Includes RWCU Return Flow)

6. Recirculating Pump Suction

7. Recirculating Pump Discharge 1069 1047 1035 1000 1063 1037 1327534 550 549 545 421 534 535528.7 639.91191.0 1191.0398.5 528.4 529.8PRESSURE(psia)FLOW(lb/hr)TEMP.(F)ENTHALPY(Btu/lb)108.5 x 10 6*FCVFCVJet PumpCoreRecirculation PumpDriving Flow Main Feed FlowMain Steam Flow Turbine Steam Dryers Steam Separators 7165432Note 1Note 1* Channel Bypass - Nominally 10% Note 1: The FCVs are kept in mechanically blocked full open position.

Note 1Rated Operating Conditions of theBoiling Water Reactor 900547.44 5.1-1FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.15.0 x 10 615.0 x 10 615.2 x 10 632 x 10632 x 106Columbia Generating StationFinal Safety Analysis Report A. Lower Plenum B. Core C. Upper Plenum and Separators D. Dome (Above Normal Water Level)

E. Downcomer Region F. Recirculating Loops and Jet Pumps 4010 1990 2290 7160 5210 1010Volume of Fluid (ft

3) Note1: The FCVs are kept in mechanically blocked full open position.Coolant Volumes of the Boiling Water Reactor 960690.04 5.1-2FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report FCVFCVJet PumpCoreRecirculation PumpDriving Flow Main Feed FlowMain Steam Flow Turbine Steam Dryers Steam Separators Note 1Note 1Note 1BADFEC COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 5.2-1 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY

This section discusses measures employed to provide and maintain the integrity of the reactor coolant pressure boundary (RCPB) for the plant design lifetime.

5.2.1 COMPLIANCE WITH CODES AND CODE CASES

5.2.1.1 Compliance with 10 CFR Part 50, Section 50.55a Table 3.2-1 shows compliance with the rules of 10 CFR Part 50.55a "Code s and Standards." The American Society of Mechanical Engineers (ASME) Code edition, applicable addenda, and component dates are in accordance with 10 CFR 50.55a except for those RCPB components listed in Table 5.2-1 . The design, fabrication, and testing of the RCPB components listed in Table 5.2-1 were in accordance with the recognized codes and standards in effect at the time th e components were ordered as shown in the table. The code edition and applicable addenda that would be required by strict interpreta tion of the rules set forth in 10 CFR 50.55a are identified in Table 5.2-1 . Application for Columbia Generating Stati on (CGS) was filed with the Commission in August 1971. At that time a construction perm it was expected before the end of the 1972, but requests for additional seismic data in August 1972 caused the issuance of the construction permit to go beyond the end of the year to Ma rch 19, 1973. As is common practice in the utility industry, Energy Northwest proceeded with the engineering, design, and material and components procurement in anticipation of th e award of a construction permit to meet construction schedules. Had the construction permit been is sued as initially expected, the requirements of 10 CFR 50.55a would have been met to the letter of the law.

However, in each instance of exception the ASME Code version a pplied was one addenda earlier (6 months) than the code version requi red by the rules of 10 CFR 50.55a. The changes embodied in the later ASME Code addenda were reviewed. It was concluded that the addenda required by the rules of 10 CFR 50.55a affected documentation format but imposed no new technical requirements or change s in quality control procedures from the code version applied in the procurement of the components. Th e level of safety and quality provided by conformance to the earlier code edition and addenda applied in procurement is equivalent to that which would be required by strict application of the rules of 10 CFR 50.55a. The effort and expense of recertification of these com ponents, which had all been shipped to the construction site, would not have provided a comp ensating increase in th e level of safety and quality.

5.2.1.2 Applicable Code Cases

The reactor pressure vessel (R PV) and appurtenances and the RC PB piping, pumps and valves, were designed, fabricated, and tested in accordance with the applicable edition of the ASME COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-2 Code, Section III, including the addenda that were mandatory at the order date for the applicable components. This is in compliance with the intent of Regulat ory Guides 1.84 and 1.85. Section 50.55a of 10 CFR Part 50 requires code case approval only for Class 1 components. These code cases contain requirements or special rules which may be used for the construction of pressure-retaining components of Quality Group Classification A. The various ASME Code case interpretations that were applied to components in the RCPB are listed in Table 5.2-2. Code cases listed in Table 5.2-2 are those used in the original construction of CGS. Other c ode cases that are a dopted for use, as a pproved by Regulatory Guides 1.147, 1.84, 1.85, or specifically approved by the Regulatory Authority for use at CGS, are specified in the component's design specification as required by ASME Section III. 5.2.2 OVERPRESSURIZATION PROTECTION

5.2.2.1 Design Bases

Overpressurization protection is provided in conformance with 10 CFR 50, Appendix A,

General Design Criterion 15.

5.2.2.1.1 Safety Design Basis

The nuclear pressure-relie f system is designed to

a. Prevent overpressurization of the nuclear system that could lead to the failure of the RCPB,

b. Provide automatic depr essurization for small breaks in the nuclear system occurring with maloperation of the high-pressure core spray (HPCS) system so that the low-pressure coolant injection (LPCI) and the low-pressure core spray (LPCS) systems can operate to protect the fuel barrier (see Section 6.3.2.2.2

),

c. Permit verification of its operability, and

d. Withstand adverse combinations of load ings and forces resulting from operation during abnormal, accident, or special event conditions.

5.2.2.1.2 Power Gene ration Design Bases The nuclear pressure relief system safety/relief valves (SRV) ha ve been designed to meet the following power ge neration bases:

a. Discharge to the containment suppression pool, and

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-98-113 5.2-3 b. Correctly reclose following operation so that maximum operational continuity can be obtained.

5.2.2.1.3 Discussion

The ASME Boiler and Pressure Vessel Code (B&PV Code) requires that each component designed to meet Section III be protected from overpressure under upset conditions. The code allows a peak allowable pressu re of 110% of design pressure under upset c onditions. The code specifications for safety valves require that (a) the lowest safety valve setpoint will be set at or below design pressure, and (b) the highest safety valve setpoint will be set so that total accumulated pressure does not exceed 110% of the design pressure for upset conditions. The SRVs are designed to open by means of either of two modes of operation as discussed in Chapter 15. The safety (spring) setpoints are listed in Table 5.2-3 and satisfy the first of the above-mentioned ASME Code specifi cations for safety valves becau se all valves open at less than the nuclear system de sign pressure of 1250 psig.

The automatic depressurization capability of the nucl ear system pressure relief system is evaluated in Sections 6.3 and 7.3. The following detailed criteria are used in selection of SRVs:

a. Must meet requirements of ASME Code, Section III,

b. Valves must qualify for 100% of na meplate capacity cred it for overpressure protection function, and

c. Must meet other performance require ments such as response time, etc., as necessary to provide relief functions.

The SRV discharge piping is constructed in accordance with the ASME Code, Section III, 1971 Edition through the Winter 1973 Addenda.

5.2.2.1.4 Safety Valve Capacity

The safety valve capacity of this plant is ad equate to limit the primary system pressure, including transients, to the re quirements of the ASME B&PV Code, Section III, 1971 Edition through the Summer 1971 Addenda.

Table 5.2-4 lists the systems which c ould initiate during the safety valve capacity overpressure event.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 5.2-4 5.2.2.2 Design Evaluation

5.2.2.2.1 Method of Analysis

To design the pressure protection for the nuclear boiler system, extensive analytical models representing all essential dynamic characteristic s of the system are simulated on a large computing facility. These models include the hydrodynamics of the flow loop, the reactor

kinetics, the thermal characteristics of the fuel and its transfer of heat to the coolant, and all the principal controller features, such as feedwater flow, recircula tion flow, reactor water level, pressure, and load demand. These are presented with all their principal nonlinear features in models that have evolved through extensive expe rience and favorable co mparison of analysis with actual boiling water reactor (BWR) test data.

A detailed description of the models is documented in licensi ng topical reports, References 5.2-1 and 5.2-7. Safety/relief valves are simulated in the nonlinear repr esentation, and the models thereby allow full investigation of the various valve response times, valve capacities, and actuation setpoints that are available in applicable hardware systems.

The typical capacity characteristic as modeled is represented in Figure 5.2-1 for the spring mode of operation. The associated turbine bypass, turbine control valve (TCV), and main steam isolation valve (MSIV) characteristics are also simulated in the models.

The associated bypass, TCV, main steam isolation character istics, and anticip ated transients without scram (ATWS) pump trip are al so represented fully in the models.

5.2.2.2.2 System Design

The overpressure protection system must ac commodate the most se vere pressurization transient. There are two major transients, the closure of a ll MSIVs and a turbine generator trip with a coincident failure of the turbine steam bypass system valves, that represent the most severe abnormal operational transients resulting in a nuclear system pressure rise. The evaluation of transient behavior with final pl ant configuration has s hown that the isolation valve closure is slightly more severe when credit is taken onl y for indirect derived scrams; therefore, it is used as the overpressure protection basis event and shown in Figure 5.2-2 . Table 5.2-5 lists the sequence of events of the vari ous systems assumed to operate during the main steam line isolation closure with flux scram event.

Compliance to ASME Code overpressure protec tion requirements for in troduction of GNF2 fuel has been conservatively demonstrated fo r the limiting overpressu re event. The GE thermal-hydraulic and nuclear coupled transient code TR ACG (References 5.2-7 and 5.2-8) was used to obtain system res ponse and peak vessel pressure. The setpoints ar e listed in Table 5.2-3. The evaluation, based on r eactor operation at 100% of upr ated power, end-of-cycle nuclear dynamic parameters, an initial dome pr essure of 1035 psia (nominal uprated dome

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 5.2-5 pressure), six SRVs with lowest safety setpoints out of servi ce, and SRV opening pressures at 3% above nominal setpoint values resulted in a maximum reactor pr essure of 1311 psig.

The scram reactivity curve is shown in Figure 5.2-2 . 5.2.2.2.3 Evaluation of Results

5.2.2.2.3.1 Safety Valve Capa city. The required SRV capacity is determined by analyzing the pressure rise from an MSIV closure with fl ux scram transient. The plant is assumed to be operating at the turbine-generato r design conditions at a nominal vessel dome pressure of 1035 psia. The analysis hypothetically assumes the failure of the direct MSIV position scram. The reactor is shut down by the backup, high ne utron flux scram. For the analysis, the spring-action safety valve setpoi nts used are in the range of 1236 to 1256 psia. The TRACG analysis indicates that the design valve capacity is capable of mainta ining adequate margin below the peak ASME Code allowable pre ssure in the nuclear system (1375 psig). Figure 5.2-2 shows the result of the TRACG anal ysis. The sequen ce of events in Table 5.2-5 , assumed in these analyses, were investigated to meet code requirements and to evaluate the pressure relief system exclusively.

Under Section III of the ASME B&PV Code, credit can be allowed for a scram from the reactor protection system. In addition, credit is also taken for the protection circuits which are

indirectly derived when determ ining the required SRV capacity.

The backup reactor high neutron flux scram is conservatively applied as a design basis in determining the required capacity of the pressure relieving dual purpose SRVs. Application of the direct position scrams in the design basis c ould be used since they qualify as acceptable pressure protection devices when determining the required SRV capacity of nuclear vessels under the provisions of the ASME Code. The SRVs are operated in a relief mode (pneumatically) at setpoints lower than those specified under the sa fety function. This ensures sufficient margin between anticipated relief mode closing pr essures and valve spring forces for proper seating of the valves.

The typical parametric relationship between peak vessel (bottom) pressure and SRV capacity for the MSIV transient with high flux scram is described in Figure 5.2-3 . Also shown in Figure 5.2-3 is the peak vessel (bottom) pressure for position scram with 18-valve capacity. Pressures shown for flux scram will result only with multiple fa ilure in the redundant direct scram system.

The typical time response of the vessel pressu re to the MSIV transi ent with flux scram is illustrated in Figure 5.2-4 . This shows that the pressure at the vessel bottom exceeds 1250 psig for less than 7 sec and do es not reach the limit of 1375 psig. COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-029 5.2-6 5.2.2.2.3.2 Pressure Drop in Inlet and Discharge. Pressure drop in the piping from the reactor vessel to the valves is taken into account in calculati ng the maximum vessel pressures.

Pressure drop in the discharge piping to the suppression pool is limited by proper discharge line sizing to prevent back-p ressure on each SRV from exceed ing 40% of the valve inlet pressure, thus ensuring choked flow in the valve orifice and no reduction of valve capacity due to the discharge piping. Each SRV has its own separate discharge line. 5.2.2.2.3.3 Reload Specific Confirmatory Analysis. The calculated vessel pressure for MSIV inadvertent closure may be dependent upon the fuel design and core loading pattern. Compliance with the ASME upset limit is demons trated by cycle-dependent analysis just prior to the operation of that cycle. The results are reported in Supplem ental Reload Licensing Report (Reference 5.2-11). 5.2.2.3 Piping and Instrumentation Diagrams

See Figure 5.2-5 which shows the schematic location and number of pressure-relieving devices. The schematic arrangement of the SRVs is shown in Figures 5.2-6 and 5.2-7. 5.2.2.4 Equipment and Component Description

5.2.2.4.1 Description

The nuclear pressure relief system consists of SRVs located on the main steam lines between the reactor vessel and the first isol ation valve within the drywell.

Chapter 15 discusses the events which are expected to activate the primary system SRVs. The chapter also summarizes the number of valves e xpected to operate during the initial blowdown of the valves and the expected duration of this first blowdown. For several of the events it is expected that the lowest set SRV will reopen and reclose as gene rated heat drops into the decay heat characteristics. The pressure increase and relief cycl e will continue with lower frequency and shorter relief discharges as the decay heat drops off and until such time as the residual heat removal (RHR) system can dissipat e this heat. The duration of each relief discharge should, in most cases, be less th an 30 sec. Remote manual actuation of the valves from the control room is recommended to minimize the total number of these discharges, with the intent of achieving extended valve seat li fe and reducing cha llenges to the SRV.

A schematic of the main SRV is shown in Figure 5.2-8 . It is opened by e ither of two modes of operation:

a. The spring mode of operation which c onsists of direct action of the steam pressure against a spring-loaded disk that will pop open when the valve inlet

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-7 pressure force exceeds the spring force. Figure 5.2-9 depicts typical valve lift versus opening time characteristics; and

b. The power-actuated mode of operation which consists of using an auxiliary actuating device consisting of a pneumatic piston/cylinder and mechanical

linkage assembly which opens the valve by overcoming the spring force, even with valve inlet pressure equal to zero psig.

The pneumatic operator is so arra nged that if it malfunctions it will not prevent the valve disk from lifting if steam inlet pressure reaches the spring lift set pressure.

For overpressure SRV operation (self-actuated or spring lift mode), the spring load establishes the safety valve opening setpoint pressure and is set to ope n at setpoints designated in Table 5.2-3. In accordance with the ASME Code, full lift in this mode of operation is attained at a pressure not greater than 3% above the setpoint.

To prevent backpressure from af fecting the spring lift setpoint, each valve is provided with a bellows and balancing piston to c ounteract the effects of any stat ic backpressure which may be present in the discharge line be fore the valve is opened to discharge steam. The bellows isolates steam in the valve disc harge chamber from the valve's internals. If the bellows fails, the balancing piston serves as a functional backup by presenting an effective pi ston area to the back pressure equal to the valve seat area, thus balancing it so there is essentially no net back pressure effect on the setpoint ( Figure 5.2-8 ). The safety function of the SRV is a backup to the relief function described below. The spring-loaded valves are desi gned and constructed in accordan ce with ASME III, 1971 Edition, Paragraph NB-7640, as safety valves with auxiliary actuating devices.

Each SRV is provided with its own pneumatic accumulator and inlet check valve to provide high assurance the valve will actuate in the power-actuated (relief) mode when its pneumatic solenoid valve is energized. The pneumatic accumulator has su fficient capacity to provide one SRV actuation at approximate ly 1000 psig valve inlet pressure. Although no credit is taken under ASME Code Section III for overpressure protec tion by the SRVs in their power-actuated mode, power actuation of the SRV will limit peak reactor pressure in the majority of overpressure transients. Safety/relief valve actuation in the relief mode is initiated by pr essure switches (one per valve) which sense reactor steam space pressure at lower values than the spring mode inlet steam opening pressure. The pressure switches initia te the opening of the SRVs by energizing the pneumatic solenoids (one per valve) at the relief setpoints designated in Table 5.2-3 . When the solenoid is actuated, the delay time, maximum elapsed time between receiving the overpressure signal at the valve actuator and the actual start of valve motion, will not exceed

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-98-113 5.2-8 0.1 sec. The maximum full stroke opening time will not exceed 0.15 sec with 1000 psig steam at the valve inlet.

The SRVs can be operated in th e power-actuated mode by remote-manual controls from the main control room.

The SRVs are designed to operate to the exte nt required for overpressu re protection in the following accident environments:

a. 340°F for a 3-hr period, at drywell design pressure, b. 320°F for an additional 3-hr period, at drywell design pressure, c. 250°F for an additional 18-hr peri od, at 25 psig drywell pressure, and

d. 200°F during the next 99 days at 20 psig drywell pressure.

The automatic depressurization sy stem (ADS) utilizes selected SR Vs for depressurization of the reactor (see Section 6.3). Each of the SRVs utilized for automatic depressuri zation is equipped with an air accumulator and check valve arrangement. These accumulators ensure that the

valves can be held open followi ng failure of the air supply to the accumulators. The designed pneumatic supply to the ADS accumulator is such that, following a failure of the safety-related pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at 70% of design pressure. For a discussion of the noninterruptible air supply to the ADS valves, see Section 9.3.1. Three ADS SRVs and their associ ated solenoid pilot valves (SPV) are qualified for the full post-LOCA time frame for long-term c ooling. All other SRVs and their SPVs are qualified for 24 hr post-LOCA to provide overpressure protection capability.

The valve position indication (VPI) and the tailpipe temperature indication systems are discussed in Section 7.5.2. Each SRV discharges steam through a discharge line to a point below the minimum water level in the suppression pool. Safety/relief valve discharge line piping from the SRV to the suppression pool consists of two parts. The first part is attached at one end to the SRV and at

its other end penetrates and is welded to a 28-in. downcomer (considered a pipe anchor). The main steam piping, including this portion of the SRV discharge piping, is analyzed as a complete system. This portion of the SRV discharge line is cl assified as Quality Group C and Seismic Category I down to the jet deflector plate just above the diaphragm floor (through which it is rigidly guided) and Quality Group B and Seismic Cate gory I from the jet deflector plate to the downcomer.

The second part of the SRV discharge piping extends from the downcomer (anchor) to the suppression pool. Because of the anchor on this part of the line, it is physically decoupled from the main steam header and is, therefore, analyzed as a separate piping system. In analyzing this part of the discharge piping in accordance with the requirements of Quality Group B, the following load combination was considered as a minimum:

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-9 a. Pressure and temperature, b. Dead weight, and

c. Fluid dynamic loads due to SRV operation.

As a part of the preoperational and startup testing of the main steam lines, movement of the SRV discharge lines were inspected w ith negligible vibration observed.

The SRV discharge piping is designed to limit va lve outlet pressure to 40% of maximum valve inlet pressure with the valve open. Water in the line more than a few feet above suppression pool water level would cause excess ive pressure at the valve disc harge when the valve is again opened. For this reason, re dundant 10-in. vacuum relief va lves are provided on each SRV discharge line to prevent drawing an excessive amount of water up into the line as a result of steam condensation following termina tion of relief operation. Each vacuum relief valve pair is situated with the valves in parallel, the discharge being routed to a common tee in the SRV discharge line.

The nuclear pressure relief syst em automatically depressurizes the nuclear system sufficiently to permit the LPCI and LPCS systems to operate as a backup for the HPCS system. Further descriptions of the operation of the automatic depressurization feature are found in Sections 6.3 and 7.3.1.1.1 . 5.2.2.4.2 Desi gn Parameters

Table 5.2-6 lists design temperature, pressure, and maximum test pressure for the RCPB components. The specified opera ting transients for components within the RCPB are given in

Section 3.9. Refer to Section 3.7 for discussion of the input criteria for design of Seismic Category I structures, systems, and components.

A summary of the number of cycles for transients used in design and fatigue analysis is listed in Table 3.9-1 and categorized under the appropriat e design condition (i.e., normal, upset, emergency, and faulted).

The design requirements establishe d to protect the principal com ponents of the reactor coolant system against environmental ef fects are discussed in Section 3.11. 5.2.2.4.2.1 Safety/Relief Valve . The discharge area of the valve is 16.117 in. 2 and the coefficient of discharge KD is equal to 0.966, as certified by the National Board of Boiler and Pressure Vessel Inspectors.

The design pressure and temperature of the va lve inlet and outlet are 1250 psig at 575°F and 625 psig at 500°F, respectively.

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-10 The valves have been designe d to achieve the maximum pr actical number of actuations consistent with state-of-the-art technology. Cyclic testing has de monstrated that the valves are capable of at least 60 actuation cy cles between required maintenance. See Figure 5.2-8 for a schematic cross section of the valve.

5.2.2.5 Mounting of Pressure Relief Devices

The pressure relief devices are located on the main steam piping headers. The mounting consists of a special contour nozzle and an oversized flange connection. This provides a high

integrity connection that accounts for the thru st, bending, and torsiona l loadings which the main steam pipe and relief valve discharge pipe are subjected to.

In no case will allowable valve flange loads be exceeded nor will the stress at a ny point in the piping exceed code allowables for any specified combination of loads. The design criteria and

analysis methods for considering loads due to SRV discharge is contained in Section 3.9.3.3. 5.2.2.6 Applicable C odes and Classification

The RCPB overpressure protection system is designed to satisfy the requirements of Section III, Subsection NB, of the ASME B& PV Code. The gene ral requirements for protection against overpressure as given NB-7120 of Section III of the code recognize that RCPB overpressure protection is one function of the reactor protective systems and allows the

integration of pressure relief devices with the protective syst ems of the nuclear reactor. Hence, credit is taken for the scram protective system as a complement ary pressure protection device.

5.2.2.7 Material Specification

Pressure retaining components of SRVs are constructed only from ASME Section III, Class 1 designated materials.

5.2.2.8 Process Instrumentation

Overpressure protection process instru mentation is listed in Table 1 of Figure 5.2-5 and shown in Figure 10.3-2 . 5.2.2.9 System Reliability

Overpressure protection system reliability is princi pally a function of the SRVs in their spring-opening mode of ope ration. No credit is taken in th e ASME Code Section III required overpressure protection report for power actuation of the SRVs to provide protection against overpressure.

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 5.2-11 Section 5.2.2.10 discusses the inspection and testing c onducted to ensure hi gh SRV reliability. As demonstrated by the extensive qualification and production testing, the valves are very reliable.

In addition to SRV testing to ensure high SRV quality, an extensive in-depth quality assurance program was followed in the manufacture and production testing of the valves to provide assurance of high quality.

A significant amount of BWR operating experience was been accumu lated on this type of SRV, approximately 150 individual valv e years, only one "stuck-open relief valve" had occurred. This was due to an air solenoid valve sticking open after it was deener gized, thus holding the SRV open in the power-actuated mode. Proper ma intenance procedures ar e incorporated into the instruction manual to preclude recurrence.

This type of SRV has demonstrated good inservi ce operability similar to that demonstrated by the qualification test program.

In summary, this type of SRV has demonstrated excellent reliability , both in qualification testing and in act ual BWR operation.

5.2.2.10 Inspection and Testing

To verify the design of the SRV used will reliably operate, several SRVs were subjected to qualification test programs. These qualification test programs de monstrated the design of the valve is capable of performi ng its overpressure protection function under normal, upset, emergency, and faulted c onditions and its designated mechanical motion(s) to fulfill its safety function to shut down the plant or mitigate the c onsequence of a postulated event. To ensure that valves to be installed ar e operable, each valve is manuf actured, inspected, and production tested in accordance with quality control procedures to veri fy compliance with both ASME Code and operability assura nce acceptance criteria.

The SRV design used at CGS su ccessfully complete d the following qua lification tests:

a. Life Cycle Test

Following the prequalification production tests, each modified SRV was then subjected to life cycle qua lification tests with satu rated steam conditions, in accordance with GE specification 22A6595. This included approximately 300 relief (power) and safety (pressur e) actuations to demonstrate and characterize each valve for acceptable BWR service. Tests parameters included:

1. Seat tightness/leakage characteristics, COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-12 2. Set pressure,

3. Opening and closing response time,

4. Blowdown,

5. Safety/relief valve lift-achieving rated flow capacity lift during each activation,

6. Safety/relief valve reclosure without chattering, disc oscillation, or sticking open, and

7. Capability to open without inlet steam when activated on demand.

Test conditions were varied according to facility capability to ensure valve operability across the design limits to which the SRV ma y be subjected while in service. These included temperature, pr essure ramp rates, pneumatic operating pressure, solenoid voltage, inlet pr essure, and the dynamically imposed backpressure.

Test results indicate essen tially zero leakage for both the relief (power) and safety (pressure) modes of SRV opera tion. All valves demonstrated seat-tightness capability to meet the 20 lb/hr specific ation limit under saturated steam conditions. Each valve demons trated safety actuation within the nameplate value plus 1% at a confidence level of 0.95. The response is also linear with ambient temperature in the negative direction; i.e., at temperatures

above 135°F the actual pop pressure is lo wer than the namepl ate value. The temperature correction value is 0.2 psi/ °F for this SRV. Set pressure is

independent of ramp rate variance. Res ponse of the SRV is directly related to the effective differential pr essure force acting to open the SRV; therefore, outlet static pressure at th e exit can be accurately accounted for. Opening times were as follo ws during the test set up: Safety actuation time - 0.020 t 0.30 sec Relief actuation time - 0.020 t 0.15 sec Actual installation times could result in a delay time >0.10 sec due to wire lengths and other non-SRV wire losses. Closing times were:

Safety actuation - none, contro lled by blowdown requirement. COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-13 Relief actuation - time to deenergize solenoid < 0.90 sec disc travel after solenoid < 1.50 sec was deenergized Blowdown within the require d range of 2% to 11% wa s demonstrated. Each SRV is adjusted by full flow testing for acceptable blowdown.

Qualification test results demonstrate the SRV will open to rated capacity lift in either the relief or safety modes of operation when actuated. The SRV reclosure was demonstrated th roughout the qualifica tion tests without sticking, chatter, or disc oscillation during the closure stroke. When inlet pressure was increased to repressurize to the set pressure, the SRV reactuated to the full open position. The modified SRV w ill open to its full rated capacity lift position when operated in the relief mode with the inlet pressure at zero psig, thus demonstrating its em ergency operability capability. Six SRVs were included in this life cy cle qualification test program. Test anomalies corrected during th is demonstration do not i nvalidate the adequacy of the test results obtained; the finalized modified SRV design is considered acceptable for BWR main steam applications.

b. Seismic and Moment Transfer Test One valve specimen was subjected to operating basis earthquake (OBE) and safe shutdown earthquake (SSE) accelerations and flange d end connection moment loading with valve inlet pr essurized with saturated st eam. Valve operability was demonstrated during and afte r application of loading. Maximum test loads were 8 x 105 in. pound moment at valve inlet and 6 x 10 5 in. pound moment at valve outlet. Seismic accelerations of 5.

0g horizontal and 4.2g vertical are the established maximum for a ny frequency between 5 to 200 Hz unless otherwise specified for a smaller frequency range.

c. Emergency Environmen tal Qualification Test

The solenoid valves and the pneumatic ac tuator assembly were subjected to a test sequence as follows:

1. Thermal aging equivalent to 343°F for 96 hours,

2. Radiation aging to greater than or equal to 30 x 10 6 rads, COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-14 3. Mechanical aging for 10 00 cycles (500 per solenoid),

4. Seismic testing as de scribed in item b. above,

5. Exposure to emergency environmental conditions of 340°F at 65 psig decreasing to 250°F at 25 psig for 4 days, and

6. Separate solenoid valve test 340°F, 3 hrs, 45 psig 320°F, 3 hrs, 45 psig 250°F, 18 hrs, 25 psig 200°F, 99 days, 20 psig.

Operability of the actuat or assembly was demons trated during and after exposure to the emergency environment.

d. Low-Pressure Water Discharge Test

Low-pressure water discharge tests as described and reported in GE Report NEDE-24988 to satisfy the requi rements of II.D.1 of NUREG-0737.

Test reports/records of the above qualific ation tests are available for inspection. Each SRV is production tested at the vendor's shop to ensure , by demonstration, each SRV manufactured will reliably perfor m its required function(s). Th e SRV production test consist of

a. Inlet and outlet hydrostatic tests at sp ecified conditions to satisfy ASME Code requirements,

b. Emergency operability test to verify capability of actuator to open the SRV without inlet pressure applied to the valve,

c. Actuator system leakage test to assure pneumatic leaktightness is compatible with plant air system make-up requirements,

d. Nitrogen set pressure and leakage test to rough adjust setpoint and ensure seat quality of seating surface prior to steam tests (optional),

e. Set pressure and blowdown test under thermally stabilized and saturated steam conditions,

f. Response time tests to verify relie f opening and closing times under thermally stabilized and saturate d steam conditions, and COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-15 g. Steam leakage tests to verify leaktightness.

The valves are normally installed as received from the factory providing there is no apparent evidence of damage during transportation, handling, and storage. For valves stored longer than one year, it is recommended they be recertified to ensure operability. The GE equipment specification requires certification from the va lve manufacturer that de sign and performance requirements have been met.

Testing to satisfy the ASME Code requirements is normally perfor med in situ. Testing can be performed locally or remotely. The local test method is conducte d using a test fixture that is temporarily mounted on the SRV and then removed on completion of the test. Remote testing is accomplished using a permanently mounted pneumatic head assembly th at is controlled by a remote computer. This method does not require any pe rsonnel entry into the containment for the purpose of testing.

During the startup test program, all of the main steam SRVs were tested for proper operation. These tests include a documentation review to ensure that the valves were properly installed, properly handled during transporta tion, storage, and installation, and were properly maintained as to cleanliness prior to performance of any te sts. In addition, the air accumulator capacity, SRV nameplate set pressure, and capacity were compared with the system design documentation for compliance.

Actual mechanical tests incl uded an operability check of th e SRV discharge line vacuum breakers, actuation of the individual SRVs by each remote manual switch (main control room

and/or remote shutdown panel) to demonstrate full lift, sm ooth stroke, and opening time characteristics, actuation of each SRV in the relief mode by stimulating its pressure switch, and a demonstration that each SRV accumulator (ADS and/or normal) has sufficient capacity to operate the SRV air actuator as required by the system design documentation. Finally, the ADS logic was fully tested for proper performa nce. Note that only the air actuator was exercised during many of the startup tests. This minimizes valve wear and unnecessary maintenance.

During the power ascension phase of the st artup test program, each SRV was manually actuated at approximately 250 ps ig reactor pressure to demonstrate valve operability. At approximately 50% power each SRV was actuated a second time to measure discharge capacity and to demonstrate that no blockage in the SRV di scharge line existed.

At commercial turnover the scope of SRV testing was governed by ASME B&PV Code Section XI, Article IWV and the Technical Specifications. This article specifies the rules and requirements for inservice testing to verify operational readine ss of the SRVs. This code section is applied to both AD S and non-ADS valves alike. Supplemental tests of the ADS COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 5.2-16 valves each operating cycle are required by the Technical Specific ations. Applying Section XI, the SRV test schedule (i n part) is as follows:

Time Period Number of Total Elapsed (Cycle) Valves Tested Tested Time (years)

1 6 6 1.5 2 4 10 2.5 3 4 14 3.5 4 4 18 4.5 5 4 4 1.0 6 4 8 2.0 7 4 12 3.0 8 4 16 4.0 9 2 18 5.0 Note that following the return to service of th e testing SRVs, an operability demonstration will be performed in compliance with Section XI, Article IWV-3200.

This combination of the start up test program, Technical Spec ifications surv eillance, and inservice inspection testing satis fies industry standards for SR V operability demonstrations. Energy Northwest participated in the BW R Owners' Group for TMI concerns on SRV reliability. The final test pr ogram description was submitted to the NRC by the BWR Owners' Group and is endorsed by Energy Northwest.

5.2.3 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS

5.2.3.1 Material Specifications

Table 5.2-7 lists the principal pressure retaining materials and the appropriate material specifications for the RCPB components.

5.2.3.2 Compatibility with Reactor Coolant 5.2.3.2.1 Pressurized Water Reacto r Chemistry of Reactor Coolant Not applicable to BWRs.

5.2.3.2.2 Boiling Water Reactor Chemistry of Reactor Coolant

Regulatory Guide 1.56 compliance is addressed in Section 1.8. COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-10-010 5.2-17 Reactor feedwater (RFW) quality is maintained in accordance with the Licensee Controlled Specifications (LCS) and as described in Section 10.4.6. Materials in the primary system are primarily austenitic stainles s steel and Zircaloy cladding. The reactor water chemistry limits are established to provide an environment favorable to these materials. Limits are placed on conductivity and chloride c oncentrations. Conductivity is limited because it can be continuously and relia bly measured and gives an indication of abnormal conditions and the presence of unusual ma terials in the coolant. Chloride limits are specified to prevent stress corrosion cracking of stainless stee

l. For further information, see Reference 5.2-2. Periodically an On-Line NobleChem application will be perfor med to create a catalytic layering of the noble metal platinum to reduce the hydrogen injection rate required to achieve a low electrochemical corrosion po tential (ECP). The low ECP achieves intergranular stress corrosion cracking (IGSCC) and irradiation assisted stress corrosion cracking (IASCC) protection while minimizing the effects of high dose rates attributed to regular hydrogen injection rates.

When conductivity is in its normal range, pH, chloride, and other impurities affecting conductivity will also be within their normal ra nge. When conductivity becomes abnormal, chloride measurements are made to determine whether or not they are also out of their normal operating values. Conduc tivity could be high due to the presence of a neutral salt, which would not have an effect on pH or chloride. In such a case, high cond uctivity alone is not a cause for shutdown. In some types of water-cooled reactors, conductivities are high because of the purposeful use of additives . In BWRs, however, where no additives which significantly affect conductivity are used a nd where near neutral pH is ma intained, conductiv ity provides a good and prompt measure of the quality of the reactor water. A depleted zinc oxide (DZO) skid is connected to the RFW system which maintains DZO concentration in reactor water. This has a small effect on conductivity. Significant changes in conductivity provide the operator with a warning mechanism so he can investigate and reme dy the condition before reactor water limits are reached. Methods available to the operator for correcting the off-standard condition include ope ration of the reactor cleanup sy stem, reducing the input of impurities, and placing the reactor in the cold shutdown condition. The major benefit of cold shutdown is to reduce the temperature-depende nt corrosion rates and provide time for the cleanup system to reestablish the purity of the reactor coolant.

During normal plant operation, the dynamic oxygen equilibrium, in the reactor vessel water phase, established by steam-gas stripping and radiol ytic formation (principally) rates, corresponds to a nominal value of approximately 200 ppb (0.2 ppm) of oxygen at rated operating conditions. Slight vari ations around this value have been observed as a result of differences in neutron fl ux density, core-flow, and r ecirculation flow rate.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-02-046, 03-069 5.2-18 A reactor water cleanup (RWCU) system is provided for removal of feedwater input impurities plus corrosion and fission products originating from primary sy stem components. The cleanup process consists of filtration a nd ion exchange and serves to maintain a high level of water purity in the reactor coolant.

Additional water input to the reactor vessel or iginates from the control rod drive (CRD) cooling water. The CRD water is of feedwate r quality. Additional filt ration of the CRD water to remove insoluble corrosion products takes place within the CRD system prior to entering the drive mechanisms and reactor vessel. An iron addition system is used to inject an ir on oxalate/demineralized water solution into the suction line of the condensate booster pumps. The injection flow rate is extremely small when compared to condensate system fl ow rate. This iron injection system will have a negligible affect on the oxygen concentration in the RFW.

A hydrogen injection system is installed across the condensate booster pumps. This hydrogen injection system will have a negligible affect on the oxyge n concentration in the RFW.

No other inputs of water or sources of oxygen are present during normal plant operation. During plant conditions other than normal ope ration, additional inputs and mechanisms are present as reactor coolant water coul d contain up to 8 ppm dissolved oxygen.

Conductivity of the primary coolant is continuous ly monitored with instruments connected to the reactor water recirculation loop and the RWCU system inlet. The effluent from the RWCU system is also monitored for conductivity on a continuous basis. These measurements provide reasonable surveillance of the reactor coolant.

Grab sample points are provide d at the locations shown in Table 5.2-8, for special measurements such as pH, oxygen, ch loride, and radiochemical content.

The relationship of chloride concentration to specific conduc tance measured at 25°C for chloride compounds such as sodium chloride and hydrochloric acid can be calculated (see Figure 5.2-10). Values for these compounds essentially bracket values of other common chloride salts or mixtures at the same chloride concentration. Surveillance requirements are based on these relationships. In addition to this program, limits, monitoring, and sampling requirements are established for the condensate, condensate treatment, and feedwa ter system. Thus, a total plant water quality surveillance program is established providing assurance that o ff specification conditions will quickly be detected and corrected.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-023 5.2-19 The sampling frequency establis hed for primary coolant at no rmal conductivity levels is adequate for instrument checks and routine audit purposes. When specific conductance increases and higher chloride c oncentrations are possible or when continuous conductivity monitoring is unavailable, sampling frequency is increased according to LCS. The primary coolant conductivity monitoring instrumentation, ranges, sensor, and indicator locations are shown in Table 5.2-8. The sampling is coordinated in a reactor sample station especially designed with constant temperature control and samp le conditioning a nd flow control equipment. Water Purity During a Condensate Leakage

Due to improved water quality limits, any appreci able circulating water inleakage would result in water chemistry conditions outside acceptable limits and require action(s) to return the water quality to within applicable limits for continued plant operation.

5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant

The materials of construction exposed to the reactor coolan t consist of the following:

a. Solution annealed austenitic stainless st eels (both wrought and cast) types 304, 304L, 316 and 316L,

b. Nickel base alloys -

Inconel 600 and Inconel X750 and Inconel 82 and 182 weld metal,

c. Carbon steel and low alloy steel,

d. Some 400 series martens itic stainless steel (all tempered at a minimum of 1100°F), and

e. Cobalt, chromium, nickel, and ir on based alloy hardfacing material

All of these materials of cons truction are generally resistant to stress corrosion in the BWR coolant. General corrosion on all materials, except carbon and low alloy steel, is negligible. Conservative corrosion allowances are provided for all exposed surfaces of carbon and low alloy steels.

Contaminants in the reactor coolant are cont rolled to very low limits by the reactor water quality specifications. No detrimen tal effects will occur on any of the materials from allowable contaminant levels in the high purity reactor coolant. Radiolytic products in the BWR have no adverse effects on the c onstruction materials.

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-10-010 5.2-20 The recirculation system piping and normally flooded sec tions of the reactor vessel are coated as needed utilizing the GEH On-Line NobleChem application process with a microscopic layer of noble metals. This coating serves to prevent as well as mitigate IGSCC by eliminating the dissolved oxygen at the meta l surface when an amount of hydr ogen gas is added in a molar ratio of greater than 2 to 1 hydrogen to oxygen.

Type 304 stainless steel has been replaced with type 316L stainless steel in the recirculation inlet line safe ends. The bypass lines and the CR D hydraulic return line were eliminated and nozzles capped. The core spra y lines are fabricat ed of carbon steel. The piping components that do not comply with the requirements of the Generic Letter 88-01 (GL 88-01), NRC Position on IGSCC BWR austenitic Stainless Steel Piping, will be subjected to the augmented inspection requirements of GL 88-01 as modified in Energy Northwest response (see Section 5.2.4 and Tables 5.2-9 and 5.2-10). 5.2.3.2.4 Compatibility of Cons truction Materials with Exte rnal Insulation and Reactor Coolant The materials of cons truction exposed to external insulation are

a. Solution annealed austenitic stainless steels (e

.g., types 304, 304L, and 316), and

b. Carbon and low alloy steel.

Two types of external insulation are used. Reflective metal in sulation used does not contribute to any surface contamination and has no effect on construction materials. The fibrous

insulation used meets the requirements of Regulat ory Guide 1.36.

DZO and iron are additives in the BWR coolant. Leakage would expo se materials to high purity demineralized water, DZO, and iron. Exposure to demine ralized water, DZO, and iron would cause no detrimental effects.

5.2.3.3 Fabrication and Proce ssing of Ferritic Materials a nd Austenitic Stainless Steels

Fracture toughness requirements for the ferritic material s used for piping and valves (no ferritic pumps in RCPB) of the RCPB were as follows:

Safety/relief valves were exempted from fracture toughness requirements because Section III of the 1971 ASME B&PV Code did not require impact testing on valves with inlet connections of 6 in. or less nominal pipe size. Main steam isolation valves were also exempted because the mandatory ASME Code, 1971 Edition through the Winter 1971 Addenda, required brittle fracture testing on ferritic pressure

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-21 boundary components only if re quired in the Design Specificati on. The Design Specification did not require brittle fracture testing because the system temperature is in excess of 250°F at pressure above 20% of the desi gn pressure. Material informa tion pertaining to the MSIVs is contained in Table 5.2-11 . Main steam piping was tested in accordance with and met the fr acture toughness requirements of Paragraph NB-230 0 of the 1972 Summer Addenda to ASME Code, Section III.

The ferritic pressure boundary material of the RPV was qua lified by impact testing in accordance with the 1971 Edition of Section III ASME Code and Addenda to and including the Summer 1971 Addenda.

Austenitic stainless steels with a yield strength greater than 90,000 psi are not used.

The degree of compliance with Regulatory Guides 1.31, 1.34, 1.37, 1.43, 1.44, 1.50, 1.66, and 1.71 is addressed in Section 1.8. 5.2.4 INSERVICE INSPECTION AND TESTING OF THE REACTOR COOLANT PRESSURE BOUNDARY

The structural integrity of AS ME Code Class 1, 2, and 3 components are maintained as required by the ISI program in accordance with 10 CFR 50.55a. With the structural integrity of any component not co nforming to the above re quirements, the structur al integrity will be restored to within its limits or the affected component will be isolated. For Class 1 components, this isolation will be accomplished prior to increasing reactor coolant system temperature more than 50 °F above the minimum temperature required by nil-ductility transition (NDT) considerations. For Class 2 components, isolation will be accomplished prior to increasing reactor coolant system temperature above 200 °F. Inservice Inspections are perf ormed in accordance with the requirements of 10 CFR 50.55a subparagraph (g) as described in th e Inservice Inspect ion Program Plan.

5.2.4.1 System Boundary Subject to Inspection

The system boundary subject to in spection is defined in the Inservice Inspection Program Plan. The RPV was examined prior to service in accordance with the requirements of the 1974 Edition of the ASME B&PV Code, Section X I, including the Summer 1975 Addenda. All Class 1 piping, pumps, and valves were examined prior to serv ice in accordance with the requirements of the 1974 Edition of the ASME B&PV Code, Section XI, with Addenda through Summer 1975, including Appendix III from the Winter 1975 Addenda.

The design of the RPV shield wall and external inse rvice inspection system was completed prior to the promulgation of amendments to 10 CFR 50.55a which require the upgrading of the COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-22 utility's inservice inspection code commitment for examina tions subsequent to the baseline examination. The design has allowed some additional access for inspections and coverages anticipated to be required by later codes, where possible. The result of this effort has increased the areas on the RPV available to inservice inspection (approximately 84% of the vessel weld volume is accessible) and has allowed the pipi ng examination to be upgraded to conform to the requirements of the Summer 1975 Addenda to Sec tion XI as far as practical. The preservice examination was performed on Class 1 components and piping pursuant to the requirements of the 1974 Edition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda for both the RPV and associated piping, pumps, and va lves. It is described in the Preservice Inspection Program Plan (Reference 5.2-6). 5.2.4.2 Arrangement of Systems and Components to Provide Accessibility

Access for the purpose of inservic e inspection is defined as the design of the plant with the proper clearances for exami nation personnel and/or equipment to perform inservice examinations. The RCPB for the RPV is designed to provide compliance with the provisions for access as required by Subarticle IWA-1500 of the 1974 Edition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda. The RCPB for piping, pumps, and valves is designed to provide compliance with the provis ions for access as required by Subarticle IWA-1500 of the 1974 Edition of the ASME B& PV Code, Section XI, with addenda through Summer 1975.

Access is provided for volumetr ic examination of the pressure containing welds from the external surfaces of components and piping by means of remo vable insulation, removable shielding, and permanent tracks for remote inspection devices in areas where personnel access is restricted. The provisions for suitable access for inservice inspection examinations minimizes the time required for th ese inspections and, hence, redu ces the amount of radiation exposure to both plant and examination personnel. Working pla tforms are provided at most strategic locations in the plant which permit re ady access to those area s of the RCPB which are designated as inspection points in the inserv ice inspection program. Temporary scaffolding will be used as required to gain access for examination.

Energy Northwest retained Southwest Research Institute to provide an independent assessment as to the suitability of plant access provisions for inservice inspection. This overview provided for identification of design modification or inspection technique development needs to ensure maximum practical complian ce with code requirements.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-23 5.2.4.2.1 Reactor Pressure Vessel

Access for inspection of the RPV is as follows:

a. Access to the exterior su rface of the RPV for inservice inspection is provided by removable insulation and shield plugs.

Hinged shield wall plugs around nozzles are used to gain access for nozzle inspection. A minimum annular space of 8.25 in. is provided between the vessel exterior surfa ce and the insulation interior surface to permit the insertion of remotely operated inspection devices between the insulation and the reactor vessel. Th e RPV nozzle insulation is removable. This design allows sufficient clearances for the mounting of a nozzle-to-shell examination device from tracks located either at the nozzle safe-end or at the pipe area. Examina tions that can be pe rformed from these tracks include the required coverage of the nozzle-to-she ll welds and depending on technique, could provid e examination coverage of the nozzle inner radius section and nozzle-to-safe-end weld. Access, geometry and radiation level considerations will determine those nozzl es scheduled for manual examination.

b. The vessel flange area and vessel closure head can be examined during refueling outages using m anual ultrasonic techniques.

With the closure head removed, access is afforded to the upper interior clad surface of the vessel by removal of a steam dryer and steam separ ator assembly. Removal of these components also enables the examination of remaining internal components by remote visual techniques. The volumetric examinati on of the vessel-to-flange weld and closure head-to-fl ange weld can be performe d by applying the search units directly to the seal surface areas. The vessel-to-flange weld is also

examined from vessel shell surface.

c. The closure head is dry st ored during refueling which facilitates direct manual examination. Removable insulation allo ws examination of the head welds from the outside surface. Reactor vessel nuts and washers are removed to dry storage for examination during refueling.

Selected studs are examined during re fueling in accordance with the Inservice Inspection Program Plan.

d. Openings in the RPV support skirt are provided to permit access to the RPV bottom head for purposes of inservice examination. The examinations performed include volumetric examinations of circumferential welds, portions of the meridional welds, portions of the do llar plate longitudinal welds, and visual examination of accessible penetration welds.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-24 5.2.4.2.2 Piping, Pu mps, and Valves The physical arrangement of piping, pumps, and valves is designed to allow personnel access to welds requiring inservice inspection. Mod ifications to the initial plant design have been incorporated where practicable to provide in spection access on Class 1 piping systems. Removable insulation is provided on those piping systems requiring inspection. In addition, the placement of pipe hangers and supports with respect to t hose welds requiring inspection have been reviewed and mod ified where necessary to reduc e the amount of plant support required in these areas during inspection. Wo rking platforms are provided to facilitate servicing most of the pumps and valves. Temporar y platforms, scaffolding, and ladders will be provided to gain additional access for piping and some pump and valve examinations. An effort has been made to mini mize the number of fitting-to-fitti ng welds within the inspection boundary. Welds requiring inspecti on are located to permit ultr asonic examinations from at least one side, but where compone nt geometries permit, access fr om both sides of the weld is provided. The surface of welds within the inspection boundary are prepared to permit effective ultrasonic examination.

5.2.4.3 Examination T echniques and Procedures

Examination techniques and proce dures for the preservice examination, including any special technique and procedure, met the requirements of Table IWB-2600 of the 1974 Edition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda for both the RPV and the associated piping, pump, and valve examinations. Examination techniques and procedures for inservice inspections are in accordance with the Inservice Inspection Program Plan. During plant design, an effort was m ade to upgrade the requirement for calibration standards. Where upgrading was not feasible, material of the same P series with similar acoustic characteristics were used.

5.2.4.3.1 Equipment for Inservice Inspection

Access for inservice inspection of the RPV seam welds is accomplishe d through openings in the sacrificial shield. These openings are provided at each nozzle location. Permanently installed tracks between the vessel surface and the insulation can be used for mounting remotely operated devices. Access is also provided for devices that do not require use of these tracks. Remote ultrasonic scanning equipment for examin ation of the nozzle-to-vessel welds will be supported and guided from tracks temporarily mounted on the pipe connected to the nozzle. The examination equipment will provide radial and circumferential motion to the ultrasonic transducer while rotating about the nozzle. Installation of th e equipment will be accomplished through the access openings in the sacrificial shield which are provided at each nozzle location.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-25 5.2.4.3.2 Coordination of Inspection Equipment With Access Provisions Access to areas of the plant requi ring inservice inspection is provi ded to allow use of standard equipment wherever practicable. Design in general provides for free space envelopes both radially and axially from welds to be examin ed so standard manual examination equipment may be utilized. Any special equipment or techniques used will achieve the sensitivities required by the codes.

5.2.4.3.3 Manual Examination In areas where manual ultrasoni c examination is performed, all reportable indications are recorded consistent with current inservice inspection codes in effect. Radiographic techniques may be used where ultrasonic techniques are not practical. In areas where manual surface or direct visual examinations are performed, all recordable indications will be in accordance with the Inservice Inspec tion Program Plan.

5.2.4.4 Inspection Intervals

Inspection intervals are defined in the Inservice Inspection Program Plan.

5.2.4.5 Examination Cate gories and Requirements

Examination categories and require ments for the preser vice inspection ar e defined in the Preservice Inspecti on Program Plan and closely follo w the categories and requirements specified in Tables IWB-2500 and IWB-2600 of the 1974 Edition with Addenda through Summer 1975 of the ASME B&PV Code, Section XI, for the RPV and the associated piping, pumps, and valves.

Examination categories and requirements for inse rvice inspections are in accordance with the requirements of ASME Section XI and are contained in the Inservice Inspection Program Plan.

5.2.4.6 Evaluation of Examination Results

Evaluation of results for the RPV, pump, and valve baseline examinations were conducted in accordance with Article IWB-3000 of the 1974 Ed ition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda. Evaluation of examination results for piping baseline examinations were conducted in accordance with Article IWB-3000 of the 1974 Edition of the ASME B&PV Code, Section IX, with Addenda through Winter 1975. Energy Northwest recognized that Section XI had been promulgated as an eff ective code by 10 CFR 50.55a, for the baseline examinations, only through th e Summer 1975 Addenda. However, Energy Northwest also recognized that even though the code through Summe r 1975 Addenda included evaluation criteria which could be interpreted to apply to pipi ng (Category B-J) welds, the evaluation criteria found in the Winter 1975 Adde nda clearly provides eva luation criteria which COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-26 are applicable to these welds. Energy Northwest was unaware that the NRC staff was opposed to these evaluation criteria and an ticipates that the criteria wh ich will appear in the future codes will be consistent therewith. Evaluations are performed in accordance with the Inservice Inspection Program Plan.

5.2.4.7 System Leakage and Hydrostatic Pressure Tests

The requirement for baseline hydr ostatic test for the RPV was satisfied by the hydrostatic test performed in accordance with the requirement s of ASME Section III . Similarly, the requirements for the baseline piping system leak age and hydrostatic test s were satisfied by reference to the Section III hydrostatic test report as permitted by ASME Section XI, IWA-5210(b). Subsequent hydrostatic a nd system leak tests are conduc ted to the code in effect in accordance with the Inservice Inspection Program Plan.

5.2.4.8 Inservice Inspection Commitment

All quality Group A components were examined once prior to startup in accordance with the above requirements. This pre operational examination served to satisfy the requirements of IWB-2100 of the 1974 Edition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda for the RPV and associated piping, pumps, and valves. Inservice inspection of Columbia Genera ting Station is performed in accordance with the Inservice Inspection Program Plan.

5.2.4.9 Augmented Inservice Inspection to Protect Against Postulated Piping Failures

An augmented Inservice Inspection Program Pl an has been implemented for Columbia Generating Station, on high energy

• Class 1 piping systems whic h penetrate containment for which the effects of postulated pipe breaks would be unacceptable. This program is described in the Inservice Inspection Program Plan.
• High-energy lines include those systems that, during normal plant conditions, are either in operation or maintained pressuri zed and where either the maximu m operating pressure exceeds 275 psig or maximum opera ting temperature exceeds 200

°F. If, for a particular line, the above pressure and temperature limits are not exceeded more than 2% of the time that the system is in operation, then that line is considered moderate energy and is exempt from the requirement for augmente d inservice inspection. COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-27 5.2.4.10 Augmented Inservice Inspection of Reactor Pressure Vessel Feedwater Nozzles 5.2.4.10.1 Preservi ce Examination

Energy Northwest performed a preservice inspection ultrasonic examination of the RFW nozzle inner radii, bore, and sa fe end regions as desc ribed in the Preservi ce Inspection Program Plan.

In addition, a preservice liqui d penetrant examination was perf ormed on the accessible areas of all RFW nozzle inner radius surfaces.

5.2.4.10.2 Inservice Examination

Inservice examinations of RFW nozzles are performed in accordance with the Inservice Inspection Program Plan.

5.2.4.11 Augmented Inservice Inspecti on for Intergranular Stress Corrosion Cracking Energy Northwest performed an ultrasonic examination of all Code Class 1 piping which is considered susceptible to IGSCC. The results are reported in the Preservice Inspection Summary Report (References 5.2-9 and 5.2-10). GL 88-01 weld categories and augmented insp ection requirements are described in the Inservice Inspecti on Program Plan.

5.2.4.12 ASME Section XI Repairs/Replacements

The repair or modification of N-stamped comp onents will be performed in accordance with the Edition and Addenda of ASME S ection XI defined in the Inservice Inspection Program Plan and in accordance with ASME Section III (Code Edition and Addenda to which the component was fabricated).

Deviations to the above refe renced code edition and addenda as allowed by code will be reviewed by Energy Northwest and authorized on a case-by-case basis.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-11-005 5.2-28 5.2.5 DETECTION OF LEAKAGE THROUGH REACTOR COOLANT PRESSURE BOUNDARY

5.2.5.1 Leakage Detection Methods

The nuclear boiler leak detection system consists of temperatur e, pressure, and flow sensors with associated instrumentation and alarms. This system detects, annuncia tes, and isolates (in certain cases) leakages in the following systems:

a. Main steam lines,

b. RWCU system,

c. RHR system,

d. Reactor core isolation cooling (RCIC) system,

e. Feedwater system,

f. HPCS,

g. LPCS, and

h. Coolant system within the primary containment.

Isolation and/or alarm of affe cted systems and the detection methods used are summarized in Table 5.2-12 . Small leaks (5 gpm and less) are detected by te mperature and pressure changes, drain sump pump activities, floor drain flow monitoring, an d fission product monitoring. Large leaks are also detected by changes in reactor water leve l and changes in flow rates in process lines.

The 5-gpm leakage rate is the limit on unidentified leakage. The leak detection system sensitivity and response is di scussed in Section 7.6.2.4. Compliance with Regulatory Guide 1.45 is described in Section 1.8. Table 5.2-12 summarizes the actions taken by each le akage detection function. The table shows that those systems which detect gross leakage initiate immediate auto matic isolation. The systems which are capable of detecting small leaks initiate an alarm in the control room. The operator can manually isolate the violated system or take othe r appropriate action. 5.2.5.1.1 Detection of Abnormal Leakage Within the Primary Containment Leaks within the drywell are detected by m onitoring for abnormally high-pressure and temperature within the drywell, high fillup rates of equipment and floor drain sumps, excessive

temperature difference between th e inlet and outlet cooling wate r for the drywell coolers, a decrease in the reactor vessel water level, and high levels of fission products in the drywell atmosphere. Temperatures within the drywell ar e monitored at various elevations. Also the temperature of the inlet and exit ai r to the atmosphere is monitored. Excessive temperatures in COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-29 the drywell, increased drywell drain sump flow rate, and drywell high-pressure are annunciated by alarms in the control room. Drywell high pressure and low reactor vessel water level will cause automatic primary containment isolation. In addition, low reactor vessel water level will isolate the main steam lines. The systems within the drywell share a common area; therefore, their leakage detection system s are common. Each of the leakage detection systems inside the drywell is designed with a capability of detecting le akage rates less than those established by the Technical Specifications. 5.2.5.1.2 Detection of Abnormal Leakage Outside the Primary Containment

Outside the drywell, the piping within each system monitored for leakage is in compartments or rooms, separate from other systems where feasible, so th at leakage may be detected by area temperature indications. Each leakage detecti on system discussed in the following paragraphs is designed to detect leak rates that are less than thos e established by the Technical Specifications. The method used to monito r for leakage for each RCPB component is described in Table 5.2-12 . a. Ambient and differential room ventilation temperature

A differential temperature se nsing system is installed in each room containing equipment that is part of the RCPB. These rooms are the RCIC, RHR, and the RWCU systems equipment rooms and main steam line tunnel. Temperature sensors are placed in the inlet and outlet ventilation ducts or across room boundaries. Other sensors are installed in the equi pment areas to monitor ambient temperature. A differential temperature monitor reads each set of sensors and/or ambient temperature and initiates an alarm and isolation when the temperature reaches a preset value. Annunciator and remote readouts from temperature sensors are indi cated in the control room.

Spurious isolations of systems due to a relatively sharp drop in outside ambient temperature is highly unlikely. For ex ample, the normal approximate operating differential temperature for the RHR and RCIC pump rooms is 26°F and 32°F respectively. The temperat ure elements are lo cated at the face of the supply and return ductwork in each pump room. The setpoint differential for isolation is 50°F and 55°F for RCIC and RHR to allow for heat released from a predetermined steam leak. Analysis has shown that it would take a 30°F/hr

ambient (outside) temperature decrease for about 2 hr to cause isolation. This magnitude of temperature drop is not supported historically because meteorological data for Hanford has not recorded ch anges of this magnitude.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-30 b. Reactor building sump flow measurement Instrumentation monitors and indicates the amount of leakag e into the reactor building floor drainage system. The normal leakage collected in the system consists of leakage from the RWCU and CRD systems and from other miscellaneous vents and drains.

c. Visual and audible inspection Accessible areas are inspected periodically and the temperature and flow indicators discussed above are monitored regularly as required by the Technical Specifications. Any instrument indication of abnormal leakage will be investigated.

d. Differential flow measur ement (cleanup system only)

Because of the arrangeme nt of the RWCU systems, differential flow measurement provides an accurate leakage detection method. The flow from the reactor vessel is compared w ith the flow back to the vessel. An alarm in the control room and an isolation signal are initiated when higher flow out of the reactor vessel indicates that a leak may exist.

5.2.5.2 Leak Detection Devices

a. Drywell floor drain sump measurement

The normal design leakage collected in the floor drain sump consists of leakage from the CRDs, valve flange leakage, floor drains, closed co oling water system drywell cooling unit drains, and potential valve stem leaks. The floor drain sump collects unidentified leakage. Design details are given in Section 9.3.3. b. Drywell equipment drain sump

The equipment drain sump collects only id entified leakage. This sump receives condensate drainage from pump seal leakoff and the reactor vessel head flange vent drain. Collection in excess of background leakage would indicate reactor coolant leakage. Design de tails are given in Section 9.3.3. c. Drywell air sampling

The primary containment radiation monitori ng system is used to supplement the temperature, pressure, and flow variati on method described previously to detect

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-31 leaks in the nuclear system process barrier. This system is described in Sections 11.5 and 7.6. Radiation monitors are useful as leak detection devices because of their sensitivity and rapid response to leaks. After several weeks of full power operation, a set level of b ackground radiation is established. Any sudden or unexplained increase in b ackground radiation indicat es a possible primary coolant leak within the primary containment. If an increase is noted, a comparison with other leak detection devices having a relationship to each other is made, particularly the equipment and floor drain flow rate monitors, and the reactor building sump pumps activation on high sump level. Using the flow rate monitors as a reference, the comparisons provide independent indications of a leak within the primary containment. Th is provides diversity in leak detection.

d. Reactor vessel head closure

The reactor vessel head clos ure is provided with double seals with a leak off connection between seals that is piped to the equipm ent drain sump. Leakage through the first seal is annunciated in the control room. When pressure between the seals increases, an alarm in the control room is actuated. The second seal then operates to contain the vessel pressure.

e. Reactor water recirculation pump seal

Reactor water recirculation pump seal leaks are detected by monitoring the drain line. Leakage, indicated by high flow rate, alarms in the control room. Leakage is piped to th e equipment drain tank.

f. Safety/relief valves

Tail pipe temperature sensors connected to a multipoint recorder are provided to detect SRV leakage during reactor operation. Safety/relief valve temperature elements are mounted, using a thermowell, in the SR V discharge piping several feet from the valve body. Temperature ri se above ambient is recorded in the main control room.

5.2.5.3 Indication in the Control Room

Details of the leakage detection system indications are included in Section 7.6.1.3. COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-32 5.2.5.4 Limits for Reactor Coolant Leakage 5.2.5.4.1 Total Leakage Rate

The total leakage rate consists of all leakage, iden tified and unidentified, that flows to the drywell floor drain and equipment drain sumps. The total leakage rate li mit is established so that, in the absence of normal ac power with loss of feedwater supply, make-up capabilities are provided by the RCIC system.

The equipment sump and the floor drain sump co llect all leakage. Th e equipment sump is drained by one 50-gpm pump and th e floor drain sump is draine d by two 50-gpm pumps. The total leakage rate limit from inside containm ent is established at 25 gpm, which includes no more than 5 gpm unidentified l eakage. The total l eakage rate limit is lo w enough to prevent overflow of the drywell sumps.

5.2.5.4.2 Normally Expected Leakage Rate

The pump packing glands and other seals in systems that are part of the RCPB and from which normal design leakage is expected , are provided with drains or auxiliary sealing systems. Nuclear system pumps inside th e drywell are equipped with double seals. Leakage from the primary recirculation pump seal s is piped to the equipment drain sump. Leakage in the discharge lines from the main steam SRVs is m onitored by temperature sensors that transmit a signal to the control room. Any temperature increase above the drywe ll ambient temperature detected by these sensors indicates valve leakage.

Thus, the leakage rates from pumps and the re actor vessel head seal are measurable during plant operation. These leakage rates, plus any other leakage rates meas ured while the drywell is open, are defined as identified leakage rates.

The identified leakage is measured continuously and the leakage rate will be calculated and recorded on a frequency of at least once per 12 hr in accordance with the Technical Specifications. The procedures describing how the identified leakage rate is determined include provisions for showing the identified leakage rate has not exceeded the maximum allowable value of 25 gpm, including no mo re than 5 gpm unidentified leakage. Each equipment leak-off connection has been provided with a temperature element which will identify to the operator that a higher than normal temperature exists at that particular location.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-33 5.2.5.5 Unidentified Leak age Inside the Drywell 5.2.5.5.1 Unidentified Leakage Rate

The unidentified leakage rate is the portion of the to tal leakage rate recei ved in the drywell sumps that is not identified as pr eviously described. A threat of significant compromise to the nuclear system process barrier ex ists if the barrier contains a crack that is large enough to propagate rapidly (critical crack length). The unidentified leakage rate limit must be low because of the possibility that most of the unidentified leakage rate might be emitted from a single crack in the nuclear system process barrier.

An allowance for leakage that does not compromise barrier integr ity and is not identifiable is made for normal plant operation.

The unidentified leakage rate limit is established at the 5-gpm rate to allow time for corrective action before the process barrier c ould be significantly compromised.

The following indications are available to the control room operator for evaluating and detecting unidentified leakage:

Drywell pressure recorders,

Drywell temperature recorders,

Drywell floor drain total flow recorder, Reactor building floor drain sump fillup rate timer, Reactor building floor drain sump pump out rate timer, Drywell cooler cooling water differential temper ature recorder, Reactor vessel water level, and

Drywell atmosphere radiation monitors.

While the indications listed above have no definitive correla tion between their engineering units, they provide an early warn ing of a potential leak to the ope rator. The actual unidentified leak rate is determined by observing the drywell floor drain system flow rate recorders provided in the control room. Since the monitoring is not computerized, a computer failure would not affect indications.

5.2.5.5.2 Length of Through-Wall Flaw Experiments conducte d by GE and Battelle Memorial Ins titute (BMI) permit an analysis of critical crack size and crack opening displacement (References 5.2-4 and 5.2-5). This analysis relates to axially oriented through-wall cracks and provides a realis tic estimate of the leak rate to be expected from a crack of critical size. In every case, the leak rate from a crack of critical size is significantly gr eater than the 5-gpm criterion.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-029, 11-005 5.2-34 If either the total or unidentified leak rate limits are exceeded, an orderly shutdown would be initiated and the reactor would be placed in a cold shutdown condition in accordance with the Technical Specifications.

5.2.5.5.3 Criteria to Evaluate the Adequacy and Margin of the Leak Detection System

For process lines that ar e normally open, there are at least two different met hods of detecting abnormal leakage from each system within the nuclear system pr ocess barrier lo cated in the drywell, reactor building, and auxiliary building as shown in Table 5.2-12 . The instrumentation is designed so it can be set to provide alarms at established leakage rate limits and isolate the affected system, if necessary. The alarm points are determ ined analytically or based on measurements of appr opriate parameters made duri ng startup and preoperational tests. Some alarm points requi re hot operation data for their determination. Preoperational testing verified proper operation of the instrumentation for the alarm point used.

The unidentified leakage rate limit is based with an adequate margin for contingencies on the crack size large enough to propagate rapidly. The establishe d limit is sufficien tly low so that, even if the entire unidentified leakage rate we re coming from a single crack in the nuclear system process barrier, correctiv e action could be take n before the integrity of the barrier would be threatened with significant compromise.

The leak detection system sensitivity and response tim e is discussed in Section 7.6.2.4 such that an unidentified leakage rate increase of 1 gpm in less than 1 hr will be detected.

5.2.5.6 Safety Interfaces

The balance of plant/GE nuclear steam supply system safety inte rfaces for the leak detection system are the signals from the monitored balance-of-plant equipment and systems that are part of the nuclear system process barrier and associated wiring and cable lying outside the nuclear steam supply equipment. These balance-of-pla nt systems and equipment include the main steam line tunnel, the SRVs, a nd the turbine building sumps.

5.2.5.7 Testing and Calibration

Provisions for testing and calibration of the leak detection syst em are described in Section 7.6. 5.

2.6 REFERENCES

5.2-1 "Qualification of the One-Dimensional Core Transient Model (ODYN) for BWR's," NEDO-24154-A, Vol. 1 and 2, General Electric, August 1986.

5.2-2 J. M. Skarpelos and J. W. Bagg, "Chloride C ontrol in BWR Coolants," June 1973, NE DO-10899. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 5.2-35 5.2-3 W. L. Williams, Corrosi on, Vol. 13, 1957, p. 539t.

5.2-4 GEAP-5620, "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flows," by M. B. Reynolds, April 1968.

5.2-5 "Investigation and Evalua tion of Cracking in Austeniti c Stainless Steel Piping of Boiling Water Reactor Plants," NUREG-76/067, NRC/PCSG, dated

October 1975.

5.2-6 Washington Public Power Supply Sy stem, 1985, "WNP-2 Preservice Inspection Program Plan," Washington Public Power Supply System, Richland,

Washington.

5.2-7 NEDE-32906P Supplement 3-A, "Migration to TRACG04/PANAC11 fromTRACG02/PANAC10 for TRACG AOO and ATWS Overpressure Transients," April 2010.

5.2-8 "Columbia Generating Station TRACG Implementation for Reload Licensing Transient Analysis," (T1309), 001N9 271-R1, Revision 1, January 2015.

5.2-9 Letter GO2-85-110 from G. C. Sorens on, Supply System, to A. Schwencer, NRC,

Subject:

Nuclear Project No. 2, CPPR-93 Preservice Inspection Program Plan, Amendment No. 4, Su mmary Report Supplement No . 1, NIS-1 Code Data Report, dated February 28, 1985.

5.2-10 Letter GO2-83-401 from G. D. Bouchay, Supply Syst em, to A. Schwencer, NRC,

Subject:

Nuclear Project No. 2, CPPR-93, Preservice Inspection

Program Plan, Volume No. 4, "Preservice Inspection Summary Report", dated May 3, 1983.

5.2-11 "Supplemental Reload Licensing Report for Columbia" (most recent version referenced in COLR). Table 5.2-1 Exceptions to Conformance to 10 CFR 50.55a Reactor Coolant Pressure Boundary Components Component Description Quantity Plant Identification System Number Purchase Order Date Code Applied ASME Section III Code Required by 10 CFR 50.55(a) Component Status COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 20015.2-37Main steam safety

relief valves 18 MS-RV-1 A-D MS-RV-2 A-D MS-RV-3 A-D MS-RV-4 A-D

MS-RV-5 B-C

(B22-F013 A-V) April 1971 1971 Edition 1971 Summer Addenda FSa Recirc pumps 2 RRC-P-1A (B35-C001) April 1971 1971 Edition 1971 Summer Addenda FS Recirc gate valves 4 RRC-V-23/ RRC-V-67 (B35-F023/F067) June 1971 1971 Edition 1971 Summer Addenda FS Recirc flow control

valve 2 RRC-V-60 (B35-F060) June 1971 1971 Edition 1971 Summer Addenda FS Recirc piping 1 lot B35-G001 October 1971 1971 Summer Addenda 1971 Winter Addenda FS a FS = Fabricated and Shipped COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-2 Reactor Coolant Pressure Boundary Component Code C ase Interpretations

Number Tit le Remarks 5.2-38 1. 1332 - Revision 6 Requirements for steel forgi ngs Regulatory Guide 1.85, Revision 6

2. 1401 - Revision 0 Welding repairs to cladding of Class I, Section III, components after heat treating

3. 1420 - Revision 0 5b-167 Ni-Cr-Fe all oy pipe or tube

4. 1441 - Revision 1 Waiving of 3 Sm requirement for Section III construction

5. 1141 - Revision 1 Foreign p roduced steel Regulatory Guide 1.85, Revision 5

6. 1361 - Revision 2 Socket wel ds, Section I II Regulatory Guide 1.84, Revision 9 7. 1525 Pipe descaled by means other than pickling, Section III

8. 1535 -

Revision 2 Hydrostatic test of Cl ass 1 nuclear valves, Section III Regulatory Guide 1.84, Revision 9 9. 1567 Testing lots of carbon and low alloy steel covered electrodes, Section III Regulatory Guide 1.85,

Revision 6 10. 1621 - Revision 1 Internal and external valve items,

Section III, Class 1 Regulatory Guide 1.84,

Revision 12 (for 1621-2) 11. 1588 Electro-etching of Section III code symbols Regulatory Guide 1.84,

Revision 9 12. 1820 Alternative ultrasonic examination technique Section III, Division 1 Regulatory Guide 1.85,

Revision 11 13. N181 Steel castings refined by the argon oxygen decarbonization process Section 3,

Division 1 construction

14. 1711 Pressure relief valve, design rules, Section III, Division 1, Class 1, 2, 3

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-3 Nuclear Sy stem Safety/Relief Setp oints Number of Valves Spring Set Pressure (psig) ASME Rate Capacity at 103% Spring Set Pressure (lb/hr each) Pressure Setpoint for the Power Actuated Mode (psig) 5.2-39 2 1165 876,500 1091 4 1175 883,950 1101 4 1185 891,380 1111 4 1195 898,800 1121 4 1205 906,250 1131 Note: Seven of the safety/relief valves serve in the automatic dep ressurization function.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-4 Systems Which May Initiate During Safety Valve Capacity Overpressure Event System Initiating/Trip Signal(s) a 5.2-40 Reactor Protection System Reactor trips "OFF" on high flux RCIC "ON" when reactor water level L2 "OFF" when reactor water level L8 HPCS "ON" when reactor water level L2 "OFF" when reactor water level L8 Recirculation system "OFF" when reactor water level L2 "OFF" when reactor pressure 1143 psig RWCU "OFF" when reactor water level L2 a Note: Vessel level trip se ttings L2 and L8 shown in Figure 5.3-3 . COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 5.2-5 Sequence of Events for Figure 5.2-2 Time-Sec Event LDCN-15-011 5.2-41 0 Initiate closure of all main steam isolation valves (MSIV). 0.45 MSIVs reached 85% open and in itiated reactor scram. However, hypothetical failure of this position scram was assumed in this analysis. 2.0 Neutron flux reached the high APRM flux scram setpoint and

initiate reactor scram. 2.9 Steam line pressure reached the group safety relief valve pressure setpoint (spring-action mode and safety relief valves started to open). 3.0 MSIVs completely closed. 3.5 All safety relief valves opened.

3.9 Vessel bottom pressure reached its peak value.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6 Design Te mperature, P ressure and Maximum Test

Pressure for RCPB Components

Component Design Temperature (F) Design Pressure (psig) Maximum Test Pressure (psig) 5.2-42 Reactor vessel 575 1250 1563 Recirculation system Pump discharge piping, through

valves 575 1650 (a) Pump discharge piping, beyond

valves 575 1550 (a) Pump suction piping 575 1250 (a) Pump and discharge valves 575 1650 (b) Suction valves 575 1250 (b) Flow control valve 575 1675 (a) Vessel drain line 575 1275 (a) Main steam system Main steam line 575 1250 (a) Main steam line valves 575 1250 (b) Residual heat removal system Shutdown suction Recirculation header to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) Pump discharge Reactor ve ssel to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6

Design Te mperature, P ressure and Maximum Test Pressure for RCPB Components (Continued) Component Design Temperatu re (F) Design Pressure (psig) Maximum Test Pressure (psig) 5.2-43 Shutdown return Recirculation header to second

isolation valve Piping 575 1575 (a) Valves 575 1575 (b) Reactor feedwater Reactor ve ssel to man ual valve

(F011) Piping 575 1300 (a) Valves 575 1300 (b) Reactor co re isolation cooling system Steam to RCIC. 575 1250 (a) Pump turbine Reactor ve ssel to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) Pump discharge to reactor 170 1500 (a) Reactor ve ssel to second isolation valve Piping 575 1500 (a) Valves 575 1500 (b) High-pressure core spray system Outboard containment isolation valve to and including

maintenance valve insi de containmen tc Piping 575 1250 (a) Valves 575 1250 (b) COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6 Design Te mperature, P ressure and Maximum Test

Pressure for RCPB Components (Continued) Component Design Temperature (F) Design Pressure (psig) Maximum Test Pressure (psig) 5.2-44 From maintenance val ve to reactor ve ssel Piping 575 1250 (a) Valves 575 1250 (b) Low-press ure core spray system Outboard i solation valve to

reactor ve ssel Piping 575 1250 (a) Valves 575 1250 (b) Standby liquid control Pump discharge to reactor vessel Reactor to second isolation valved Piping 150 1400 (a) Valves 150 1400 (b) Reactor water cleanup system Pump suction Recirculation piping to isolation valve outside drywell Piping 575 1250 (a) Valves 575 1250 (b) Control rod drive system Piping to HCUs 150 1750 2187 a Test pressure at the bottom of the reactor vessel is nominally 1565. The piping is field tested with the reactor vessel. b Test pressure is based on ASME III Table NB-3531-9 (1971 Edition through Winter 1973 Addenda). c For dual design conditions, see Figure 6.3-3.1 . d The design temperature and pressure of the original injection piping were 575°F and 1250 psig. This portion of piping was rerouted to the HPCS injection and was tested in accordance with ASME Section XI , 1980 Edition, Winter Addenda.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Table 5.2-7 Reactor Coolant Pressure

Boundary Materials Component Form Material Specification (ASTM/ASME) LDCN-00-096 5.2-45 Reactor vessel Rolled plate Low alloy steel SA-533 grade B class 1 Heads, shel ls Forgings Welds Low alloy s teel SA-508 class 2

SFA-5.5 Closure flange Forged ring Welds Low alloy s teel Low alloy s teel SA-508 class 2

SFA-5.5 Nozzle safe ends Forgings or Plates Stainless steel SA-182, F304 or F316 SA-336, F8 or F8 M

SA-240, 304 or 316 Welds Stainless steel SFA-519, TP-308L or 316L Nozzle safe ends Forgings Welds Ni-Cr-Fe

Ni-Cr-Fe SB-166 or SB-167 SFA-5.14, TP ERNiC r-3 or SFA-5.11,

TP ENCrFe-3 Nozzle safe ends Forgings Carbon steel SA-105 grade 2, SFA-5.18 grade A, or

SFA-5.17 F70 Nozzle safe ends Forgings Austenitic stainless steel SA-182 grade F, 316L Cladding Weld overlay Austenitic stainless steel SFA-5.9 or SFA-5.4

TP-309 with carbon

content on final surface

limit to 0.09% maximum Control rod

drive housings Pipe Forgings

Welds Austenitic stainless steel Inconel SA-312 type 304

SFA-5.11

type ENiCrFe-3 or

SFA-5.14

type ERNiCr-3

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 5.2-7 Reactor Coolant Pressure Boundary Materials (Continued) Component Form Material Specification (ASTM/ASME) LDCN-14-018 5.2-46 In-core housings Pipe Forgings

Welds Austenitic stainless steel

Inconel SA-312 type 304

SFA-5.11

type ENiCrFe-3 or

SFA-5.14

type ERNiCr-3

Additional RCPB component materi als and specifications to be used are specified below.

Depending on whether impact test s are required and depending on the lowest service metal temperature when impact tests are required, the following ferritic materials and specifications are used:

Pipe SA-106 grade B and C; SA-333 grade 5; SA-155 grade KCF 70

Valves SA-105 grade II-normalized; SA-350 grade LF1 or LF2 and SA-216 grade WCB, normalized; and SA-352 grade LCB

Fittings SA-105 grade II-normalized; SA-350 grade LF1 or LF2-normalized; SA-234 grade WPB-normalized; and SA-420 grade WPL1

Bolting SA-193 grade B7; and SA-194 grades 7 and 2H

Welding Material Welding materials conform to the applicable SFA specifications listed in ASME B&PV Code Section IIc. Individual selection of filter metals are reviewed for conformity to the ba se materials being welded by the

Consulting Engineers' review of welding procedures.

For those systems or portions of systems such as the reactor recirculation system, which require austenitic stainless steel, the following materials and specifications are used:

Pipe SA-376 type 304; SA-312 type 304; SA-358 type 304 Valves SA-182 grade F-304 and F-316; SA-351 grades CF-3, CF-3M, CF-8 and CF-8M

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-7 Reactor Coolant Pressure Boundary Mater ials (Continued)

5.2-47 Pump SA-182 grade F-304; SA-351 grades CF-8 and CF-8M

Flanges SA-182 grade F-316

Bolting SA-193 grade B7; SA-194 grades 7 and 2H Welding SFA-5.4 (E308-15, E308L-15, E316 -15); SFA-5.9 (ER-308, ER-308L, ER-316)

Fittings SA-182 grade F304; SA-351 grade CF-8; SA-403 grade WP-304, 304W

Table 5.2-8 Water Sample Locations COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 2011LDCN-09-032 5.2-48 Sample Origin Sensor Location Indicator Location Recorder Location Range mho/cm Low Alarm High Reactor water recirculation loop Sample line Sample station Control room 0-1 0.0 1.0 Reactor water cleanup system inlet Sample line Sample station Control room 0-1 0.0 1.0 Reactor water cleanup system outlets Sample line Sample station Control room 0-0.3 NA 0.15

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-9 IHSI Summary Prior to First Refueling GL 88-01,

Category B Welds

Energy Northwest ISI Weld Number Welds 5.2-49 Stainless steel to s tainless s teel 24RRC(2)-A-2 thru 24RRC(2)-A-12 11 24RRC(1)-A-13 thru 24RRC(1)-A-22 10 16RRC(1)-A-1 thru 16RRC(1)-A-4 4 12RRC(1)-N2A-1, 1A 2 12RRC(1)-N2B-1, 1A 2 12RRC(1)-N2C-1, 1A 2 12RRC(1)-N2D-1, 1A 2 12RRC(1)-N2E-1, 1A 2 20RRC(6)-1 thru 20RRC(6)-7, 7A, 8 9 4RRC(8)-2A-1, 2 2 4RRC(8)-1A-1, 2 2 12RRC(7)-A-1 thru 12RRC(7)-A-6 6 12RHR(1)-A15 thru 12RHR(1)-A18 4 24RRC(2)-B-2 thru 24RRC(2)-B-10 9 16RRC(1)-B-1 thru 16RRC(1)-B-4 4 24RRC(1)-B-11 thru 24RRC(1)-B-20 10 12RRC(1)-N2F-1, 1A 2 12RRC(1)-N2G-1, 1A 2 12RRC(1)-N2H-1, 1A 2 12RRC(1)-N2J-1, 1A 2 12RRC(1)-N2K-1, 1A 2 4RRC(8)-2B-1, 2 2 4RRC(8)-1B-1, 2 2 12RRC(7)-B-1, 2, 2A thru 12RRC(7)-B-6 7 12RHR(1)-B-11 thru 12RHR(1)-B-13 3 20RHR(2)-1 1 Stainless steel to s tainless s teel caps 24RRC(1)-A13/8CAP-1, A20/12CAP-1 2 24RRC(1)-B-11/CAP-1, 18/12CAP-1 2 Stainless steel to carbon steel 20RHR(2)-2 1 12RHR(1)-A14 1 12RHR(1)-B-10 1 TOTAL 113 COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-10

IHSI Summary During First Refueling GL 88-01,

Category B Welds

Energy Northwest ISI Weld Number Welds 5.2-50 4RRC(4) A-1 thru 4R RC(4) A-11 11 4RRC(4) B-1 thru 4RRC(4) B-12 12 24RRC(2) A-10/4RRC(8)-4S 1 24RRC(2) A-10/4RRC(4)-4S 1 24RRC(1) A-13/4RRC(8)-4S 1 24RRC(1) A-13/8 Cap 1 24RRC(1) A-20/12 Cap 1 24RRC(1) A-20/12RRC(7)-4S 1 24RRC(2) B-8/4RRC(8)-4S 1 24RRC(2) B-8/4RRC(4)-4S 1 24RRC(1) B-11/8 Cap 1 24RRC(1) B-11/4RRC(8)-4S 1 24RRC(1) B-18/12 Cap 1 24RRC(1) B-18/12RRC(7)-4S 1 TOTAL 35 Type 304 Welds with Low Carbon Content a4JP (NZ) A-1 Inconel 182 buttering 1 a4JP (NZ) B-1 Inconel 182 buttering 1 a4JP (NZ) A-2 1 a4JP (NZ) B-2 1 TOTAL 4 a Confirmed by CMTR review safe end material used was type 304 with a carbon content of 0.025%. COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-11 Main Steam Isolation Valves Material Information Item Material Spec Material Type Minimum Design Wall Thickness 5.2-51 Body SA-216 GR WCB 1.58 in. Bonnet SA-105 GR II 7.66 in. Stem disc a SA-105 N/A 1.56 in. Disc piston a SA-105 N/A 3.24 in. Stema SA-564 or A-182 Tp 630 H1100

GR F6A C1 3 Bonnet studs SA-540 Class 4 1-5/8 in. diameter Bonnet nuts SA-194 GR 7 1-5/8 in. diameter See Section 5.2.3.3 for fracture toughness response.

Piping connecting the MSIV

Outside diameter 12 in.

Nominal wall thickness = 1.103 in. plus 0.125 in. a Redesign/replacement mater ials

Table 5.2-12 Summary of Isolation/Alarm of System Monitored and the Leak Detec tion Methods Used COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-12-020 5.2-52 Variable Monitored FUNCTION A A A A/I A/I A A/I A/I A/I A/I A/I A A

Source of Leakage

Location

High PC F PC Sump High Flow Rate High/Dry-well Cooler Condensate Flowa Equip- ment Area High T and T Low Steam Line Pressure RB Sump or Drain High Flow Rate PC Pressure (High) High Flow Rateb RCIC Diaphragm High Exhaust Line Pressure RWCU Flow (High) Reactor Low Water Level High Differential Pressure Fission Products Higha Main steam line PC X X X Xc X X X X RB X Xc X X X RHR PC X X X X X X RB X X X X RCIC steam PC X X X X X X X RB X X X X RCIC water PC X RB X RWCU water PC X X X Xb X X X RB hot X X X X X RB cold X X X X Feedwater PC X X X X RB Xd X ECCS water PC X X X RB X X Reactor coolant PC X X X X X X RB PC - Primary containment RB - Reactor building RWCU - Reactor water cleanup CCW - Closed cooling water

A - Alarm I - Isolation NOTE: a All systems within the drywell share a common detection system. b Break downstream of flow element will isolate the system. c In run mode only. d Alarm only (steam tunnel).

Simulated Safety Relief Valve Spring Mode Characteristic used for Capacity Sizing Analysis1-2.564.096069 1008060402000.960.970.980.991.001.011.021.031.041.05"Opening" Path"Closing" PathCode Approved Capacity Pressure/Pressure Set Point FigureAmendment 53 November 1998Form No. 960690.veR.oN .warD Columbia Generating Station Final Safety Analysis Report FigureForm No. 960690 Draw. No. Rev.950021.16 5.2-2Columbia Generating Station Final Safety Analysis Report Amendment 63December 2015 LDCN-15-011 1 Peak Vessel Pressure Versus Safety Valve Capacity 960690.47 5.2-31400135013001250(psig)406080100120Safety Valve Capacity - % NB Rated Steam FlowNumber of Operating Safety Valves 81012141618MSIV - Flux Scram (REDY)MSIV - Flux Scram (ODYN) Code Limit(1375 psig)LR W/O BP (ODYN) 1200FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis ReportPeak Vessel Bottom Pressure (psig) Time Response of Pressure Vessel forPressurization Events 960690.48 5.2-41350130012501200115011001050MSIV Closure - Flux Scram (ODYN) MSIV Closure -

Flux Scram (REDY) LR w/o BP

Direct Scram Time (Sec) Vessel Bottom Pressure (psig) (ODYN)2468101214FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.2-52202B22-04,26,1Nuclear Boiler System - P&IDRev.FigureDraw. No. Safety/Relief Valve Schematic Elevation 960690.49 5.2-6DrywellMain Steam LineReactor Vessel Main SteamIsolation ValvesSafety/Relief Valves Suppression Pool FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Flow Restrictor Columbia Generating StationFinal Safety Analysis Report FigureForm No. 960690 Amendment 53November 1998Draw. No.Rev.960690.62Safety/Relief Valve and Steam Line Schematic 5.2-7Reactor Vessel S/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VMain Steam Lines Main Steam IsolationValvesDrywellColumbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.85Schematic of Safety Valve with Auxiliary Actuating Device 5.2-8Setpoint Adjust ScrewBonnetSpindleBalancing Piston BellowsEductorBlowdownAdjusting Ring Eductor Sleeve SteamFlowInletNozzleRingDiscDisc Ring Disc Holder Piston-type Pneumatic Actuator AssemblySPVD Linear Variable Differential Transformer (LVDT)Valve Position Indication (VPI) LVDTSet Pressure Verification Device

(SPVD) Pneumatic Head SPVD Load Cell "C""B""A"Solenoid/ Air ControlValveAssemblies Discharge NozzleBodySpringLeverSchematic of Crosby 6R10/8R10 Dual-Function Type Spring-Loaded Direct-Acting Safety/Relief Valve Columbia Generating StationFinal Safety Analysis Report FigureSafety Valve Lift Versus Time Characteristics 960690.50 5.2-9050100Time (Sec) T1 = Time at which pressure exceeds the valve set pressure T1Safety Valve openingcharacteristicsValve achieves rated capacity at < 103% of set pressureSafety Valve Lift (% of full open)ValveStroke Time 0.3Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Conductance Versus pH as a Function of ChlorideConcentration of Aqueous Solution at 25C960690.51 5.2-101001010.10.01pH (at 25C)45678910Specific Conductance (mho/cm at 25°C) 0.5Chloride(ppm)0.20.11FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Typical BWR Characteristic MSIV Closure Flux Scram 960690.525.2-11FigureAmendment 63 December 2015 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report DELETEDLDCN-15-011 COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-000 5.3-1 5.3 REACTOR VESSEL

5.3.1 REACTOR VESSEL MATERIALS

5.3.1.1 Materials Specifications

The materials used in the reactor pressure vessel and appurtena nces are shown in Table 5.2-7 together with the app licable specifications. 5.3.1.2 Special Processes Used for Manufacturing and Fabrication The reactor pressure vessel is primarily constructed from low alloy, high strength steel plate and forgings. Plates are or dered to ASME SA-533, Grade B, Class 1, and forgings to ASME SA-508, Class 2. These materials are me lted to fine grain practice and are supplied in the quenched and tempered conditio

n. Further restrictions incl ude a requirement for vacuum degassing to lower the hydrogen level and impr ove the cleanliness of the low alloy steels.

Studs, nuts, and washers for the main closure flange are ordered to ASME SA-540, Grade B23 or Grade B24. Welding electrodes are low hydrogen type ordered to ASME SFA 5.5.

All plate, forgings, and bolting are 100% u ltrasonically tested and surface examined by magnetic particle methods or li quid penetrant methods in acco rdance with ASME Section III Subsection Nuclear Boiler (NB) standards. Fr acture toughness propertie s are also measured and controlled in accordance with subsection NB requirements.

All fabrication of the reactor pressure vessel is performed in accordance with the General Electric Company (GE) approved dr awings, fabrication procedures , and test procedures. The shells and vessel heads are ma de from formed plates and the flanges and nozzles from forgings. Welding performed to join these vessel components is in accordance with procedures qualified per ASME Section III and IX requirements. Weld test samples are required for each procedure for major vessel full penetration welds. Tensile and impact tests are performed to determine the properties of the base metal, heat-affected zone (HAZ) and weld metal. Submerged arc and manual stick electrode welding processes are employed. Electroslag welding is not permitted. Preheat and interp ass temperatures employed for welding of low alloy steel meet or exceed the requirements of ASME Section III, Subsection NB. Postweld heat treatment at 1100°F minimum is a pplied to all low al loy steel welds.

Radiographic examination is performed on all pressure contai ning welds in accordance with requirements of ASME Section III, Subsection NB-5320. In addition, all welds are given a supplemental ultrasonic examination.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-2 The materials, fabrication procedures, and testing me thods used in the c onstruction of boiler water reactor (BWR) reactor pressure vessels meet or exceed requirements of ASME Section III, Class 1 vessels.

5.3.1.3 Special Methods for Nondestructive Examination

The materials and welds on the reactor pressu re vessel were examin ed in accordance with methods prescribed and met the acceptance requirements specified by ASME Boiler and Pressure Vessel (B&PV) Code Section III. In addition, the pressure retaining welds were ultrasonically examined using manual techni ques. The ultrasonic examination method, including calibration, instrument ation, scanning sensitivity, a nd coverage was based on the requirements imposed by ASME Co de Section XI in Appendix I. Acceptance standards were equivalent or more restrictive than required by ASME Code Section XI.

5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels

The degree of compliance with Regulatory Guides 1.31, 1.34, 1.43, 1.44, 1.50, 1.71, and 1.99 is described in Section 1.8. 5.3.1.5 Fracture Toughness

5.3.1.5.1 Compliance w ith Code Requirements

The ferritic pressure boundary mate rial of the reactor pressure vessels was qualified by impact testing in accordance with the 1971 edition of Section III ASME Code and Summer 1971 Addenda. From an operational standpoint, the minimum temperature limits for pressurization defined by the 1998 Edition of Section XI ASME Code and 2000 Addenda, Appendix G, Protection Against Nonductile Failu re, are used as the basis for compliance with ASME Code Section III.

5.3.1.5.2 Compliance with 10 CFR 50 Appendix G

A major condition necessary for full compliance to Appendix G was satisfaction of the

requirements of the Summer 1972 Addenda to Section III. This was not possible with components which were purchased to earlier Code requirements. For the extent of the compliance, see Table 5.3-1 . Ferritic material complying w ith 10 CFR 50 Appendix G must ha ve both drop-weight tests and Charpy V-notch (CVN) tests with the CVN specimens oriented transverse to the maximum material working direct ion to establish the RTNDT. The CVN tests must be evaluated against both an absorbed energy and a lateral expansion criteria. The maximum acceptable RT NDT must be determined in accordance with the analytical procedures of ASME Code Section III, Appendix G. Appendix G of 10 CFR 50 requir es a minimum of 75 ft-lb upper shelf CVN

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-3 energy for beltline material. It also requires at least 45 ft-lb CVN energy and 25 mils lateral expansion for bolting material at the lower of the preload or lowest service temperature.

By comparison, material for the Columbia Generating Statio n (CGS) reactor vessels was qualified by either drop-weight tests or longitudinally oriented CVN tests (both not required), confirming that the material nil-ductility transi tion temperature (NDTT) is at least 60°F below the lowest service temperature. When the CVN test was app lied, a 30 ft-lb energy level was used in defining the NDTT. There was no upper shelf CVN energy requirement on the beltline material. The bolting material was qualified to a 30 ft-lb CVN energy requirement at 60°F below the minimum preload temperature.

From the previous comparison it can be seen that the fracture toughness testing performed on the CGS reactor vessel material cannot be shown to comply with 10 CFR 50 Appendix G. However, to determine operating limits in accordance with 10 CFR 50 Appendix G, estimates of the beltline material RT NDT and the highest RT NDT of all other material were made and are discussed in Section 5.3.1.5.2.2 . The method for developing these operating limits is also described therein.

On the basis of the last paragraph on page 19013 of the July 17, 1973, Federal Register, the following is considered an appr opriate method of compliance.

5.3.1.5.2.1 Intent of Proposed Approach . The intent of the prop osed special method of compliance with 10 CFR 50 Appendix G for this vessel is to provide operating limitations on pressure and temperature based on fracture tou ghness. These operating limits ensure that a margin of safety against a nonductile failure of this vessel is very nearly the same as that for a vessel built to the Summer 1972 Addenda.

The specific temperature limits for operation when the core is critical are based on 10 CFR 50 Appendix G, Paragr aph IV, A.2.C.

5.3.1.5.2.2 Operating Limits Based on Fracture Toughness . Operating limits which define minimum reactor vessel metal temperatures versus reactor pre ssure during normal heatup and cooldown and during inservice hydrostatic testi ng were established us ing the methods of Appendix G of Section XI of the ASME B&PV Code, 1998 Edition, 2000 Addenda. The results are shown in Figure 5.3-1 . All the vessel shell and head area s remote from discontinuities plus the feedwater nozzles were evaluated, and the operating limit curves are ba sed on the limiting location. The boltup limits for the flange and adjacent shell region ar e based on a minimum metal temperature of RTNDT +60°F. The maximum through-wall temperatur e gradient from continuous heating or cooling at 100°F/hr was considered. The safety factors applied were as specified in ASME Section XI Appendix G.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-4 For the purpose of setting these operating limits the reference temperature, RT NDT, is determined from the toughness te st data taken in accordance with requirements of the code to which this vessel is designed and manufactured. This tough ness test data, CVN and/or dropweight NDT, is analyzed to permit complian ce with the intent of 10 CFR 50 Appendix G. Because all toughness tes ting needed for strict compliance with Appendix G was not required at the time of vessel procurement some toughne ss results are not available. For example, longitudinal CVNs, instead of transverse, were tested, usually at a single test temperature of +10°F or -20°F, for absorbed energy. Also, at the time either CVN or NDT testing was permitted; therefore, in many cases both tests were not performed as is currently required. To substitute for this absence of certain data, toughness property corr elations were derived for the vessel materials to operate on the available data to give a conservative estimate of RT NDT compliant with the intent of Appendix G criteria.

These toughness correlations vary , depending upon the specific ma terial analyzed, and were derived from the results of We lding Research Counc il (WRC) Bulletin 217, "Properties of Heavy Section Nuclear Reactor Steels," and from toughness data from the CGS vessel and other reactors. In the case of vessel plate material (SA-533 Grade 8, Class 1), the predicted limiting toughness property is either NDT or transverse CVN 50 ft-lb temperature minus 60°F. NDT values are available for CGS vessel shell plates. The transverse CVN 50 ft-lb transition temperature is estimated from longitudinal CV N data in the following manner. The lowest longitudinal CVN 50 ft-lb value is adjusted to derive a longitudinal CVN 50 ft-lb transition temperature by adding 2°F per ft-lb to the test temperature. If the actual data equals or exceeds 50 ft-lb, the test temperature is used. Once the longitudinal 50 ft-lb temperature is derived, an additional 30°F is added to account for orientati on effects and to estimate the transverse CVN 50 ft-lb temperature minus 60°F, estimated in the preceding manner.

Using the above general approach, an initial RT NDT of 28°F was established for the core beltline region.

For forgings (SA-508 Class 2), the predicted limiting property is the same as for vessel plates. CVN and NDT values are availabl e for the vessel flange, closure head flange, and feedwater nozzle materials for CGS. RT NDT is estimated in the same way as for vessel plate.

For the vessel weld metal th e predicted limiting property is the CVN 50 ft-lb transition temperature minus 60°F, as the NDT values are -50°F or lower for these materials. This temperature is derived in th e same way as for the vessel plate material, except the 30°F addition of orientation effects is omitted since there is no princi pal working direction. When NDT values are available, they are also considered and the RT NDT is taken as the higher of NDT or the 50 ft-lb temperat ure minus 60°F. When NDT is not available, the RTNDT shall not be less than -50°F, since lower values are not supported by the correlation data.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-5 For vessel weld HAZ material the RT NDT is assumed the same as for the base material as ASME Code weld procedure qualification test requirements, and postweld heat treatment indicates this assumption is valid.

Figure 5.3-2 provides a sketch of the reactor ve ssel, including the basic dimensions, all longitudinal and circumferential welds, and all pl ates of the beltline region. Tables 5.3-2 through 5.3-7 contain the supporting information for Figure 5.3-2, such as piece mark, heat number, and impact data for th e plates and filler material used in the beltline region. Closure bolting material (SA-540 Grade B24) t oughness test requirement s for CGS were for 30 ft-lb at 60°F below the boltup temperature. Current code requirements are for 45 ft-lb and 25 mils lateral expansion at the preload or lowest service temperature, including boltup. All CGS closure stud materials meet current requirements at +10°F. The effect of the main closure flange discontinuity was considered by adding 60°F to the RTNDT to establish the minimum temperature fo r boltup and pressurization. The minimum boltup temperature of 80°F for CGS, which is shown on Figure 5.3-1 , is based on an initial RTNDT of +20°F for the shell plate connec ting to the closure flange forgings.

The effect of the feedwa ter nozzle discontinuities were consid ered by adjusting the results of a BWR/6 reactor discontinuity analysis to the reactor. The ad justment was made by increasing the minimum temperatures required by the diffe rence between the CGS and BWR/6 feedwater nozzle forging RT NDT. The feedwater nozzle adju stment was based on an RT NDT of 0°F.

The reactor vessel closure studs have a minimum Charpy impact energy of 45 ft-lb and 26 mils lateral expansion at 10°F. The lowest service temperature for the closure studs is 10°F.

Vessel irradiation embrittlement of beltline materials, as measured by adjusted reference temperatures and upper shelf en ergies due to increased flux , was evaluated against the requirements of 10 CFR 50 Appendix G. For a predicted fluence of 7.41 x 10 17n/cm2, fracture toughness values are acceptable and remain within Appendix G limits.

5.3.1.5.2.3 Temperature Limits for Boltup . A minimum temperature of 10°F is required for the closure studs. A sufficient number of studs may be tensioned at 70°F to seal the closure flange O-rings for the purpose of raising reactor water level above the clos ure flanges to assist in warming them. The flanges and adjacent shell are required to be warmed to a minimum temperature of 80°F before they are stressed by the full intended bolt preload. The fully preloaded boltup limits are shown in Figure 5.3-1 . 5.3.1.5.2.4 Inservice Inspection Hy drostatic or Leak Pressure Tests . Based on 10 CFR 50 Appendix G, and Regulatory Guid e 1.99, Revision 2, requirements, pressure/temperature limit curves were estab lished based on an RT NDT of 28°F for the limiting beltline material; see Figure 5.3-1 . The fracture toughness analysis for inse rvice inspection of le ak test resulted in

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-13-009 5.3-6 curve A shown in Figure 5.3-1 . The predicted shift in the RT NDT temperature was determined using the methodology outlined in Regulatory Guide 1.99, Revision 2.

Technical Specification 3.10.1 allo ws inservice leak and hydrostatic testing to be performed in Mode 4 when the metallurgical characteristics of the reactor pressure vessel require testing at temperatures greater than 200F, given specified Mode 3 Limiting Conditions for Operations are met. This exemption is only applicable provided reactor coolant temperature does not exceed 275F. 5.3.1.5.2.5 Operating Limits During Heatup, Cooldown, and Core Operation. The fracture toughness analysis was done for the normal heat up or cooldown rate of 100°F/hr. The temperature gradients and thermal stress effects corresponding to th is rate were included. The results of the analysis ar e operating limits defined by Figure 5.3-1 . Curves A, B, and C give the limits for hydrotest, nonnucl ear heating, and nuclear heating. The minimum boltup temperature of 80°F is based on an RT NDT at 20°F for a shell plate wh ich connects to the lower flange (Heat and Slab No. C-1307-2); above 80°F the core beltline plate (Heat and Slab No. C-1272-1), which has an initial RT NDT of 28°F, is most limiting for inservice hydrostatic or leak pressure tests (curve A). The feedwater nozzles, which have an RT NDT of 0°F, are more restrictive than the core beltline at lower pressures during nonnucl ear and nuclear heating (curves B and C).

5.3.1.5.2.6 Reactor Vessel Annealing. Inplace annealing of the reactor vessel to counteract radiation embrittlement is unnecessary because beltl ine material adjusted reference temperature of the NDT is well within the 10 CFR 50 Appendix G 200°F screening limit.

5.3.1.6 Material Surveillance

The materials surveillance progr am monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting from exposure to neutron irradiation and ther mal environment.

The CGS plant-specific RPV ma terials surveillance program is replaced by the NRC approved BWR Vessel and Internals Proj ect (BWRVIP) Integrated Su rveillance Program (ISP), as described in the latest approved revision of BWRVIP-86 (Reference 5.3.4-2). The ISP meets the requirements of 10 CFR 50, Appendix H.

The current surveillance capsule withdrawal schedule for the re presentative materials for the CGS vessel is based on th e latest approved revision of BWRVIP-86 (Reference 5.3.4-2). No capsules from the CGS ve ssel are included in the ISP. Th e withdrawal of capsules for the CGS plant-specific surveillance program is perman ently deferred by participation in the ISP. Capsules from other plants will be remove d and tested in acco rdance with the ISP COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005, 04-033 5.3-7 implementation plan. The results from these tests will provide the necessary data to monitor embrittlement for the CGS vessel.

Materials for the plant-specific materials surveillance program were se lected to represent materials used in the reactor beltline region. The specimens were manufactured from a plate actually used in the beltline region and a weld typi cal of those in the be ltline region and thus represent base metal, weld meta l, and the transition zone betw een base metal and weld. The plate and weld were heat treated in a manner which simulates the actual heat treatment performed on the core regi on shell plates of the comp leted vessel. WPPSS-ENT-089 (Reference 5.3.4-1) provides additional de tail and supporting inform ation for the materials surveillance program. For the extent of compliance to 10 CFR 50 Appendix H, see Table 5.3-8 . NEDO-21708 also addressed the requirements of Appendix H to 10 CFR 50 and supports the current application of Regulatory Guide 1.99.

5.3.1.6.1 Positioning of Surve illance Capsules and Method of Attachment for Plant-Specific Surveillance Program

Surveillance specimen capsules are located at three azimuths at a common elevation in the core beltline region. The sealed capsules are not atta ched to the vessel but are in welded capsule holders. The capsule holders are mechanically restrained by capsule holder brackets as shown in Figure 5.3-4. The capsule holder brackets allow the capsule holder to be removed at any desired time in the life of the plant for specimen testing. A positive spring-loaded locking device is provided to retain the capsules in pos ition throughout any anticipated event during the lifetime of the vessel.

The capsule holder brackets are designed, fabricat ed, and analyzed to th e requirements of the ASME B&PV Code Section III. The surveillance brackets are welded to the clad material which surfaces the pressure vessel walls. As attached , the brackets do not ha ve to comply with specifications of the ASME Code.

5.3.1.6.2 Time and Number of Dosimetry Measurements

General Electric provides a sepa rate neutron dosimeter so that fluence measurements may be made at the vessel ID during the first fuel cycle to verify the predicted fluence at an early date in plant operation. This measurement is made ov er this short period to avoid saturation of the dosimeters now available. Once the fluence-to -thermal power output is verified, no further dosimetry is considered necessary because of the linear relationship be tween fluence and power output.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-8 5.3.1.6.3 Neutron Flux a nd Fluence Calculations

A description of the methods of analysis for neutron flux and fl uence calculations is contained in Sections 4.1.4.5 and 4.3.2.8. 5.3.1.7 Reactor Vessel Fasteners

The reactor vessel closure head (flange) is fastened to the reactor vessel shell flange by multiple sets of threaded studs and nuts. The lower end of each stud is installed in a thread hole in its vessel shell flange. A nut and washer are installed on the upper end of each stud. The proper amount of preload can be applied to the studs by sequential te nsioning using hydraulic tensioners. The design a nd analysis of this area of th e vessel is in full compliance with all Section III Class 1 Code requirements. The material for studs, nuts, and washers is SA-540, Grade B23 or B24. The maximum reported ultimate te nsile stress for the bolting material was 167,000 psi whic h is less than the 170,000 psi limitation in Regulatory Guide 1.65. Also the Charpy impact test recommendations of Pa ragraph IV.A.4 of Appendix G to 10 CFR 50 were not specified in the vessel order since the order was placed prior to issuance of Appendix G to 10 CFR 50. However, impact data from the certified materials report shows that all bolting material has met the Appendix G im pact properties. For example, the lowest reported CV N energy was 45 ft-lb at 10°F ve rsus the required 45 ft-lb at 70°F and the lowest reported CV N expansion was 26 mils at 10°F versus the required 25 mils at 70°F.

Hardness tests are performed on a ll main closure bolting to demonstrate that heat treatment has been properly performed. Studs, nuts, and washers are ultras onically examined in accordance with Section III, N8-2585 and the following additiona l requirements:

a. Examination is performed after heat treatment and pr ior to machining threads.

b. Straight beam examination is performed on 100% of each stud. Reference standard for the radial scan is 0.5-in

. diameter flat bottom hole having a depth equal to 10% of the material thickness. For the end scan the reference standard is a 0.5-in. flat bottom hole having a dept h of 0.5 in. For additional details of the techniques used to examine the reactor vessel studs, s ee the response to Regulatory Guide 1.65, Revision 0, October 1973, in Section 1.8.

c. Nuts and washers are examined by angle beam from the outside circumference in both the axial and circ umferential directions.

There are no metal platings applied to closure studs, nuts, or washers. A phosphate coating is applied to threaded areas of studs and nuts and bearing areas of nuts and washers to act as a rust inhibitor and to assist in re taining lubricant on these surfaces.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-9 5.3.2 PRESSURE-TEMPERATURE LIMITS

5.3.2.1 Limit Curves

Limits on pressure and temperat ure for inservice leak and hydr ostatic tests, normal operation (including heatup and cool down), and reactor core operation are shown in Figure 5.3-1 . The basis used to determine these limits is described in Section 5.3.1.5. 5.3.2.2 Operating Procedures

By comparison of the pressure versus temperature limits in Figure 5.3-1 with intended normal operating procedures for the most severe upset transient, it is shown that the limits will not be exceeded during any foreseeable upset condition. Reactor operating procedures have been

established such that actual tran sients will not be more severe than those for which the vessel design adequacy has been demonstrated. Of the design transients, the upset condition producing the most adverse temp erature and pressure condition anywhere in the vessel head and/or shell areas has a minimu m fluid temperature of 250°F a nd a maximum pressure peak of 1180 psig. Scram automatically oc curs with initiation of this even t, prior to the reduction in fluid temperature, such that the applicable operating limits are bounded by curve A of Figure 5.3-1 . Figure 5.3-1 show that at the maximum tran sient pressure of 1180 psig, the minimum allowable reactor ve ssel metal temperature conser vatively bounds the minimum 250°F reactor fluid temperature.

5.3.3 REACTOR VESSEL INTEGRITY

The reactor vessel was fabricated for GE's Nuclear Energy Di vision by CBI Nuclear Co., and was subject to the requirements of GE's Quality Assurance program.

Assurance was made that measures were es tablished requiring that purchased material, equipment, and services associated with the reactor vessel and appurt enances conform to the requirements of the subject purchase documents . These measures included provisions, as appropriate, for source evalua tion and selection, objective ev idence of quality furnished, inspection at the vendor source, and examin ation of the comple ted reactor vessel.

Energy Northwest's agent provided inspection surveillance of the reactor vessel fabricators in process manufacturing, fabrication, and tes ting operations in accordan ce with GE's Quality Assurance program and approved inspection procedures. The reactor vessel fabricator was responsible for the first level in spection of manufactur ing, fabrication, and testing activities, and GE was responsible for the first level of audit a nd surveillance inspection.

Adequate documentary evidence that the reactor vessel material, manufacture, testing, and inspection conforms to the specified quality assurance re quirements contained in the procurement specification is available in plant records. COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-033, 05-021 5.3-10 5.3.3.1 Design

5.3.3.1.1 Description

5.3.3.1.1.1 Reactor Vessel . The reactor vessel shown in Figure 5.3-5 is a vertical, cylindrical pressure vessel of welded cons truction. The vessel is designed, fabricated, tested, inspected, and stamped in accordance with the ASME Code Section III, Cla ss 1, including the addenda in effect at the date of order pl acement. Design of the reactor ve ssel and its support system meets Seismic Category I equipment requirements. The materials used in the reactor pressure vessel are shown in Table 5.2-7 . The cylindrical shell and bottom head sections of the reactor vessel are fabricated of low alloy steel, the interior of which is clad with stainless steel weld overlay. Nozzle and nozzle weld zones are unclad except fo r those mating to stainless steel piping systems.

Inplace annealing of the reactor vessel is unnecessary because shifts in transition temperature caused by irradiation during the 40-year life can be accommodated by raising the minimum pressurization temperature. Radiation embrittle ment is not a problem outside of the vessel beltline region because the irradiation in those areas is less than 1 x 10 18 nvt with neutron energies in excess of 1 MeV. The inside diameter and mini mum wall thickness of the reactor vessel beltline is provided in Table 5.3-9 . Quality control methods used dur ing the fabrication and assemb ly of the reactor vessel and appurtenances ensure that design specifications were met. The ve ssel top head is secured to the reactor vessel by studs and nuts. These nuts are tightened with a stud tensioner. The vessel flanges are sealed with two concentric metal seal rings de signed to permit no detectable leakage through the inner or outer seal at any operating condition, including heating to operating pressure and te mperature at a maximum rate of 100°F/hr in any 1-hr period. To detect seal failure, a vent tap is located between the two seal rings. A monitor line is attached to the tap to provide an indication of leakage from the inner seal ring seal.

5.3.3.1.1.2 Shroud Support . The shroud support is a circular plate welded to the vessel wall. This support is designed to ca rry the weight of the shroud, shroud head, peripheral fuel elements, neutron sources, core plate, top guide, the steam separators, the jet pump diffusers, jet pump slip joint clamps, and to laterally support the fuel as semblies. Design of the shroud support also accounts for pressure differentials across the shroud support plate, for the restraining effect of component s attached to the support, and for earthquake loadings. The shroud support design is specified to m eet appropriate ASME Code stress limits.

5.3.3.1.1.3 Protec tion of Closure Studs. The BWR does not use borated water for reactivity control. This section is therefore not applicable.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-11 5.3.3.1.2 Safety Design Bases

Design of the reactor vessel a nd appurtenances meet the foll owing safety design bases:

a. The reactor vessel and appurtenances will withstand adverse combinations of loading and forces resulting from operation under abnor mal and accident conditions, and

b. To minimize the possibility of brittle fracture of the nucl ear system process barrier, the following are required:

1. Impact properties at temperatures related to vessel ope ration have been specified for materials used in the reactor vessel.

2. Expected shifts in transition temp erature during design life as a result of environmental conditions, such as ne utron flux, are considered in the design. Operational limitations ensure that NDTT shifts are accounted for in reactor operation.

3. Operational margins to be obser ved with regard to the transition temperature are specified for each mode of operation.

5.3.3.1.3 Power Gene ration Design Basis

The design of the reactor vessel and appurte nances meets the following power generation design basis:

a. The reactor vessel has been desi gned for a useful life of 40 years,

b. External and internal supports that ar e integral parts of the reactor vessel are located and designed so that stresses in the vessel and supports that result from reactions at these supports are within ASME Code limits, and

c. Design of the reactor vessel and appurte nances allow for a suitable program of inspection and surveillance.

5.3.3.1.4 Reactor Vessel Design Data

Reactor vessel design data are contained in Tables 5.2-6 and 5.2-7. COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-12 5.3.3.1.4.1 Vessel Support . The concrete and steel vessel support pedestal is constructed as an integral part of the building foundation. Steel anchor bolts set in the concrete extend through the bearing plate and secure the flange of the reactor vessel support skirt to the bearing plate and thus to the support pedestal.

5.3.3.1.4.2 Contro l Rod Drive Housings . The control rod drive (C RD) housings are inserted through the CRD penetrations in the reactor vessel bottom head and are welded to the reactor vessel. Each housing transmits loads to the bottom h ead of the reactor. These loads include the weights of a control rod, a CRD, a CRD t ube, a four-lobed fuel s upport piece, and the four fuel assemblies that rest on the fuel support piece. The housings are fabricated of Type 304 austenitic stainless steel.

5.3.3.1.4.2.1 Control Rod Drive Return Line . To preclude CRD return line cracking on CGS, the return line was deleted and the system modified. The modification cons ists of adding pressure equalizing valves be tween the exhaust and cooling water headers and the use of reverse flow through multiple hydr aulic control unit (HCU) solenoi d valves as the CRD system exhaust flow path. The acceptance of this modification is based on system analyses and performance tests conducted on operating BWRs which have shown satisfactory system operation. The system tests showed that system pressure transients, CRD settling times, and CRD speeds were all unchanged. The tests also showed that all syst ems functions performed normally.

5.3.3.1.4.3 In-Core Neut ron Flux Monitor Housings. Each in-core neutron flux monitor housing is inserted through the in-core penetrati ons in the bottom head and is welded to the inner surface of the bottom head.

An in-core flux monitor guide t ube is welded to the top of each housing and either a source range monitor/intermediate range monitor drive unit or a local power range monitor is bolted to the seal/ring flange at the bottom of the housing.

5.3.3.1.4.4 Reactor Vessel Insulation . The insulation panels for the cylindrical shell of the vessel are self-supporting, with seis mic restraints attach ed to the sacrificia l shield wall. The insulation is designed to be re movable over those portions of the vessel where required for the purpose of in-service inspection. 5.3.3.1.4.5 Reactor Vessel Nozzles . All piping connecting to the reactor vessel nozzles has been designed so as not to exceed the allowable loads on any nozzle. The vessel top head nozzle is provided with a flange with large groove facing. The drain

nozzle is of the full penetration weld design. The recirculation inlet nozzles (located as shown in Figure 5.3-5), feedwater inlet nozzles, core spray inlet nozzles, low-pressure coolant injection (LPCI) nozzles, and the CRD hydraulic system return nozzle all have thermal sleeves. Nozzles connecting to stainless steel piping have safe ends or extensions made of COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-13 stainless steel. These safe ends or extensions were welded to the nozzles after the pressure vessel was heat treated to avoid furnace sensitization of the stainless steel. The material used is compatible with the material of the mating pipe.

The nozzle for the standby liquid control (SLC) pipe was designed to minimize thermal shock effects on the reactor vessel in th e event of injection of cold SLC solution. However, the SLC injection pipe has been relocate d to a nozzle on the high-pressure core spray (HPCS) injection line and no longer uses the old nozzle in the bottom head of the reactor pressure vessel. The old nozzle is still in service as the connection for pressure sensing belo w the core plate, but there is no flow through the nozzle under any oper ating condition.

In the past, thermal fatigue cracking of feedwater nozzles and vibrational cracking of sparger arms have been observed at other operating BWRs. The mechanisms which have caused cracking in other operating BWRs are understood . A summary discussion of these problems and the solutions incorporated in the CGS design is presented in the following.

A detailed evaluation of the problems of the feedwater nozzle and spar ger is presented in NEDE-21821, "BWR Feedwater No zzle/ Sparger Final Report," March 1978. The solution of the feedwater nozzle and sparger cracking pr oblems involved severa l elements, including material selection and processing, nozzle clad elimination, and ther mal sleeve and sparger redesign. The following summarizes the problem s and solutions that have been implemented in the CGS design.

Problem Cause Fix Sparger arm cracks Vibration Eliminated clearance between thermal sleeve and safe end

RPV feedwater Thermal Eliminated clad, thermal fatigue eliminated leakage with a welded joint between the sparger and safe end The sparger vibration has been a ttributed to a self-excitation caused by instability of leakage flow through the annular clearance between the thermal sleeve and safe end. Tests have shown that the vibration is eliminated if the clearance is reduced sufficiently or sealed. The solution that was selected for CGS uses a welded joint to ensure no leakage. This feature is also an essential part of the solution of the nozzle cracking problem. Freedom from vibration over a range of conditions has been demonstrated by the tests reported in NEDE-23604 (see Figures 5.3-6 and 5.3-7). COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-033 5.3-14 The cracking of the feedwater noz zles is a two-part process. The crack initiation mechanism as discussed above is the resu lt of self-initiated thermal cycling. If this were the only mechanism present, the cracks would initiate, grow to a depth of approximately 0.25 in., and arrest. This degree of cracking could be to lerated; however, there is another mechanism which supports crack growth. This mechanism is the system induced tr ansients, primarily the startup/shutdown transients. Because of CGS's welded thermal sleeve arrangement, leakage flow is eliminated and the heat transfer between the feedwater and the nozzle are reduced to the point where the thermal stresses in the nozzle are not high enough to cause a significant crack growth. Analyses presented in NEDE-21821, Section 4.7, demonstrated the benefits of the welded thermal sleeve and of using unclad nozzles. With these demonstrated benefits and inservice surveillance, CGS found it unnecessary to install instrumentation for design verification.

CGS has installed two automatic feedwater low flow control va lves, RFW-FCV-10A and 10B. These valves have the capacity to control flow down to 362 gpm, or about 1.25% of total flow. This valve configuration will substantially reduce the temperature differential between the feedwater and the water in the RPV during low power operation, also reducing the thermal stresses in the nozzle.

5.3.3.1.4.6 Materials and Inspection . The reactor vessel was de signed and fabricated in accordance with the appropriate ASME B&PV Code as defined in Section 5.2.1.2. Table 5.2-7 defines the materials and specifications. Table 5.3-8 defines the compliance with reactor vessel material surve illance program requirements.

5.3.3.1.4.7 Reactor Vessel Schematic (BWR) . The reactor vessel sche matic is contained in Figure 5.3-3 . Trip system water levels are indicated as shown.

5.3.3.2 Materials of Construction

All materials used in the construction of the reactor pressure ve ssel conform to the requirements of ASME Code Section II materials. The vessel heads, shells, flanges, and nozzles are fabricated from low alloy steel plate and forgings purchased in accordance with ASME specifications SA533 Grad e B Class 1 and SA-508 Class

2. Special requirements for the low alloy steel plate and forgings are discussed in Section 5.3.1.2. Cladding employed on the interior surfaces of the vessel consists of austenitic stainless steel weld overlay.

These materials of construction were selected because they provide adequate strength, fracture toughness, fabricability, and compatibility with the BWR environment. Their suitability has been demonstrated by long-term successful operating experience in reactor service.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-15 5.3.3.3 Fabrication Methods The reactor pressure vessel is a vertical cyli ndrical pressure vessel of welded construction fabricated in accordance with ASME Code Section III, Class 1, requirements. All fabrication of the reactor pressure vessel was performed in accordance with buyer-approved drawings, fabrication procedures, and test procedures. The shells and vessel heads were made from formed low alloy steel plates and the flanges and no zzles from low alloy steel forgings. Welding performed to join these vessel components was in accordance with procedures qualified per ASME Section III and IX requirements. Weld test samples were required for each procedure for major vesse l full penetration welds.

Submerged arc and manual stick electrode welding processes we re employed. Electroslag welding was not permitted. Preheat and interpass temperatures employed for welding of low alloy steel met or exceeded the requirements of ASME Section III, Subsection NB. Postweld heat treatment of 1100°F minimum was applied to all low alloy steel welds.

All previous BWR pressure vesse ls have employed sim ilar fabrication met hods. These vessels have operated for periods up to 16 years and their service history is excellent.

The vessel fabricator, CBI Nu clear Co., has had extensive experience with GE, reactor vessels, and has been the primary supplier for GE domestic reactor vesse ls and some foreign vessels since the company was formed in 1972 from a merger agreement between Chicago Bridge and Iron Co. and GE. Prior experience by the Chicago Bridge and Iron Co. with GE reactor vessels dates back to 1966.

5.3.3.4 Inspection Requirements

All plate, forgings, and bolti ng were 100% ultrasonically te sted and surface examined by magnetic particle methods or li quid penetrant methods in acco rdance with ASME Section III requirements. Welds on the reactor pressure vessel were examin ed in accordance with methods prescribed and met the acceptance requi rements specified by AS ME Section III. In addition, the pressure-retaining welds were ultrasonically examined usin g acceptance standards which were required by ASME Section XI.

5.3.3.5 Shipment and Installation

The completed reactor vessel was given a thorough cleaning and examination prior to shipment. The vessel wa s tightly sealed for shipment to pr event entry of dirt or moisture. Preparations for shipment were in accordance with de tailed written procedures. On arrival at the reactor site the reactor vessel was carefully examined for evidence of any contamination as a result of damage to shipping covers. Suitable measures were taken during installation to ensure that vessel integrity was maintained; for example, acces s controls were applied to COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-16 personnel entering the vessel, weather protec tion was provided, peri odic cleanings were performed, and only approved miscellaneous materials were us ed during assembly. 5.3.3.6 Operating Conditions

Restrictions on plant operation to hold thermal stresses within acceptable ranges are included in the Technical Specifications. These re strictions on coolant temperature are

a. The average rate of change of react or coolant temperatur e during normal heatup and cooldown,

b. Coolant temperature difference between the dome (inferred from P sat) and the bottom head drain, and

c. Idle reactor recirculation loop a nd average reactor c oolant temperature differential.

The limit regarding the normal rate of heatup and cooldown (item a) as sures that the vessel closure, closure studs, vessel support skirt, and CRD housing and stub tube stresses and usage remain within acceptable limits. The vessel temperatur e limit on recirculating pump operation and power level increase restriction (item b) augments the it em a limit in further detail by ensuring that the vessel bottom head region will not be warmed at an ex cessive rate caused by rapid sweep out of cold coolant in the vessel lower head region by recirculating pump operation or natural circulation (cold coolant can accumulate as a result of control drive inleakage and/or low recirculati on flow rate during startup or hot standby). The item c limit further restricts operation of the recirculating pumps to avoid high thermal stress effects in the pumps and piping, while also minimizing thermal stresses on the vessel nozzles.

The above operational limits when maintained insu re that the stress limi ts within the reactor vessel and its components are with in the thermal limits to whic h the vessel was designed for normal operating conditions. To maintain the material integrity of the vess el in the event that these operational limits are exceeded the reactor vessel has also been designed to withstand a limited number of transients caused by operator error. Reactor vessel material integrity is also maintained during abnorm al operating conditions where safety systems or controls provide an automatic response in the reactor vessel. The special and transi ent events cons idered in the design of the vessel are discus sed or referenced in Section 5.2.2. 5.3.3.7 Inservice Surveillance

Inservice inspection of the reactor pressure vessel is in acco rdance with the requirements as discussed in Section 5.2.4. The vessel was examined once prior to startup to satisfy the preoperational requirements of IS-232 or the ASME Code, Secti on XI. Subsequent inservice COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-13-009 5.3-17 inspection will be scheduled and performed in accordance with the requirements of 10 CFR 50.55a subparagraph (g).

The materials surveillance progr am monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting fr om their exposure to neutron irradiation and thermal environment. See Section 5.3.1.6 for description of the materials surveillance program. Operating procedures will be modified in accordance with test results to ensure adequate brittl e fracture control. Material surveillance programs and inservice inspection programs ar e in accordance with applicable ASME Code require ments and provide assurance th at brittle fracture control and pressure vessel integrity will be maintained throughout the service lifetime of the reactor pressure vessel.

5.

3.4 REFERENCES

5.3.4-1 WPPSS-ENT-089, "WNP-2 RPV Surv eillance Program," Current Revision.

5.3.4-2 BWRVIP-86, Revision 1-A, "BWR Vessel and Inte rnals Project, Updated BWR Integrated Surveillance Program (ISP) Implementation Plan," Final Report, October 2012.

Table 5.3-1 10 CFR 50 Appendix G Matrix Appendix G Paragraph Topic ComplyYes/Noor N/A Alternative Actions or Comments COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 19985.3-19I, II Introduction; Definitions -- III.A Compliance with ASME Code, Section NB-2300 Yes See Section 5.3.1.5.2 for discussion. III.B.1 Location and Orientation of Impact Test Spec Yes See III.A above. III.B.2 Materials Used to Prepare Test Specimens No Compliance except for CVN orientation and CVN upper shelf. III.B.3 Calibration of Temperature Instruments and Charpy Test Machines No Paragraph NB-2360 of the ASME B&PV Code Section III was not in existence at the time of purchase of the CGS reactor pressure vessel. However, the requirements of the 1971 edition of the ASME B&PV Section III code, Summer 1971 addenda, were met. For the discussions of the GE interpretations of compliance and NRC acceptance see References 1 and 2. The temperature instruments and Charpy Test Machines calibration data are retained until the next recalibration. This is in accordance with Regulatory Guide 1.88, Revision 2, GE Alternative Position 1.88, and ANSI N45.2.9-1974. Therefore, the instrument calibration data for CGS would not be currently available. III.B.4 Qualification of Testing Personnel No No written procedures were in existence as required by the regulation; however, the individuals were qualified by on-the-job training and past experience. For the discussion of the GE interpretation of compliance and NRC acceptance see References 1 and 2. III.B.5 Test Results Recording and Certif ication Yes See References 1 and 2. III.C.1 Test Conditions No See III.A, III.B.2 above. Table 5.3-1 10 CFR 50 Appendix G Ma trix (Continued) Appendix G Paragraph Topic ComplyYes/Noor N/A Alternative Actions or Comments COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000LDCN-99-086 5.3-20III.C.2 Materials Used to Prepare Test Specimens for Reactor Vessel Beltline Yes Compliance on base metal and weld metal tests. Test weld not made on same heat of base plate necessarily. IV.A.1 Acceptance Standard of Materials -- IV.A.2.a Calculates Stress Intensity Factor Yes IV.A.2.b Requirements for Nozzles, Flanges, and Shell Region Near Geometric Discontinuities No Plus 60F was added to the RTNDT for the reactor vessel flanges. For feedwater nozzles the results of the BWR/6 analysis was adjusted to CGS RTNDT conditions. IV.A.2.c RPV Metal Temperature Requirement When Core is Critical Yes Comply with 10 CFR 50 Appendix G. IV.A.2.d Minimum Permissible Temperature During Hydro Test Yes IV.A.3 Materials for Piping, Pumps, and Valves No Main steam line piping is in compliance. See 5.2.3.3 for discussions on pumps and valves. IV.A.4 Materials for Bolting and Other Fasteners Yes Current toughness requirements for closure head studs are met at +10F even though testing was done per the 1971 ASME code. IV.B Minimum Upper Shelf Energy for RPV Beltline No Weld and longitudinal CVN data were taken at -20F and +10F only. An estimate of compliance to requirements should be made from the first surveillance capsule results per MTEB 5-2. Table 5.3-1 10 CFR 50 Appendix G Ma trix (Continued) Appendix G Paragraph Topic ComplyYes/No or N/A Alternative Actions or Comments COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORTDecember 2005LDCN-04-005, 04-033 5.3-21IV.B (continued) Beltline plates were tested with longitudinal CVNs at +10 °F only. The minimum values are for Heat C1272-1 (0.15% Cu; 34, 26, 30, 31, 34, 30 ft-lb; 10 and 40% shear at +10 °F) and Heat C1273-1 (0.14% Cu; 33, 33, 30, 30, 34, 35 ft-lb; 10% shear at +10 °F). Beltline welds were tested with CVNs at 10 °F or -20°F only. Lowest weld values are found for Heat 04P046/Lot D217A27A (0.06% Cu; 34, 36, 37, 39, 40 ft-lb; 20 and 30% shear at -20 °F). Heat C3L46C/Lot J020A27A (0.02% Cu; 35, 39, 40 ft-lb; 60% shear at +10 °F) and Heat 05P018/Lot D211A27A (0.09% Cu; 29, 30, 31, 36, 38 ft-lb; 30 and 40% shear at -20 °F). Because of the preceding relatively low test temperatures and Cu contents, it is anticipated that end-of-life upper shelf CVN values would

be in excess of 50 ft-lb. IV.C Requirements for Annealing when RTndt >200 N/A V.A Requirements for Material Surveillance Program See Table 5.3-8 V.B Conditions for Continued Operation Yes Requirements for continued operations are covered in Technical Specifications and the Reactor Pressure Vessel Surveillance Program document (WPPSS-ENT-089, Reference 5.3.4-1). See Section 5.3.1.6 for description of the Materials Surveillance Program. V.C Alternative if V.B Cannot be Satisfied N/A The Surveillance Program demonstrates compliance with Appendix G, Section IV. See Section 5.3.1.6 for description of the Materials Surveillance Program.

Table 5.3-1 10 CFR 50 Appendix G Matr ix for (Continued) Appendix G Paragraph Topic ComplyYes/No or N/A Alternative Actions or Comments COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORTNovember 1998 5.3-22V.D Requirement for RPV Thermal Annealing if V.C Cannot be Met N/A V.E Reporting Requirements for V.C and V.D N/A REFERENCES

1. Letter MFN-414-77 from G. G. Sherwood, G E, to Edson G. Case, NRC, dated October 17, 1977.

2. Letter from Robert B. Minoque, NRC, to G. G. Sherwood, GE, dated February 14, 1978.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-2 Plate Material Cross Reference Heat Slab 5.3-23 Ring 21 PCMK 21-1-1 C1272 1 PCMK 21-1-2 C1273 1 PCMK 21-1-3 C1273 2 PCMK 21-1-4 C1272 2 Ring 22 PCMK 22-1-1 B5301 1 PCMK 22-1-2 C1336 1 PCMK 22-1-3 C1337 1 PCMK 22-1-4 C1337 2 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-3

Weld Mate rial Cross Reference

Weld Identification Type Heat Lot 5.3-24 AB - Girthweld E8018NM 492L4871 A422B27AF RAC01NMM 5P6756 0342 RAC01NMM 3P4955 0342 E8018NM 04T931 A423B27AG Ring 21 BA E8018NM 04P046 D217A27A E8018NM 07L669 K004 A27A RAC01NMM 3P4966 1214 BB E8018NM 04P046 D217A27A E8018NM 07L669 K004 A27A E8018NM C3L46C J020A27A RAC01NMM 3P4966 1214 E8018NM 08M365 G128 A27A BC E8018NM 09L853 A111 A27A E8018NM C3L46C J020A27A RAC01NMM 3P4966 1214 BD E8018NM C3L46C J020A27A

RAC01NMM 3P4966 1214 E8018NM 04P046 D217A27A

E8018NM C3L46C J020A27A Ring 22 BE RAC01NMM 3P4966 1214 BF E8018NM 04P046 D217A27A E8018NM 05P018 D211A27A

RAC01NM 3P4966 1214 BG E8018NM 624063 C228A27A E8018NM 624039 D224A27A RAC01NMM 3P4966 1214 BH E8018NM 04P096 D217A27A E8018NM 624039 D205A27A RAC01NMM 3P4966 1214 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-4 Plate Material Charpy Impact ft-lb @ +1 0F Charpy Expansion MLE Drop Weight NDT (F) RTNDT (F) 5.3-25 Ring 21 PCMK 21-1-1

Heat C1272-1 34, 26, 30/31, 34, 30 30, 34, 24/27, 26, 32 10 28 PCMK 21-1-2

Heat C1273-1 33, 33, 30/30, 34, 35 30, 31, 27/26, 34, 32 20 20 PCMK 21-1-3

Heat C1273-2 38, 48, 55/66, 61, 71 44, 39, 34/53, 52, 56 30 4 PCMK 21-1-4

Heat C1272-2 40, 42, 44/51, 55, 50 32, 36, 38/41, 44, 42 30 0 Ring 22 PCMK 22-1-1

Heat B5301-1 64, 62, 66/52, 52, 55 56, 56, 56/45, 44, 44 30 20 PCMK 22-1-2

Heat C1336-1 70, 72, 71/60, 44, 66 59, 60, 62/56, 41, 51 30 8 PCMK 22-1-3

Heat C1337-1 71, 76, 74/70, 72, 55 61, 60, 60/63, 61, 52 30 20 PCMK 22-1-4

Heat C1337-2 62, 72, 82/73, 67, 73 51, 61, 66/52, 59, 61 50 20

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature (°F) RTNDT(°F) LDCN-04-005 5.3-26 Girth Weld AB E8018NM/492L4871 Lot A422B27AF 78, 82, 105, 93, 81 55, 60, 72, 74, 60 20a 50 RAC01NMM/5P6756 b Lot 0342 76, 79, 77, 80, 72 64, 72, 55, 69, 60 +10 50 RAC01NMM/5P6756 c Lot 0342 76, 79, 77, 80, 72 64, 72, 55, 69, 60 +10 50 RAC01NMM/3P4955 b Lot 0342 49, 63, 47, 49, 64 39, 48, 36, 43, 57 +10 20 RAC01NMM/3P4955 c Lot 0342 52, 37, 45, 55, 33 44, 30, 43, 50, 32 +10 16 E8018NM/04T931 Lot A423B27AG 86, 84, 102, 63, 61 69, 58, 60, 57, 70 20 50 Ring 21BA E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 E8018NM/07L669 Lot K004A27A 50, 50, 54 44, 44, 46 +10a 50 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10a -48 Ring 21BB E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 E8018NM/07L669 Lot K004A27A 50, 50, 54 44, 44, 46 +10a 50 E8018NM/C3L46C Lot J020827A 35, 39, 40 34, 39, 39 +10a 20 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material (Continued) Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature (°F) RTNDT(°F) LDCN-04-005 5.3-27 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10a 48 E8018NM/08M365 Lot G128A27A 49, 50, 51 38, 40, 43 +10a 48 Ring 21BC E8018NM/09L853 Lot A111A27A 78, 78, 79 60, 62, 62 +10a 50 E8018NM/C3L46C Lot J020A27A 35, 39, 40 34, 39, 39 +10a 20 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10a 48 Ring 21BD E8018NM/C3L46C Lot J020A27A 35, 39, 40 34, 39, 39 +10a 20 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10a 48 E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 Ring 22BE RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material (Continued) Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature (°F) RTNDT(°F) LDCN-04-005 5.3-28 Ring 22BF E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 E8018NM/05P018 Lot D211A27A 29, 30, 31, 36, 38 26, 26, 31, 33, 35 20a 38 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 Ring 22BG E8018NM/624063 Lot C228A27A 37, 40, 51, 57, 70 33, 34, 41, 47, 55 20a 50 E8018NM/624039 Lot D224A27A 28, 33, 34, 36, 42 29, 32, 33, 34, 42 20a 36 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 Ring 22BH E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 E8018NM/624039 Lot D205A27A 41, 44, 49, 54, 58 32, 36, 40, 41, 45 20a 50 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 a Drop weight NDT not applicable. b Tandem wire process. c Single wire process.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-6 Vessel Beltline Plate Plate P Cu C Mn Si S Ni Mo V LDCN-04-005 5.3-29 C1272-1 0.013 0.15 0.23 1.31 0.26 0.02 0.60 0.55 -- C1272-2 0.013 0.15 0.23 1.31 0.26 0.02 0.60 0.55 -- C1273-1 0.014 0.14 0.23 1.28 0.23 0.0180.60 0.57 -- C1273-2 0.014 0.14 0.23 1.28 0.23 0.0180.60 0.57 -- B5301-1 0.017 0.13 0.20 1.34 0.23 0.0140.50 0.52 -- C1336-1 0.017 0.13 0.21 1.36 0.22 0.0130.50 0.49 -- C1337-1 0.018 0.15 0.22 1.32 0.21 0.0130.51 0.50 -- C1337-2 0.018 0.15 0.22 1.32 0.21 0.0130.51 0.50 -- Peak I.D. EOL (33.1 EF PY) fluence = 7.41 x 10 17 n/cm2. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 Table 5.3-7 Vessel Beltline Weld Material Chemistry a Weld Heat/Control Cu C Mn Si S Ni Mo V P LDCN-08-023 5.3-30 492L4871b 0.03 0.07 1.17 0.32 0.02 0.98 0.51 0.02 0.02 5P6756/0342 c 5P6756/0342 d 0.08f 0.08f 0.063 0.078 1.27 1.24 0.57 0.53 0.011 0.012 0.936f0.936f 0.45 0.46 0.006 0.006 0.01 0.01 3P4955/0342 d 3P4955/0342 c 0.027f 0.027f 0.035 0.054 1.33 1.28 0.56 0.55 0.011 0.010 0.921f0.921f 0.52 0.54 0.006 0.007 0.016 0.01604T931b 0.03 0.05 1.03 0.28 0.024 1.00 0.53 0.01 0.02 04P046b 0.06 0.044 1.04 0.40 0.021 0.90 0.58 0.02 0.009 07L996b 0.03 0.05 1.24 0.48 0.016 1.02 0.54 -- 0.014 3P4966/3481 d 3P4966/3481 c 0.025f 0.025f 0.074 0.067 1.38 1.39 0.36 0.38 0.013 0.014 0.913f0.913f 0.49 0.53 0.006 0.008 0.010 0.0113P4966/3482 c 3P4966/3482 d 0.025f 0.025f 0.059 0.077 1.35 1.42 0.38 0.41 0.013 0.013 0.913f0.913f 0.50 0.53 0.005 0.005 0.013 0.014CL46Cb 0.02 0.063 0.96 0.32 0.017 0.87 0.53 -- 0.01908M365b 0.02 0.057 1.23 0.47 0.023 1.10 0.57 -- 0.02 09L853b 0.03 0.052 1.23 0.46 0.023 0.86 0.51 -- 0.018 05P018b 0.09 0.057 1.21 0.44 0.021 0.90 0.53 0.01 0.008 624063b 0.03 0.041 1.12 0.41 0.018 1.00 0.54 0.01 0.009 624039b,e 0.07 0.060 1.11 0.45 0.025 1.01 0.57 0.02 0.015 624039b,e 0.10 0.041 1.12 0.45 0.02 0.92 0.53 0.01 0.01 a As deposited. b M = Manual Welding Process c S = Single Wire Process d T = Tandem Wire Process e Different lot numbers f GE Nuclear Energy, "Pressure-Temperature Curves for Energy Northwest Columbia," NEDC-33144-P (CVI CAL 1012-00,3), Table 4-6b.

Table 5.3-8 10 CFR 50 Appendix H Matrix Appendix H Paragraph Topic ComplyYes/No or N/A Alternative Actions or Comments I Introduction N/A II.A Fluence 10 17n/cm2 Yes CGS Plant-specific RPV Surveillance Program is replaced by the

BWRVIP ISP. See Section 5.3.1.6. II.B Standards Requirements (ASTM) for Surveillance

No Plant-specific Surveillance Program: Noncompliance with ASTM E185-73 in that the surveillance specimens are not necessarily from the limiting beltline material. Specimens are from actual beltline material, however, and can be used to predict behavior of the limiting material. Heat and heat/lot numbers for surveillance specimens were supplied. See Section 5.3.1.6. II.C.1 Surveillance Specimen Shall be Taken for Locations Alongside the Fracture Test Specimens

(Section III.B of Appendix G)

No Plant-specific Surveillance Program: Noncompliance in that specimens may not have necessarily been taken from alongside specimens required by Section III of Appendix G and transverse CVNs may not be employed. However, representative materials have been used, and

RTNDT shift appears to be independent of specimen orientation. See Section 5.3.1.6. II.C.2 Locations of Surveillance Capsules in RPV

Yes Code basis is used for attachment of brackets to vessel cladding.

II.C.3.a Withdrawal Schedule of Capsules, RTNDT <100°F N/A See Section 5.3.1.6. Starting RT NDT of limiting material is based on alternative action (see paragraph III.A of Appendix G). II.C.3.b Withdrawal Schedule of Capsules, RTNDT <200°F N/A II.C.3.c Withdrawal Schedule of Capsules, RTNDT >200°F N/A COLUMBIA GENERATING STATION Amendment59 FINAL SAFETY ANALYSIS REPORTDecember 2007LDCN-06-000 5.3-31 Table 5.3-8 10 CFR 50 Appendix H Ma trix (Continued) Appendix H Paragraph Topic Comply Yes/No or N/A Alternative Actions or Comments

III.A Fracture Toughness Testing Requirements of

Specimens

Yes Requirements for postirradiation testing of surveillance material are addressed in the BWRVIP ISP implementation plan (Reference 5.3.4-2). III.B Method of Determining Adjusted Reference

Temperature for Base Metal, HAZ, and Weld Metal Yes Method of determining adjusted reference temperatures found in the BWRVIP ISP implementation plan (Reference 5.3.4-2). IV.A Reporting Requirements of Test Results

Yes Reporting requirements are discussed in the BWRVIP ISP implementation plan (Reference 5.3.4-2). IV.B Requirement for Dosimetry Measurement

Yes Dosimetry requirements are discussed in the BWRVIP ISP implementation plan (Reference 5.3.4-2). IV.C Reporting Requirements of Pressure/Temperature Limits Yes A discussion of the pressure/temperature limits and reporting requirements is found in the BWRVIP implementation plan (Reference 5.3.4-2). COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-13-009 5.3-32 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-9 Reactor Vessel Beltline Minimum Wall Thickness and Diameter LDCN-04-005, 04-033 5.3-33 Inside diameter with clad = 251 in. (minimum) Wall thickness (ring #22, lo wer intermediate shell) = 6.188 in. (minimum) Wall thickness (ring #2 1, lower shell) = 9.5 in. (minimum) Clad thickness = 0.1875 in. (nominal)

= 0.125 in. (minimum)

Refer to Figure 5.3-2 and CVI 02B13-06,2 Rev. 8 (VPF #3133-001-9) CBI Nuclear Company Drawing No. 1, Rev. 8, "Vessel Outline."

900547.42 Columbia Generating Station Final Safety Analysis Report Pressure Temperature Limits Testing Curve A (Inservice Leak and Hydrostatic Testing Curve)Draw. No.Rev.FigureAmendment 58 December 2005 5.3-1.1Form No. 960690FH LDCN-04-005 0 25 50 75 100 125 150 175 200MINIMUM REACTOR VESSEL METAL TEMPERATURE (F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig) 1035 PSIG 88.6°F800 PSIG68°F1035 PSIG117.1°FUPPER VESSELAND BELTLINE

LIMITSBOTTOM HEADCURVEACCEPTABLE AREA OFOPERATION TO THE RIGHT OF THIS CURVEBELTLINE CURVES ADJUSTED AS SHOWN:EFPY SHIFT (°F) 33.1 35INITIAL RTndt VALUES ARE28°F FOR BELTLINE, 34°F FOR UPPER VESSEL, AND34°F FOR BOTTOM HEADHEATUP/COOLDOWNRATE OF COOLANT FLANGEREGION80°FBOTTOMHEAD68°F910 PSIG110°F 14001300 120011001000900 800 700 600 500 400 300 200 1000 990578.74 Columbia Generating StationFinal Safety Analysis ReportPressure Temperature Limits Curve B(Non-Nuclear Heating and Cooldown Curve)Draw. No.Rev.FigureAmendment 58December 2005 5.3-1.2Form No. 960690FH LDCN-04-005 0100200300400 500600 700800 9001000110012001300 14000 25 5075 100125 150 175200225250MINIMUM REACTOR VESSEL METAL TEM PERATURE(F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig)UPPER VESSELAND BELTLINELIMITSBOTTOM HEADCURVEBELTLINE CUR VES ADJUSTED AS S HOWN: EFPY SHIFT (F)33.1 35HEATUP/COOLDOWNRATE OF COOLANT< 100F/HRBOTTOMHEAD 68FFLANGEREGION 80FACCEPTABLE AREA OF OPERATION TO THERIGHT OF THIS CURVE600 PSIG68F790 PSIG140FINITIAL RT ndt VALUES ARE 28F FOR BELTLINE,34F FOR UPPER VESSEL, AND34F FOR BOTTOM HEAD1035 PSIG148.1F1035 PSIG109.3F 0 25 50 75 100 125 150 175 200 225 250 275 300 900547.43 Columbia Generating Station Final Safety Analysis Report Pressure Temperature Limits Curve C(Nuclear Heating and Cooldown Curve)Draw. No.Rev.FigureAmendment 58 December 2005 5.3-1.3Form No. 960690FH LDCN-04-005MINIMUM REACTOR VESSEL METAL TEMPERATURE (F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig) 1035 PSIG 188.1F14001300 120011001000900 800 700 600 500 400 300 200 1000BELTLINE ANDNON-BELTLINELIMITSBELTLINE CURVE ADJUSTED AS SHOWN: EFPY SHIFT (F)33.1 35INITIAL RT ndt VALUESARE28F FOR BELTLI NE, 34F FOR UPPERVESSEL, AND34F FOR BOTTOM HEAD HEATUP/C OOLDOWN RATE OF C OOLANT < 100F/HRACCEPTABLE AREA OF OPERATION TO THERIGHT OF THIS CURVE790 PSIG180F60 PSIGMinimum CriticalityTemperature 80F312 PSIG Amendment 57December 2003 910402.30 5.3-2FigureForm No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis ReportVessel Beltline Plate and Weld Seam Identification LDCN-02-064 PCMK 22-1-4 Heat C1337

Slab 2Weld "BG"Weld "BF" PCMK 22-1-2

Heat C1336

Slab 1Weld "BE"Girth Weld "AB"Weld "BH" PCMK 21-1-2

Heat C1273

Slab 1Weld "BC"Weld "BB" PCMK 21-1-3

Heat C1273

Slab 2Weld "BA"Weld "BD" PCMK 21-1-1

Heat C1272

Slab 1PCMK 21-1-4

Heat C1272

Slab 2PCMK 22-1-3 Heat C1337

Slab 1PCMK 22-1-1

Heat B5301

Slab 1251" dia. Ring #22Ring #21405" Elev.360.31" TopCore Elev.230" Elev.99 13/16" Elev. 216.31" Bott.Core Elev. 0" Elevation EOL Limiting Plate

Nominal Reactor Vessel Water Level Trip and Alarm Elevation Settings 960690.53 5.3-3High Water Level Alarm, L7 = 568.0 in.Normal Water Level = 563.55 in.Low Water Level Alarm, L4 = 559.0 in. Recirc Outlet Nozzle = 172.5 in.Top of Active Fuel Zone = 366.31 in.Bottom of Active Fuel Zone = 216.31 in. Elevation 0.00 in. Recirc. Inlet Nozzle = 181.0 in.Low Water Level, L1 = 398.5 in. Steam Line Nozzle = 648.0 in.High Water LevelTrip, L8 = 582.0 in.Low Water Level Scram, L3 = 540.5 in. Feedwater Nozzle = 493.25 in.Low Water Level,

L2 = 477.5 in. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Bracket for Holding Surveillance Capsule 960690.54 5.3-4FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.-.00-C-11B.12Vessel Inside Clad Radius FullPenetration Weld (Typ.) -B-.25.25Typ.C.50 Total118.31-.25.06.621.38.06.06.062.00.75.752.00.06.061.18.622.00.06.06+.25+.12Columbia Generating StationFinal Safety Analysis Report Rev.FigureDraw. No. Form No. 960690 Amendment 53 November 1998 Columbia Generating Station Final Safety Analysis Report 020002.44 5.3-5Reactor Vessel Feedwater Nozzle 960690.56 5.3-6FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Nozzle, SA-508, CI.II Safe End, SB-166, Inconel Thermal Sleeve Extension, SB-166 Thermal Sleeve, SA-336, CI.F8 Inconel OverlayWeld Illustration Back-up Ring, SB-168 12345676 3/4"1453767/8"7/16"1 1/8"7 1/8"9/16"22 3/4"R3 9/16"R Feedwater Sparger 960690.57 5.3-72136"End BracketForged TeeTyp. for Weld Nozzle, SA-508, CI.IIForged Tee, 304S.S Sparger Header, 304S.S 123FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-1 5.4 COMPONENT AND SUBSYSTEM DESIGN Pumps and valves within the reactor coolant pressure boundary (RCPB) are described in Table 5.4-1. 5.4.1 REACTOR RECIRCULATION PUMPS

5.4.1.1 Safety Design Bases The reactor recirculation system (RRC) has been designed to meet the following safety design bases: a. An adequate fuel barrier thermal margin shall be ensured during postulated transients,

b. A failure of piping inte grity shall not compromise the ability of the reactor vessel internals to provide a refloodable volume, and

c. The system shall mainta in pressure integrity duri ng adverse combinations of loadings and forces occurring during a bnormal, accident, and special event conditions.

5.4.1.2 Power Gene ration Design Bases

The RRC meets the following power generation design bases:

a. The system shall provide sufficient flow to remove heat from the fuel, and

b. System design shall minimize maintenance situations that would require core disassembly and fuel removal.

5.4.1.3 Description

The RRC consists of the two r ecirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reacto r vessel jet pumps (see Figure 5.4-1 ). Each external loop contains one hi gh-capacity variable-s peed motor-driven recirculation pump. The motor is powered by an adjustable speed driv e (ASD). The external loop also contains two motor-operated gate valves (for pump maintenance). Each pump

suction line contains a flow meas uring system. The recirculati on loops are part of the RCPB and are located inside the drywell structure. The jet pumps are reactor vessel internals. Their location and mechanical desi gn are discussed in Section 3.9.5. The important design and performance characteristics of the RRC is shown in Table 5.4-2 . COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-10-010 5.4-2 The head, flow, torque, net pos itive suction head (NPSH), BHP, and efficiency curves are shown in Figures 5.4-2 , 5.4-3, and 5.4-4. Instrumentation and cont rol description is provided in Sections 7.6 and 7.7. The recirculation system pi ping and normally flooded secti on of the reactor vessel is periodically coated with a micros copic layer of noble metals. Th is coating serv es to create a catalytic layering of the noble me tal platinum to reduce the hydr ogen addition injection rate required to achieve a low electrochemical corrosion potential (ECP). The low ECP achieves intergranular stress corrosion cr acking (IGSCC) and irradiation assisted stress corrosion cracking (IASCC) protection while minimizing the effects of high dose rates attributed to regular hydrogen injection rates.

The recirculated coolant consists of saturated water from the steam separators and dryers that have been subcooled by incoming feedwater. This water passes down the annulus between the reactor vessel wall and the core shroud. A po rtion of the coolant flows from the vessel, through the two external recirc ulation loops, and beco mes the driving flow for the jet pumps. Each of the two external recirc ulation loops discharg es high pressure flow into an external manifold from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remain ing portion of the coolant mixtur e in the annulus provides the driven flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the driving flow. The flows, both driving and driven, are mixed in the jet pump throat section and result in partial pressure recovery. The balance of recovery is obtained in the jet pump diffusing suction (see Figure 5.4-5 ). The adequacy of the to tal flow to the core is discussed in Section 4.4. The allowable heatup rate for the recirculation pump casing is the same as the reactor vessel. If one loop is shut down, the id le loop can be kept hot by leav ing the loop valves open; this permits the reactor pressure plus the active jet pump head to cause reverse flow in the idle loop. When starting the pump in an idle recirc ulation loop with the other loop in operation, the operating loop flow will be verified to be less than 50% of rated loop flow within 15 minutes prior to pump start.

Because the removal of the reactor recirculation gate valve in ternals would re quire unloading the core, the objective of the valve trim design is to minimize the need for maintenance of the valve internals. The valves are provided with high quality backseats that permit renewal of stem packing while the system is full of water.

The 20-in. motor-operated gate valves provide pump and flow control valve (FCV) isolation during maintenance. The suction valve is capable of closing w ith up to 50 psi differential, while the discharge valve can clos e with up to 400 psi differential. Both valves are remote manually operated.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-3 The FCV is blocked open (seized in the full open position). This condition does not affect the pressure integrity or impact the transient duty cycle of the valve or allow the ball to break away from the shaft.

The required NPSH for the recirculation pumps and jet pumps is supplied by the subcooling provided by the feedwater flow. Accurate temperature detectors are provided in the recirculation lines. Steam dome temperature is provided through pressu re conversion. The difference between these two readings is a di rect measurement of the subcooling. If the subcooling falls below the time-delayed setpoint 10.7°F, the ASD system is reduced to minimum frequency 15 Hz (25% pump speed) on both of the RRC loops. Each loop has independent instrumentati on for cavitation protection.

When preparing for hydrostatic te sts, the nuclear system temperat ure must be raised above the vessel nil ductility transition (NDT) temperature lim it. The vessel is heat ed by core decay heat and/or by operating th e recirculation pumps.

Connections to the piping on the suction and discharge sides of the pumps provide a means to

flush and decontaminate the pum p and adjacent piping. The pi ping low point dr ain, designed for the connection of temporar y piping, is used during fl ushing or decontamination.

Each recirculation pump is driven by an adjustable speed motor and is equipped with a two-stage mechanical seal cart ridge. Each of the two seals in the package is subject to one-half the total pressure being sealed. Each seal is structurally capable of sealing full pressure for limited periods of operation. The two seals can be replaced without removing the motor from the pump. The pump shaft passes through a breakdown bushing in the pump casing to reduce leakage in the event of a gross failure of both shaft seals. The cavity temperature and pressure drop across each individual seal can be monitored.

Each recirculation pump motor is a vertical, solid-shaft, totally enclosed, air-water-cooled, induction motor. The combined rotating inertias of the recirculation pump and motor provide a slow coastdown of flow following loss of ASD-supplied power to the drive motors so that they are adequately cooled during the transient. This inertia requirement is met without a flywheel.

The ASD can vary the discharge flow of the pump proportionally to a reactor operator remote manually adjusted demand signal. The RRC GE-FANUC digital control scheme is described in Sections 7.6 and 7.7. The recirculation loop flow rate can be varied, within the expected flow range, in response to changes to system demand.

The design objective for the recirculation system equipment is to provide units that will not require removal from the system for rework or overhaul. Pump casing and valve bodies are designed for a 40-year life and are welded to the pipe.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-041 5.4-4 The pump drive motor, impeller, and wear rings ar e designed for as long a life as is practical. Pump mechanical seal parts and the valve packing have life expectancies which afford convenient replacement during the refueling outages.

The ASD system selected to drive the recirculation pump induction motor is a dual channel system. Two ASDs are provided, capable of 11,200 hp at 66 Hz per RRC loop. If one channel fails, the RRC loop flow capability must be reduced to the capability of a single channel ASD. The dual channel ASD system provides for high ava ilability of the ASD system. The ASD system is a solid-state frequency converter with overall high availability. Sections 7.6 and 7.7 provide more detail of the system design.

The recirculation system piping is designed and constructed to meet the requirements of the applicable ASME and ANSI codes.

The RRC pressure boundary equipment is designe d as Seismic Category I equipment. The pump is assumed to be filled w ith water for the analysis. Vibr ation snubbers located at the top of the motor and at the bottom of the pump casing are designed to resist the horizontal reactions.

The recirculation piping, valves, and pumps ar e supported by hangers to avoid the use of piping expansion loops th at would be required if the pumps were anchored. In addition, the recirculation loops are provided with a system of restraints designed so that reaction forces associated with any split or ci rcumferential break do not jeopard ize drywell integrity. This restraint system provides adequate clearance for normal therma l expansion movement of the loop. The criteria for the protection agai nst the dynamic effects associated with a loss-of-coolant accident (LOCA ) are contained in Section 3.6. The recirculation system piping, valves, and pump casings are c overed with thermal insulation having a total maximum heat tr ansfer rate of 65 Btu/hr-ft 2 with the system at rated operating conditions. This heat loss includes losses through joints, laps , and other openings that may occur in normal application.

The insulation is primarily the al l-metal reflective type. It is prefabricated into components for field installation. Removable insulation is provided at various locations to permit periodic inspection of the equipment. The residual heat removal (RHR) system can use the recirculation loop jet pumps to provide circulation through the reactor core. Operating restrictions limit RHR operation to regions where jet pump cavitation does not occur.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-5 5.4.1.3.1 Recirculation Syst em Cavitation Consideration Cavitation Coefficients

The recirculation pump, jet pump, and FCV were tested to determine their cavitation coefficients so that prolonged operati on in cavitating regime s can be avoided.

Equipment Damage Provisions Cavitation interlocks are provided for the recirculation pum p and jet pumps; since cavitation produces material damage afte r long-term operation and the damage potential decreases with an increase in water temperature, short periods of cavitation during a transient or accident are not a concern. However, long-te rm operation that might occur is of sufficient concern to call for inspections during the next refueling outage. Consequently , to avoid the need for such inspections, automatic interlocks are installed. Class 1E equipment is not necessary for power generation design requirements, so the automatic interlocks are non-Class 1E.

The consequences of cavitation would require inspection of the affected compone nt and repair or replacement if the inspection showed unacceptable damage. Consequently, cavitation could call for increased scheduled outag e time for inspection/repair aff ecting plant availability power generation design goals.

The ASD and its GE-FANUC digital control syst em is a non-safety-related system. The ASD and control system have alar m and protective systems and ar e provided with on-line video diagnostic displays at the main control room ope rating benchboard.

5.4.1.4 Safety Evaluation

Reactor recirculation system malfunctions that pose threats of damage to the fuel barrier are described and eval uated in Section 15.3. It is shown in Section 15.3 that none of the malfunctions result in significan t fuel damage. The RRC has sufficient flow coastdown characteristics to maintain fuel thermal margins during ab normal operational transients.

The core flooding capability of a jet pump design plant is discussed in detail in the emergency core cooling system (ECCS) docum ent submitted to the NRC (Reference 5.4-1). The ability to reflood the boiling water reactor (BWR) core to the top of the jet pumps is shown schematically in Figure 5.4-6 and is discussed in Reference 5.4-1.

Piping and pump design pressures for the RRC are based on peak steam pressure in the reactor dome, appropriate pump head allowances, and the elevation head above the lowest point in the recirculation loop. Piping and related equipment pressure part s are chosen in accordance with applicable codes. Use of the listed code design criteria ensure s that a system designed, built,

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-6 and operated within design limits has an extrem ely low probability of failure caused by any known failure mechanism.

Purchase specifications require that the recirculation pumps first critical speed shall not be less than 130% of operating speed. Calculation submittal was requi red and approved.

Purchase specifications require that integrity of the pum p case be maintained through all transients and that the pump remain operable through all normal and upset transients. The design of the motor bearings are required to be such that dynamic load capability at rated operating conditions is not exceed ed during the safe shutdown ear thquake (SSE). Calculation submittal was required of the vendor and has been received and approved by GE.

Pump overspeed occurs during the course of a LOCA due to blowdown through the broken loop's pump. Design studies determined that the overspeed was not sufficient to cause destruction of the motor; c onsequently no pump overspeed protection provision was made.

A failure modes effects analysis (FMEA) was performed on the bl ock valves. In addition, an analysis was made to determine the effect of block valve closure on recirculation pump coastdown. The analysis postulates that coincident with a recirculation pump trip, the block valves begin to close. It was concluded that any closure time greater than 1 minute will have no effect on coastdown times. The consequences of an in advertent closure without a coincident pump trip is covered in the FMEA.

5.4.1.5 Inspection and Testing

Quality control methods we re used during fabrication and asse mbly of the RRC to ensure that design specifications were met. Inspection and testing is carried out as described in Chapter 3 . The reactor coolant system was thoroughly cl eaned and flushed before fuel was loaded initially.

During the preoperational test program, the RR C was hydrostatically tested at 125% reactor vessel design pressure. Preoperational tests on the RRC also included checking operation of the pumps, flow control system, and gate valves, and are discussed in Chapter 14 . During the startup test program, horizontal and vertical motions of the RRC piping and equipment were observed as described in Section 5.4.14. 5.4.2 STEAM GENERATORS (Pressurized Water Reactor)

This is not applicab le to BWR plants.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-7 5.4.3 REACTOR COOLANT PIPING

The RCPB piping is di scussed in Sections 3.9.3.1 and 5.4.1. The recirculation loops are shown in Figures 5.4-1 and 5.4-7. The design characteristics are presented in Table 5.4-2 . Avoidance of stress corrosion crack ing is discussed in Section 5.2.3. 5.4.4 MAIN STEAM LINE FLOW RESTRICTORS

5.4.4.1 Safety Design Bases

The main steam line flow restrictors were designed to

a. Limit the rate of vessel blowdown to 200 percent of the normal rated flow in the event of a steam line break outside c ontainment. This limits the reactor depressurization rate to a value which will ensure that the steam dryer and other reactor internal struct ures remain in place.

b. Withstand the maximum pressure difference expected across the restrictor, following complete severan ce of a main steam line,

c. Limit the amount of radiological releas e outside of the drywell prior to main steam isolation valve (MSIV) closure, and

d. Provide trip signals for MSIV closure.

5.4.4.2 Description

A main steam line flow restrictor (see Figure 5.4-8 ) is provided for each of the four main steam lines. The restrictor is a complete assembly welded into the main steam line. It is located between the last main steam line safety/relief valve (SRV) and the inboard MSIV.

The restrictor limits the coolant blowdown rate from the reactor vessel in the event a main steam line break occurs outside the containment. The restrict or assembly consists of a venturi-type nozzle insert welded, in accordance with applicable code requirements, into the main steam line. The flow rest rictor is designed and fabricated in accordance with the ASME "Fluid Meters," 6th edition, 1977.

The flow restrictor has no moving parts. Its mechanical structure can withstand the velocities and forces associated with a main steam line break. The ma ximum differential pressure is conservatively assumed to be 1375 psi, the reactor vessel ASME Code limit pressure.

The ratio of venturi throat diameter to steam line inside diameter of approximately 0.55 results in a maximum pressure different ial (unrecovered pressure) of a bout 10 psig at 100% of rated

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009 5.4-8 flow. This design limits the steam flow in a severed line to le ss than 200% rated flow, yet it results in negligible increase in steam moisture content during normal operation. The restrictor is also used to measure steam flow to initiate closure of the MSIVs when the steam flow exceeds preselected operational limits.

5.4.4.3 Safety Evaluation

A postulated guillotine break of one of the four main steam lines outside the containment results in mass loss from both ends of the break. The flow from the upst ream side is initially limited by the flow restrictor upstream of the inboard isolation valve. Flow from the downstream side is initially limited by the total area of the flow restrictors in the three unbroken lines. Subsequent closur e of the MSIVs further limits the flow when the valve area becomes less than the limiter area and finally terminates the mass loss when full closure is reached.

Analysis of the main steam break accident outside containment demonstrates that the radioactive materials released to the environs results in calculated doses that are in compliance with 10 CFR 50.67 and Regulat ory Guide 1.183 dose limits.

Tests on a scale model determined final design and performance characteristics of the flow restrictor. The characteristics include maximum flow rate of the restrictor corresponding to the accident conditions, unrecoverable losses under normal plant ope rating conditions, and discharge moisture level. The te sts showed that flow restriction at critical throat velocities is stable and predictable.

The steam flow restrictor is exposed to steam of 0.10% to 0.20% moisture flowing at velocities approximately 150 ft/sec (steam piping I.D.) to 600 ft /sec (steam restrictor throat). The cast austenitic stainless steel (ASME SA351, or ASTM A351, Type CF8) was selected for the steam flow restrictor material because it has excellent resistance to erosion-corrosion in a high velocity steam atmosphere. The excellent performance of st ainless steel in high velocity steam appears to be due to its resistance to corrosion. A protective surface film forms on the stainless steel which prevents any surface attack and this film is not removed by the steam.

Hardness has no significant effect on erosion-corrosion. For example, hardened carbon steel or alloy steel will erode rapidl y in applications where soft stainless steel is unaffected.

Surface finish has a minor effect on erosion-corro sion. Experience shows that a machined or a ground surface is sufficiently smooth and th at no detrimental erosion will occur.

5.4.4.4 Inspection and Testing

Because the flow restrictor fo rms a permanent part of the ma in steam line piping and has no moving components, no test ing program is planned. Only ve ry slow erosion will occur with

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009 5.4-9 time, and such a slight enlargement will have no sa fety significance. Stainless steel resistance to corrosion has been substantiated by turbine inspections at the Dresden Unit 1 facility, which have revealed no noticeable effects from erosion on the stainless steel nozzle partitions. The Dresden inlet velocities are about 300 ft/sec an d the exit velocities ar e 600 to 900 ft/sec. However, calculations show that, even if the erosion rates are as high as 0.004 in. per year, after 40 years of operation the increase in restrictor choked flow rate would not exceed 5%. The impact on calculated accident radiological releases would be minimal.

5.4.5 MAIN STEAM LINE ISOLATION SYSTEM The MSIV leakage control system has been deactivated.

5.4.5.1 Safety Design Bases

The MSIVs, individually or collectively, shall

a. Close the main steam li nes within the time establis hed by design-basis accident analysis to limit the release of reactor coolant,

b. Close the main steam line s slowly enough that simultaneous closure of all steam lines will not induce transients that exceed the nuclear system design limits,

c. Close the main steam line when required despite single failure in either valve or in the associated controls, to provide a high level of reliability for the safety

function,

d. Use separate energy sources as the motive force to clos e independently the redundant isolation valves in the individual steam lines,

e. Use local stored energy (compressed air and/or spri ngs) to close at least one isolation valve in each steam pipe line without relying on the continuity of any variety of electrical power to furnish the motive force to achieve closure,

f. Have capability to close the steam lines, either during or after seismic loadings, to ensure isolation if the nuclear system is breached, and

g. Have capability for testing during no rmal operating conditions to demonstrate that the valves will function.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-10 5.4.5.2 Description Two isolation valves are welded in a horizontal run of each of the four main steam pipes; one valve is as close as possible to the inside of the drywell a nd the other is just outside the primary containment.

Figure 5.4-9 shows an MSIV. Each is a 26-in. Y-patte rn, globe valve. Ra ted steam flow rate through each valve is 3.85 x 10 6 lb/hr. The main disc or poppet is attached to the lower end of the stem. Normal steam flow tends to close the valve, and higher inlet pressure tends to hold the valve closed. The bottom end of the valve stem closes a small pressure balancing hole in the poppet. When the hole is open, it acts as a pilot valve to relieve differential pressure forces on the poppet. Valve stem travel is suff icient to give flow ar eas past the wide open poppet approximately equal to the seat port area. The poppet travels approximately 90% of the valve stem travel to close the main disc and approximately the last 10% of travel to close the pilot hole. The air cylinder can open the poppet with a maximum differential pressure of

200 psi across the isolation valv e in a direction that tends to hold the valve closed.

A 45-degree angle permits the inlet and outlet passages to be streamlined; this minimizes pressure drop during normal steam flow and help s prevent debris blockage. The pressure drop at 105% of rated flow is 7 psi maximum. Th e valve stem penetrates the valve bonnet through a stuffing box that has Grafoil packing. To help prevent leakage through the stem packing, the poppet backseats when th e valve is fully open.

Attached to the upper end of the stem is an air cylinder that ope ns and closes the valve and a hydraulic dashpot that controls its speed. The speed is adjusted by a valve in the hydraulic return line bypassing the dashpot piston. Valve closing time is adjustable to between 3 and 10 sec.

The air cylinder is supported on the valve bonnet by actuator suppor t and spring guide shafts. Helical springs around the spring guide shafts maintain the valve in the closed position if air pressure is not available.

The valve is operated by pneuma tic pressure and by the action of compressed springs. The control unit is attached to the air cylinder. This unit contains three types of control valves that open and close the main valve and exercise it at slow speed. Remote manual switches in the control room enable the opera tor to operate the valves.

Operating air is supplied to the outboard valves from the plant air system and to the inboard valves from the containment instrument system (nitrogen). An air accumulator between the control valve and a check valve provides bac kup operating air. The outboard MSIVs will close on spring force or air cylinder pressure; the inboard valves require spring force and air pressure to close.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-11 Each valve is designed to acco mmodate saturated steam at plant operating conditions, with a moisture content of approxi mately 0.25%, an oxygen content of 30 ppm, and a hydrogen content of 4 ppm. The valves are furnished in conformance with a design pressure and temperature rating in excess of plant operati ng conditions to accommodate plant overpressure conditions.

In the worst case if the main steam line should rupture down stream of the valve, steam flow would quickly increase to 200% of rated flow. Further increase is prevented by the venturi flow restrictor inside the containment. During approximately the first 75% of closing, the valve has little effect on flow reduction because the flow is choked by the venturi restrictor. After the valve is approximately 75% closed, flow is reduced as a function of the valve area versus travel characteristic.

The design objective for the valve is a minimum of 40-years service at the specified operating conditions. Operating cycles (excluding routine exercise cycles) are estimate d to be 100 cycles per year during the first year a nd 50 cycles per year thereafter.

In addition to minimum wall thic kness required by applicable code s, a corrosion allowance of 0.120-in. minimum is added to provide for 40 years of service.

Design specification ambient conditions for normal plant operation are 135°F normal temperature, 150°F maximum temperature, 100% hum idity, in a radiation field of 15 rad/hr gamma and 25 rad/hr neutron plus gamma, conti nuous for design life. The inside valves are not continuously exposed to maximum conditions, particularly during reactor shutdown, and valves outside the primary containment and sh ielding are in ambien t conditions that are considerably less severe.

The MSIVs are designed to close under accident environmental conditions of 340°F for 1 hr at drywell design pressure. In addition, they ar e designed to remain cl osed under the following postaccident environment conditions:

a. 340°F for an additional 2 hr at drywell design pressure of 45 psig maximum,

b. 320°F for an additional 3 hr at 45 psig maximum, c. 250°F for an additional 24 hr at 25 psig maximum, and d. 200°F during the next 1 00 days at 20 psig maximum.

To resist sufficiently the response motion from the SSE, the main steam line valve installations are designed as Seismic Categor y I equipment. The valve a ssembly is manufactured to withstand the SSE forces applied at the mass center of the exte nded mass of the valve operator, assuming the cylinder/spring opera tor is cantilevered from th e valve body and the valve is located in a horizontal run of pipe. The stre sses caused by horizontal and vertical seismic forces are assumed to act simu ltaneously. The stresses in the actuator supports caused by

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-12 seismic loads are combined with the stresses caused by other live and dead loads, including the operating loads. The allowable stress for this combination of loads is based on the allowable stress set forth in applicable codes. The parts of the MSIVs that constitute a process fluid pressure boundary are designed, fabricated, inspected, and tested as required by the ASME Code Section III.

5.4.5.3 Safety Evaluation

The analysis of a comp lete, sudden steam line break outside the containment is described in Chapter 15, "Accident Analyses." The shortest cl osing time (approximately 3 sec) of the MSIVs is also shown in Chapter 15 , to be satisfactory. The switches on the valves initiate reactor scram when specific conditions (extent of valve closure, number of pipe lines included, and reactor power level) are exceeded (see Section 7.2.1.1). The ability of this 45-degree, Y-design globe valv e to close in a few sec onds after a steam line break, under conditions of high pressure differentials and flui d flows with fluid mixtures ranging from mostly steam to mostly water, ha s been demonstrated in a series of dynamic tests. A full-size, 20-in. valve was tested in a range of steam-water blowdown conditions simulating postulated accident conditions (Reference 5.4-2). The following specified hydrosta tic, leakage, and stroking te sts, as a minimum, were performed by the valve ma nufacturer in shop tests:

a. To verify valve capability to close at settings between 3 and 10 sec,

• each valve was tested at rated pres sure (1000 psig) and no flow

. The valve was stroked several times, and the closing time recorded. The valve was closed by spring only and by the combination of air cylinder and springs. The closing time is slightly greater when closure is by springs only;

b. Leakage was measured with the valve seated and backseated. The specified maximum seat leakage, using cold water at design pressure, was 2 cm 3/hr/in. of nominal valve size. In addition, an ai r seat leakage test was conducted using 50 psi pressure upstream. Maximum permissible leakage was 0.1 scfh/in. of nominal valve size. There was no visible leakage from the stem packing at hydrostatic test pressure. The valv e stem was operated a minimum of three times from the closed position to the open position, and the packing leakage was zero by visual examination;

• Response time for full closure is set prior to plant operati on for 3 sec minimum, 5 sec maximum.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-13 c. Each valve was hydrostatic ally tested in accordance w ith the requirements of the applicable edition and adde nda of the ASME Code. During valve fabrication, extensive nondestructive test s and examinations were conducted. Tests included radiographic, liquid penetran t, or magnetic particle examinations of castings, forgings, welds, hardfacings, and bolts; and

d. The spring guides and guiding of the sp ring seat member on support shafts and rigid attachment of the seat member ensure correct alignment of the actuating components. Binding of the valve poppet in the internal guides is prevented by making the poppet in the form of a cyli nder longer than its diameter and by applying stem force near the bottom of the poppet.

After the valves were installed in the nuclear system, each valve was test ed as discussed in Chapter 14 .

Two isolation valves provide redundancy in each steam line so either can perform the isolation function, and either can be tested for leakage after the other is closed. The inside valve, the outside valve, and their respective c ontrol systems are separated physically.

Electrical equipment that is a ssociated with the isolation valv es and operates in an accident environment is limited to the wiring, solenoi d valves, and position switches on the isolation valves. The expected pressure and temperature transients following an accident are discussed in Chapter 15 .

5.4.5.4 Inspection and Testing

The MSIVs can be functionally tested for ope rability during plant ope ration and refueling outage. The test provisions are listed below. During refu eling outage the MSIVs can be functionally tested, leak tested, and visually inspected.

The MSIVs can be tested and exercised indivi dually to the 90% open position, because the valves still pass rated steam flow when 90% open.

The MSIVs can also be tested and exercised indi vidually to the fully closed position if reactor power is reduced sufficiently to avoid scram fr om reactor overpressure or high flow through the steam line flow restrictors.

Leakage from the valv e stem packing will become suspect during reactor operation from measurements of leakage into th e drywell, or from observation or similar measurements in the steam tunnel.

The leak rate through the pipe line valve seats (pilot and poppet seats) can be measured accurately during shutdown by the pro cedure described in the following:

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-14 a. With the reactor at approximately 125°F and normal water level and decay heat being removed by the RHR system in th e shutdown cooling mode, all MSIVs are closed utilizing both spring force and air pressure on the operating cylinder;

b. Air from the instrument air system is introduced between the isolation valves at 25 to 26 psig. A pressure decay test or an air makeup test is used to determine combined inboard and outboard isolation valve seat leakage;

c. If combined inboard and outboard isol ation valve seat leakage is above the allowed leakage for a single isolation valve, the outboard isolation valve is then tested for seat leakage;

d. To leak-test the outboard isolation valves, the reactor vessel side of the inboard valves is pressurized to approximately the same pressure as the test pressure between the inboard and outboard valves using nitrogen gas or a hydrostatic head. A pressure decay or makeup leak test is then performed on the area between the isolation valves. This ensures essentially zero leakage through the inboard valves with test results indicating outboard va lve seat leakage. The volume between the closed valves is accurately known. Corrections for temperature variation during the test period are made to obtain the required

accuracy; and

e. At each refueling outage, the MSIVs are slow closed to verify the stem packing is not too tight. Also, the inboard MS IV containment instrument air (CIA) supply pressure boundary from the accumu lator check valve to the actuator is verified to not exceed the allowable leak rate.

Such a test and leakage measurement program ensure that the valves are operating correctly and that any leakage trend is detected.

During prestartup tests following an extensive shutdown, the valves will receive the same pressure boundary leakage or hydro tests (approximately 1000 psi) that are imposed in the primary system.

5.4.6 REACTOR CORE ISOLATION COOLING SYSTEM

5.4.6.1 Design Bases

The reactor core isolation cooling (RCIC) system initiates the discharge of a specified constant flow into the reactor vessel over a specified pressure range with in a 30-sec time interval. The RCIC water discharge into the reactor vessel varies between a temperature of 40°F up to and

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-030 5.4-15 including a temperature of 140°F. The mixture of the RCIC water and the hot steam does the following:

a. Quenches the steam,

b. Removes reactor residual heat by reducing the heat level (enthalpy) due to the temperature differential between the steam and water, and

c. Replenishes reactor vessel inventory.

The RCIC system uses an elec trical power source of high reliability, which permits operation with either onsite power or offsite power.

The steam supply to the RCIC tu rbine is automatically isolat ed on detection of abnormal conditions in the RCIC system or in RCIC equipment areas. See Section 7.4.1.1.2 . The RCIC system is neither an ECCS nor an engineered safety feature (ESF) system; however, it is included in these sections because of its similar functions. No credit (simulation) is taken in the accident analysis of Chapter 6 or 15 for its operation. However, the system is designed to initiate during plant transients that cause low reactor water level. The design bases with respect to General Design Criteria 34, 55, 56, and 57 are provided in Chapter 3 . Reactor core isolation cooling containmen t isolation valve arrangement s are described in Section 6.2. The RCIC system as noted in Table 3.2-1 is designed commensura te with the safety importance of the system and its equipment. Each componen t was individually tested to confirm compliance with system requirements. The system as a whole was tested during both the startup and preoperational phases of the plant to set a base mark for system reliability. To confirm that the system maintains this mark, functional and operability testing is performed at predetermined intervals throu ghout the life of the plant.

In addition to the automatic operational fe atures, provisions have been included for remote-manual startup, operation, and shutdown of the RCIC system, provided initiation or shutdown signals have not been act uated for startup and operation.

The RCIC system is physically located in a different quadrant of the reactor building and uses different divisional power (and se parate electrical routings) than the HPCS system. The system operates for the time intervals and the environmen tal conditions specified in Section 3.11.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-16 5.4.6.2 System Design 5.4.6.2.1 General

5.4.6.2.1.1 Description. The RCIC system consists of a turbine, pump, piping, valves, accessories, and instrumentation designed to ensure that sufficient reactor water inventory is maintained in the reactor vessel to permit adequate core cooling. This prevents reactor fuel overheating should the vessel be isolated and accompanied by loss-of-coolant flow from the reactor feedwater system. Following a reactor shutdown, steam generation will continue at a reduced rate due to the core fission product decay heat. At this time the turbine bypass system will di vert the steam to the main condenser, and the feedwater system will supply the make up water required to maintain reactor vessel inventory.

In the event the reac tor vessel is isolated and the feedwater supply is un available, relief valves are provided to automatically (or remote manually) maintain vessel pressure within desirable limits. The water level in the reactor vessel will drop due to conti nued steam generation by decay heat.

On reaching a predetermined low level, the RCIC system is initiated automatically. The RCIC turbine is driven with a portion of the decay heat steam from th e reactor and exhausts to the suppression pool. The turbine-driven pump take s suction from the condensate storage tank

(CST) during normal modes of ope ration and injects into the reactor vessel. Condensate storage tank freeze protecti on is discussed in Section 9.2.6. Since the CST is a covered tank, the water supply is not affect ed by dust storms. If the water supply from the CST becomes exhausted there is an automatic switchover to the suppression pool as the water source for the RCIC pump. This automatic sw itchover feature for RCIC cons ists of two Class 1E level switches mounted on a standpipe in the pump suc tion line. This standpi pe is located on the condensate supply line inside the reactor build ing at the reactor building/service building interface.

The standpipe is open ended and is used to indicate either a low water level condition in the CST or a loss-of-suction supply from the CST. The standpipe is desi gned, fabricated, and installed to Seismic Category I, Quality Class I, and ASME Se ction III, Class 2 standards.

The piping from the reactor building/service build ing interface to the RCIC system is Seismic Category I; each circumferential buttweld has been radiographically examined per ASME Section III, NC-5230, and a chemic al analysis has been performe d on all piping materials and as-deposited weld materials.

The inline suction reserve from the CST has sufficient volume to maintain the minimum required NPSH for the RCIC pump plus an ap proximate four-ft margin while the switchover

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-04-029 5.4-17 occurs, thus ensuring a water supply for continuous operation of the RC IC system. The CST

switchover level of 448 ft 3 in. pr ovides an additional submergen ce of 2 ft (above the top of the CST outlet pipe), which is more than ade quate to preclude vortex formation in the CST since less than 6 in. of add itional submergence for vortex pr evention is required for RCIC.

The available NPSH for worst-case operating conditions (i.e., 625 gpm rated flow, maximum water temperature) was calcula ted for the RCIC pump suction from the suppression pool and the CST. Using the conservative water temperat ure of 140°F, the NPSH available from the suppression pool is approximately 60 ft. For the CST, using 100°F water, the NPSH available is 48 ft. In both cases, the NPSH available is greater than the required NPSH of 20 ft indicated in Figure 5.4-10 for the RCIC turbine high speed setpoint of 4500 rpm.

The RCIC suction line from the su ppression pool has also been eval uated for vortex formation. The RCIC system has adequate NPSH and will not vortex unde r the conditions it would be expected to operate.

During RCIC operation, the s uppression pool acts as the heat sink for steam generated by reactor decay heat. This will re sult in a rise in pool water temp erature. Heat exchangers in the RHR system are used to ma intain pool water temperature within acceptable limits by cooling the pool water directly.

The RCIC turbine discharges in to a 10-in. exhaust pipe (see Figure 5.4-11 ), which has been installed as a sparger to prev ent flow-induced oscillations due to steam bubble formation and collapse in the suppression pool. Also, a vacuum breaker system has b een installed close to the RCIC turbine exhaust line suppression pool penetr ation to avoid siph oning water from the suppression pool into the exhaust line as steam in the line conde nses during and after turbine operation. The vacuum breaker line runs from the suppression pool air volume to the RCIC exhaust line through two norma lly open motor-operate d gate valves a nd two swing check valves arranged to allow air flow into the exhaust line and to precl ude steam flow to the suppression pool air volume. Condensate buildup in the turbine exhaust line is removed by a drain pot in the low point of the line near the turb ine exhaust connection. The condensate collected in the drain pot drains to the barometric condenser.

5.4.6.2.1.2 Diagrams. The following diagrams are included for the RCIC systems:

a. A schematic "Piping and Instrumentation Diagram" (

Figures 5.4-11 ) shows all components, piping, points where interfa ce system and subsys tems tie together and instrumentation and controls associated with subsystem and component actuation,

b. A schematic "Process Diagram" (

Figure 5.4-12) shows temperature, pressures, and flows for RCIC operation and system process data hydrau lic requirements, and COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-18 c. RCIC turbine and pump performance curves; Constant Pump Flow Figure 5.4-10 and Constant Pump Speed Figure 5.4-13 . 5.4.6.2.1.3 Interlocks . The following defines the various electrical interlocks:

a. There are four key-locked valves, RCIC-V-63 (F063), RCIC-V-8 (F008), RCIC-V-68 (F068), and RCIC-V-69 (F069

), and two key-locked resets, the "isolation resets;"

b. RCIC-V-31 (F031) limit switch acti vates when fully open and closes RCIC-V-10 (F010), RCIC-V-22 (F022), and RCIC-V-59 (F059);

c. RCIC-V-68 (F068) limit switch activate s when fully open and clears RCIC-V-45 (F045) permissive so RC IC-V-45 (F045) can open;

d. RCIC-V-45 (F045) limit switch activate s when RCIC-V-45 (F045) is not fully closed and energizes 15-sec time delay fo r low pump suction pressure trip and also initiates startup ramp function. This ramp resets each time RCIC-V-45 (F045) is closed;

e. RCIC-V-45 (F045) limits switch activates when fully closed and permits RCIC-V-4 (F004), RCIC-V-5 (F005), RCIC-V-25 (F025), and RCIC-V-26

(F026) to open and closes RCIC-V-13 (F013), RCIC-V-46 (F046) and RCIC-V-19 (F019). RCIC-V-13 (F013) and RCIC-V-46 (F046) auto open on initiation signal if RCIC-V-45 (F045) and RCIC-V-1 (F001) are open;

f. The turbine trip throttle valve RCIC-V-1 limit switch activates when fully closed and closes RCIC-V-13 (F013), RCIC-V-46 (F046) and RCIC-V-19 (F019);

g. The combined pressure switches at reactor low pressure and high drywell pressure when activated closes RCIC-V-110 a nd 113 (F080 and F086);

h. RCIC high turbine exhaust pressure, low pump suction pressure, low discharge header pressure, or an isolation signal actuates and closes the turbine trip throttle valve. When signal is cleared, the trip throttle valve must be reset from control room;

i. 125% overspeed trips both th e mechanical trip at the tu rbine and the trip throttle valve. The former is reset at the turbine and then the la ter is reset in the control room; COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-19 j. Valves RCIC-V-8 (F008), RCIC-V-63 (F063), and RCIC-V-76 (F076) automatically isolate on low reactor pressure, high turbine e xhaust line pressure, high ambient temperature in RCIC equipment areas (leak de tection) and high turbine steam supply flow rate (>300% - break detection). A setpoint of 300%

for break isolation provides sufficient operating margin to prevent inadvertent isolations due to startup tr ansients and yet is low e nough to detect large pipe breaks. Small breaks are detected by the leak detection system. Steam condensing supply valv e RCIC-V-64 (F064) has been lo ck closed as a part of the steam condensing mode deactivation. Note, the key-lo cked switches for RCIC-V-8 (F008) and RCIC-V-63 (F063) do not prevent automatic isolation of these valves. The key-locked switche s are provided to prevent inadvertent manual isolation of the RCIC steam supply during system operation;

k. An initiation signal opens RCIC-V-10 (F010) if closed, RCIC-V-45 (F045), and RCIC-V-46 (F046) if RCIC-V-1 and RC IC-V-45 (F045) are not closed. The initiation signal also starts barometric condenser vacuum pump; and closes RCIC-V-22 (F022) and RCIC

-V-59 (F059) if open;

l. The combined signal of low flow plus high discharge pressure opens and with increased flow closes RCIC-V-19 (F 019). Also see items e and f above;

m. The signal of in-line reserve tank low water level opens valve RCIC-V-31 (F031);

n. High reactor water level closes RCIC-V-45 (F045); and

o. Main turbine trips if RCIC

-V-13 and RCIC-V-45 are open.

5.4.6.2.2 Equipment and Component Description

5.4.6.2.2.1 Design Conditions . Operating parameters for the components of the RCIC systems defined in the following are shown in Figure 5.4-12 .

a. One 100% capacity tu rbine and accessories,

b. One 100% capacity pump a ssembly and accessories, and

c. Piping, valves, a nd instrumentation for

1. Steam supply to the turbine,

2. Turbine exhaust to the suppression pool,

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-20 3. Makeup supply from the CST to the pump suction,

4. Makeup supply from the suppre ssion pool to the pump suction, and

5. Pump discharge to the head cooling spray nozzle, incl uding a test line to the CST, a minimum flow bypass line to the suppression pool, and a coolant water supply to accessory equipment.

5.4.6.2.2.2 De sign Parameters. Design parameter for the RCIC system components are listed below. See Figure 5.4-11 for cross reference of com ponent numbers listed below:

a. RCIC pump operation RCIC-P-1 (C001) (Reference to Figures 5.4-11 and 5.4-13) Flow rate Injection flow - 600 gpm Lube oil cooling water flow 25 gpm

Total pump discharge - 625 gpm

(includes no margin for pump wear) Water temperature range 40°F to 140°F NPSH 21 ft minimum Developed head 3016 ft @ 1225 psia reactor pressure 610 ft @ 165 psia reactor pressure BHP, not to exceed 761 HP @ 3016 ft developed head 130 HP @ 610 ft developed head Design pressure 1500 psia Design temperature 40°F to 140°F

b. RCIC turbine operation RCIC-DT-1 (C002)

HP condition LP condition Reactor pressure (saturation temperature) 1225 psia 165 psia Steam inlet pressure 1210 psia 150 psia Turbine exhaust press 15 to 25 psia 15 to 25 psia Design inlet pressure 1265 ps ia + saturated temperature Design exhaust pressure 165 ps ia + saturated temperature

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-21 c. RCIC orifice sizing Coolant loop orifice Sized with piping arrangement to ensure RCIC-RO-9 (D009) maximum pressure of 75 psia at the lube oil cooler inlet and a minimum pressure of 45 psia at the spray nozzles at the barometric condenser

Minimum flow orifice Sized with piping arrangement to ensure RCIC-RO-5 (D005) minimum flow of 100 gpm with RCIC-V-19 (MO-F019) fully open

Test return orifice Sized with piping arrangement to simulate RCIC-RO-6 (D006) pump discharge pressure required when the RCIC system is injecting design flow with the reactor vessel pressure at 165 psia

Leak-off orifices Sized for 1/8-in. diameter minimum, RCIC-RO-8 and RCIC-RO-10 3/16-in. diameter maximum (D008 and D010)

Minimum flow orifice Sized to maintain a minimum flow of RCIC-RO-11 (D011) 60 gpm thro ugh the RCIC water leg pump (RCIC-P-3) while maintaining a positive pressure in the RCIC system at the highest elevation

d. Valve operation requirements NOTE: Differential pressures listed in the following were obtained from the RCIC system design specification data sheet and are listed for information. Detailed differential pressure requi rements are contained in engineering calculations.

Steam supply valve Open and/or close against full steam RCIC-V-45 (F045) pressure Pump discharge valve Open and/or close against full pump RCIC-V-13 (F013) discharge pre ssure and open in thermal over-pressure conditions in the RCIC

discharge header

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-22 Pump minimum flow bypass Open and/or close against full pump valve RCIC-V-19 (F019) discharge pressure

Steam supply isolation valves Open and/or close against full differential RCIC-V-08/RCIC-V-63 (F008) pressure of 1210 psi Turbine lube oil/cooling Capa ble of maintain ing constant water pressure control downs tream pressure of 75 psia valve RCIC-PCV-15 (F015) through lube oil cooler Pump discharge header relief 1500 ps ig relief setting; less than 1 gpm valve (RCIC-RV-3) required capacity; the maximum allowable discharge is less than 20 gpm

Pump suction relief valve 122 psig relief setting; 20 gpm required RCIC-RV-17 (F017) capacity

Cooling water relief Sized to prevent overpressurization of valve (RCIC-RV-19T) piping valves and equipment in the turbine lube oil coolant loop in the event of failure of pressure control valve RCIC-PCV-15 (F015). Set pressure is 99 psig; required flow is 33.1 gpm

Pump test return valve Qualifie d to open, close, and throttle RCIC-V-22 (F022) against full pump discharge pressure

Pump test return valve Qualified to close (not open) against full RCIC-V-59 (F059) pump discharge pressure

Relief valve barometric Relief valve is capable of retaining condenser vacuum tank 10 in. of mercury vacuum at 140 °F RCIC-RV-33 (F033) ambient, with a set pressure of 6 psig; required flow is 20 gpm Pump suction valve Located as close as practical to the suppression pool primary containment RCIC-V-31 (F031)

Pump suction valve Open and/or close against full suction condensate storage head from the condensate storage tank tank RCIC-V-10 (F010)

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-23 Main pump discharge System test mode bypasses this valve. check valve Its functional capability is demonstrated RCIC-V-65/RCIC-V-66 separately (F065/F066)

Warm-up line Valve will open and/or close against full isolation valve steam pressure

RCIC-V-76 (F076)

Vacuum breaker isolation Valves will open and/or close against valves RCIC-V-110 (F080) tu rbine exhaust pressure and RCIC-V-113 (F086)

e. Rupture disc

Assemblies Utilized for tu rbine casing protection, RCIC-RD-1/RCIC-RD-2 includes a mated vacuum support to (D001/D002) prevent rupture disc reversing under

vacuum conditions

Rupture pressure 150 psig +/- 10 psig Flow capacity 60,000 lb/hr @ 165 psig

f. Condensate storage requirements

Total reserve storage for reactor pr essure valve make up is 135,000 gal.

g. Piping RCIC water temperature

The maximum water temperature range fo r continuous system operation will not exceed 140°F. However, due to poten tial short-term operation at higher temperatures, piping de sign is based on 170°F.

h. Turbine exhaust vertical reaction force Unbalanced pressure due to opening and discharge under the suppression pool water level is 20 psi.

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-11-039 5.4-24 i. Ambient conditions Relative Temperature Humidity Normal plant operations 60F to 100°F 95% Isolation conditions 148°F 100%

j. Water leg pump Design pressure 150 psig Design temperature 212°F Capacity 25 gpm @ 200 ft total head

k. Barometric condenser Design pressure 50 psig Design temperature 650°F

l. Vacuum tank Design pressure 15 psig Design temperature 212°F

m. Condensate pump Design pressure 50 psig Design temperature 650°F Capacity 23 gpm @ 10 in. Hg vac., 70°F 50 psig discharge

n. Turbine and steam supply drain pots Design pressure 1250 psig Design temperature 575°F

o. Turbine governing a nd trip throttle valves Design pressure 1250 psig Design temperature 575°F

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-056 5.4-25 p. Pump suction strainers in the suppression pool The suction strainers have been procured to the following specifications: Primary service rating: ANSI 1501-1

Quality Class I

Seismic Category I

Cleanliness Class B

Applicable Code: Strainer materi als and fabrication meets ASME Section III, Class 2 requi rements. The "N" stamp is not be applied sin ce the strainers cannot be hydrostatically tested. Materials: Strainer body is stainless steel 304 or 316, or engineer approved equal, suitable for submergence in high quality water during a 40-year lifetime. Quantity: 2

Diameter: 13.5 in.

Length: 5.25 in.

Rated flow: 300 gpm (per strainer)

The strainers are cyli ndrical, as shown in Figure 5.4-14 . Strainer hole diameter is 0.09375 in. Strainers are attached to ANSI 150# RF Flanges.

Head loss is limited to 4 ft of water assuming the strainers are 50% clogged and the water

temperature is 220°F. 5.4.6.2.2.3 Overpressure Protection . Referring to Figure 5.4-11, four RCIC pipe lines have a low design pressure and, ther efore, require relief devices or some other basis for addressing overpressure protection.

The design pressure of the other major pipe lin es is equal to the vessel design pressure and subject to the normal overpressure protection syst em. In addition, the RCIC discharge header

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-056 5.4-26 has a relief valve, RCIC-RV-3, to protect against thermal overpressurization when the system is in standby mode, isolated from the reactor. Below are the overpressure protection ba ses for the low pressure piping lines.

a. RCIC pump suction line

A relief valve [RCIC-RV-17 (F017)] is located on the pump suction line in Figure 5.4-11 to accommodate any potential leakage through the isolation valves [RCIC-V-13 (F013) and RCIC-V-66 (F066)]. A high pump suction pressure alarm is provided in the control room.

b. RCIC turbine exhaust line

This line is normally vented to the suppression pool and is not subject to reactor pressure during normal operation. Rupture discs RCIC-RD-1 (D001) and RCIC-RD-2 (D002), as shown in Figure 5.4-11, are installed on this line to prevent exceeding piping design pressure should the exhaust line isolation valve RCIC-V-68 (F068) be closed when the RC IC turbine is operating. The RCIC system will automatically isolate if the rupture discs were to blow open.

c. Portions of the RCIC minimum flow line downstream of RCIC-V-19 (F019)

This line is normally vent ed to the suppression pool and is separated from reactor pressure by the pump discharge isolation valves [RCIC-V-13, RCIC-V-65, and RCIC-V-66 (F013, F065, and F066)], pump discharge check valve RCIC-V-90, and one additional nor mally closed isolation valve in the minimum flow line [RCIC-V-19 (F019)] as shown in Figure 5.4-11 .

d. Portions of the RCIC cooling water line downstr eam of RCIC-PCV-15 (F015)

In the standby condition this line is separated from r eactor pressure by the pump discharge valves [RCIC-V-13, RCIC-V -65, and RCIC-V-66 (F013, F065 and F066)], pump discharge check valve RCIC-V-90, and one additional normally closed shut-off valve in the cooling water line [RCIC-V-46 (F046)] as shown in Figure 5.4-11 . During system operation a reli ef valve [RCIC-RV-19T (F018)] is provided to prevent overpressurizing piping, valves, and equipment in the coolant loop in the event of failure of pressure control valve RCIC-PCV-15 (F015) as shown in Figure 5.4-11 . COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-04-027 5.4-27 5.4.6.2.3 Applicable C odes and Classifications

The RCIC system components within the drywell up to and including the outer isolation valve are designed in accordance with ASME Code Section III, Class 1, Nuclear Power Plant Components. Safety-related portions of the RCIC system are Seismic Category 1.

The RCIC system component classifications a nd those for the condensat e storage system are given in Table 3.2-1 . 5.4.6.2.4 System Reliability Considerations

To ensure that the RCIC will operate when necess ary, the power supply for the system is taken from immediately available energy sources of hi gh reliability. Added assurance is given by the capability for periodic testing during station operation. Evaluation of reliability of the instrumentation for the RCIC shows that no failure of a single initiating sensor either prevents or falsely star ts the system.

To ensure RCIC availability for the operational events noted previously, the following are considered in the system design.

a. The RCIC and HPCS are located in differe nt quadrants of the reactor building.

Piping runs are separated and the water delivered from each system enters the reactor vessel via different nozzles.

b. Prime mover independence is achieved by using a steam turbine to drive the RCIC and an electric motor-driven pump for the HPCS system.

c. The RCIC and HPCS control independence is secured by using different battery systems to provide control power to each system for sy stem operation. Separate detection initiation logic is used for each system.

d. Both systems are designed to meet a ppropriate safety and quality class requirements. Environment in the equipment rooms is maintained by separate auxiliary systems.

e. A design flow functional test of the RCIC is performed during plant operation by taking suction from the CST and discharg ing through the full flow test return line back to the CST.

The discharge valve to the head-spray line remains closed during the test, and reactor operation is undisturbed. All components of the RCIC system are capable of individual functional testing during normal plant operation. Control system design provides automatic return from test to

operating mode if system initiation is required. The three exceptions are as follows: COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-04-027 5.4-28 1. The auto/manual station on the flow controller. This feature is required for operator flexibility during system operation.

2. Steam inboard/outboard isolation valves. Closur e of either or both of these valves requires operator action to properly sequence their opening. An alarm sounds when either of th ese valves leaves the fully open position.

3. Bypassed or other delib erately rendered inoperabl e parts of the system are automatically indicated in the control room.

f. Periodic inspections and maintenance of the turbine-pump unit are conducted in accordance with manufacturer's instructions. Valve position indication and instrumentation alarms are displayed in the control room.

g. Specific operating procedures relieve the possibility of thermal shock or water hammer to the steam line, valve seals, and discs. Key lock switches are provided for positive administrative control of valve position. Operating procedures require throttling open the outboard isolation valve RCIC-V-8 to

remove any condensate tra pped between the isolation valves, warming up the steam line by throttling open the warmup valve RCIC-V-76 located on a pipe line bypassing the inboard isolation va lve, and then opening the inboard isolation valve RCIC-V-63. All the condensate is removed from the steam supply line by a drain pot located at the lowest point. An alarm sounds when any of these valves leaves the fully open position.

h. Emergency procedures address the opera tion of RCIC during a station blackout (SBO) event. The RCIC keepfill pump, RCIC-P-3, is powered by a Class 1E ac source, and will be unavailable during an SBO. Upon loss of ac power, the operator manually initiates RCIC. RCIC may be used during an SBO event by maintaining the RCIC discharge header continuously pressurized. The system can be operated in th is manner without its keepfill function.

5.4.6.2.5 System Operation 5.4.6.2.5.1 Auto matic Operation . Automatic startup or restart (after level 8 shutdown) of the RCIC system due to an initiation signal from reactor low water level requires no operator action. To permit this automa tic operation, Technical Specifications operability requirements ensure that all necessary components are available to perfor m their required functions. In addition, the following are periodically verified:

a. The flow controller has the correct flow setpoint and is in automatic mode; COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-030 5.4-29 b. Each RCIC manual, power-operated, and automatic valv e in the flow path that is not locked, sealed, or otherwise secure d in position, is in the correct position; and

c. The RCIC system piping is filled with water from the pump discharge valve to the injection valve.

The turbine is equipped with a mechanical overspeed trip. The mechanical overspeed trip must be reset out of the control room at the turbine itself. Once the mechanical overspeed trip is reset, the trip throttle valve can be reset.

RCIC System Operation and Shutdown:

During extended periods of opera tion and when the normal water level is again reached, the HPCS system may be manually tripped and the RCIC system flow controller may be adjusted

and switched to manual operation. This prevents unnecessary cycling of the two systems. The RCIC flow to the vessel is controlled by adjus ting flow to the amount necessary to maintain vessel level. Subsequent starts of RCIC will occur automatically if the water leve l decreases to the low level initiation point (Le vel 2) following a high level shutdown (Level 8). Should RCIC flow be inadequate, HPCS flow will automatically initiate.

RCIC flow may be directed away from the vessel by diverting the pump discharge to the CST.

This is accomplished by closi ng injection valve RCIC -V-13 and opening the test return valves (RCIC-V-22 and 59). The system is returned to injection mode by closing RCIC-V-59 or RCIC-V-22 and then opening RCIC-V-13. This mode of operation w ill not be used during events where an unacceptable source term is identified in primary containment. Diverting RCIC flow to the CST is not a safety-related function nor does it affect the ability of RCIC to initiate during plant transients. The system automatically switc hes to injection mode if the water level decreases to the low level initiation point (Level 2).

When RCIC operation is no longer required, the RCIC system is manually tripped and returned to standby conditions.

5.4.6.2.5.2 Test Loop Oper ation. This operating mode (described in Section 5.4.6.2.4 ) is conducted by manual oper ation of the system.

5.4.6.2.5.3 Steam Condensing (Hot Standby) Operation. Th e steam condensing mode of RHR for Columbia Generating Station has been deactivated. However, the major pieces of equipment are installed with the exception of the steam supp ly relief valves and are shown on the RCIC and RHR piping and instrumentation diagrams (P&IDs) ( Figures 5.4-11 and 5.4-15, respectively). Deletion of this mode of operation for RCIC and RHR will not adversely affect either system's capability to bring the reactor to cold shutdown.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-000 5.4-30 5.4.6.2.5.4 Manual Actions. The RCIC system w ill automatically initiate and inj ect into the reactor when the reactor water level drops to a low level (L2, -50 in.). No manual actions are required to operate the system. However, control room oper ators can manually initiate the system prior to reaching the low level.

5.4.6.2.5.5 Reactor Core Isolati on Cooling Discharge Line Fill System . See Section 6.3.2.2.5. The description in this section is also applicable to the RCIC line fill system. 5.4.6.3 Performance Evaluation

The RCIC system makeup capacity is sufficient to avoid th e need for ECCS for normal shutdowns and shutdowns resulting from anticipated operational occurrences.

5.4.6.4 Preoperational Testing

The preoperational and initial startup test program for the RC IC system is presented in Chapter 14 . Regulatory Guide 1.68 complia nce is described in Section 1.8. 5.4.6.5 Safety Interfaces

The balance-of-plant/GE nuclear steam supply system safety inte rfaces for the RCIC system are (a) preferred water supply from the CST, (b) all associated wire, ca ble, piping, sensors, and valves that lie outside the nuclear steam supply system scope of supply, a nd (c) air supply for testable check and so lenoid-actuated valve(s).

5.4.7 RESIDUAL HEAT REMOVAL SYSTEM

5.4.7.1 Design Bases

The RHR system is comprised of three inde pendent loops. Each loop contains its own motor-driven pump, piping, valv es, instrumentation, and contro ls. Each loop has a suction source from the suppression pool an d is capable of disc harging water to the reactor vessel via a separate nozzle, or back to th e suppression pool via a se parate suppressi on pool return line. In addition, the A and B loops have heat exchange rs which are cooled by standby service water. Loops A and B can also take suction from the RRC suction and can discharge into the reactor recirculation discharge or to the suppression pool and drywell spray spargers. Spool-piece

interties are available to permit the RHR heat exchangers to be used to supplement the cooling capacity of the fuel pool coo ling (FPC) system (see Section 9.1.3 for details). A spool piece intertie was also used to provi de a preoperational flus hing path for the low-pressure core spray (LPCS). The A and B loops also have connections to the RCIC steam line. However, these are not used because the steam conde nsing mode has been eliminated.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009 5.4-31 5.4.7.1.1 Functional Design Basis

The RHR system is designed to restore and mainta in the coolant inventory in the reactor vessel and to provide primary system decay heat removal followi ng reactor shutdown for both normal and postaccident conditions. The primary desi gn operating modes associated with performing these functions are briefl y described as follows:

a. Low-pressure coolant injection (LPC I) mode - The RHR sy stem automatically initiates into this mode a nd pumps suppression pool water into separate lines and core flooder nozzles for injection into the core region of the reactor vessel following a LOCA. The system's LPCI mode operates in c onjunction with the other ECCS to provide ad equate core cooling fo r all design basis LOCA conditions.

The functional design bases for the LPCI mode is to pump a total of 7450 gpm of water per loop using the separate pump loops from the suppression pool into the core region of the vessel when there is a 26 psi differential between reactor pressure and the pressure of the suppression pool air volume. Injection flow commences at 225 psid vessel pressure above drywell pressure.

The initiating signals are ve ssel level 1, 32 in. above the active core or drywell pressure equal to 2.0 psig. The pumps will attain rated speed in 27 sec and injection valves fully open in 46 sec.

These original LPCI mode performance capabilities bound the power uprate conditions and ensure adequate core c ooling can be provided following a LOCA at uprated power conditions;

b. Suppression pool cooling (SPC) and containment spra y cooling (CSC) modes - The RHR system's SPC and CSC mode s provide heat removal from the suppression pool and containment by pumping suppression pool water through the system's heat exchangers and discharg ing the water either directly back to the suppression pool (i.e., in the SPC m ode) or discharging the water to the wetwell and drywell spray sp argers (i.e., in the CSC mode) where the water is then returned, by drainage, back to the suppression pool. These modes of operation are designed to provide cooling to maintain containment and suppression pool temperatures and pre ssures following ma jor transients. Suppression pool cooling is manually initiated by the ope rator; however, at least one RHR loop is placed in the SPC mode to maintain suppression pool temperature <

110°F. The drywell spray func tion removes radioactive fission products from the containment atmos phere during a LOCA and is manually initiated within 15 minutes after the event occurs; COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-32 c. Shutdown cooling mode - The RHR sy stem's normal shutdo wn cooling mode removes reactor core decay and sensible heat from the primary reactor system to permit refueling and servicing. This heat removal function is initiated manually after the reactor pressure has been reduced to less than 48 psig (295°F) by discharge of steam to the main condenser. This mode of operation provides the capability to cool down the reactor under controlled conditions with minimal availability impact. Refer to Section 5.4.7.3.1 for shutdown cooling time to reach 212°F;

d. Alternate shutdown cooling mode - The RHR system's alternate shutdown cooling mode is utilized during normal plant operation and design basis events when the normal shutdown c ooling mode is not availabl e to remove reactor core decay and sensible heat. This heat removal function is safety related, initiated manually and pumps suppressi on pool water into the co re and allows the water to return to the suppression pool through the SRVs. The design objective of this mode (as established by Re gulatory Guide 1.139) is to reach cold shutdown within 36 hrs and to meet the requirements of GDC 34;

e. Fuel pool cooling mode - During normal plant shutdown, when the reactor vessel head has been remove d, the RHR system is designed to be capable of being aligned to assist th e FPC and cleanup system in maintaining the fuel pool temperature within acceptable limits. In this mode the system is designed to cool water drawn from the fuel pool by passing it through an RHR system heat

exchanger and then discharge th e water back to the fuel pool;

f. Minimum flow bypass mode - The RHR system minimum flow bypass mode is designed to provide cooling for the RHR pumps during a small break LOCA that does not result in rapid reactor ve ssel depressurization to below the RHR system shutoff discharge pr essure. This mode cool s the pumps by providing a pump flow return line to the suppre ssion pool that allows sufficient pump cooling flow to return to the pool until flow in the main discharge line is sufficient to provide adequa te pump cooling. When fl ow in the main discharge lines is sufficient for cooling of the pumps, motor-operated valves in the

minimum flow bypass line to the suppressi on pool automatically close so that all of the system's flow is directed into the main discharge lines;

g. Standby mode - During normal power operation the RHR system is required to be available for the LPCI mode in the event a LOCA occurs. The system is normally maintained in the standby mode. In this mode the system is aligned with the pumps' suction from the suppre ssion pool and all othe r valves aligned so that only the injection valves are required to open and the RHR pumps started for LPCI flow to be delivered to the reactor fo llowing depressurization.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-33 Until adequate flow is esta blished, the RHR pumps are cooled automatically by flow through the minimum flow valves;

h. Reactor steam condensing mode - The reactor steam condens ing mode has been deactivated and will no longer be utilized for CGS. No credit has been taken for the steam condensing mode in any safety analysis; and

i. The potential for exceeding the 100°F/

hr cooldown limit during the cooldown mode is minimized by precautions and limitations in the appropriate operating procedures.

5.4.7.1.2 Design Basis for Isolation of Residual Heat Removal System from Reactor Coolant System

Interlocks are provided to inhi bit shutdown cooling mode alignment whenever reactor pressure is above the design pressure of the low pressu re portions of the RHR system (approximately 135 psig).

The low pressure portions of the RHR system are isolated from full reactor pressure whenever the primary system pressure is above the RHR system design pr essure. The minimum pressure above which LPCI protection is required is below the design pr essure of the low pressure portions of the RHR system. These interlocks also provide protection of the low pressure portions of the RHR system. These interlocks ca n be reset when pressure has been reduced to approximately 135 psig. The LPCI injection valves are interlocked to prevent opening when reactor pressure is above appr oximately 460 psig, which also pr ovides protection for the low pressure portions of the RHR system. In add ition, automatic isolation may occur for reasons of vessel water inventory retention which is unrelated to piping pressure ratings. See Section 5.2.5 for an explanation of the leak dete ction system and the isolation signals.

The RHR pumps are protected against damage from a closed discharge valve by means of automatic minimum flow valves, which open when the main line flow is low and close when the main line flow is greater than the setpoint specified in the Technical Specifications.

5.4.7.1.3 Design Basis for Pressure Relief Capacity The relief valves in the RHR system are sized for one or both of the following bases:

a. Thermal relief, b. Valve bypass leakage

Relief valves are set to ensure that the design pressure pl us 10% accumulation is not exceeded anywhere in the system being protected. A check valve, RHR-V-209, is installed across

RHR-V-9 to prevent thermal overpressuri zation between RHR-V-8 and RHR-V-9. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-34 The relief valves protecting the RHR system are listed below (see Figure 5.4-15 ): Relief Valve Nominal Setpoint (psig) Required Capacity (gpm) Piping Location Design Pressure (psig) RHR-RV-88A 205 1 RHR pump suction 220 (loop A) RHR-RV-88B 205 1 from suppression 220 (loop B) RHR-RV-88C 110 1 pool 125 (loop C) RHR-RV-5 183 1 RHR pump suction from recirculation pipe 220 RHR-RV-25A 487 1 RHR discharge 500

RHR-RV-25B 488 1 RHR discharge 500

RHR-RV-25C 493 1 RHR discharge 500 RHR-RV-30 103 1 RHR flush line to radwaste 125 RHR-RV-36

• All RHR relief valves are purchased to ASME S ection III, Class 2, requi rements to match the requirements of the piping they are protecting. As such, the setpoi nt tolerance is plus or minus 3% for setpoints above 70 psi per ASME Section III, Paragraph NC-7600.

Pressure buildups in isolated lines will be slow and discharges from relief valves on these lines will be small. Water hammer and other hydrodyna mic loads are not considered a potential problem in RHR relief valve piping.

Redundant interlocks prevent ope ning valves to the low-pressu re suction piping when the reactor pressure is above the shutdown range. These same interlocks initiate valve closure on increasing reactor pressure.

A pressure interlock prevents connecting the discharge piping to the primary system whenever the primary pressure is greater than the design value. In add ition a high-pressure check valve will close to prevent reverse fl ow if the pressure should increase. Relief valves in the discharge piping are sized to account for leakage past the check valve. The RHR cooling system is connected to hi gher pressure piping at (a) shutdown cooling suction, (b) shutdown cooling return, (c) LPCI injection, and (d) head spray. The vulnerability to overpressurization of each location is discussed in the following paragraphs:

• RHR-RV-36 has been permanently removed from Columbia Generating Station. It has been replaced with a blind-flanged "Testable Pipe Spool Assembly," RHR-TPSA-1.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-35 The shutdown cooling suction pipi ng has two gate valves (RHR-V -8 and RHR-V-9) in series which have independent pressure interlocks to prevent opening at high reactor pressure. No

single active failure or operator error will result in overpressuri zation of the lower pressure piping. With the RHR pumps normally lin ed up to the suppression pool (RHR-V-6A and RHR-V-6B closed), the shutdown cooling suction line is protected from thermal expansion or from leakage past RHR-V-8 by RHR-RV-5. A bypass around RHR-V-6A may also be used to route leakage past RHR-V-8 and RHR-V-9 to the suppression pool. With all the RHR suction

valves closed, the suction piping is protected from thermal expansion or leakage past the discharge check valves by RHR-RV-88A, RHR-RV-88B, and RHR-RV-88C. When the bypass around RHR-V-6A is not in service, it will be isolated usi ng a single valve. This will allow the installed relief valves discussed above to protect the bypass piping.

The shutdown cooling return line has swing check valves (RHR-V-50A and RHR-V-50B) to protect it from higher vessel pressures. Additionally, a gate valve (RHR-V-53A and RHR-V-53B) is located in series and has a pressure interlock to prevent opening at high reactor pressures. No single active fa ilure or operator error will result in overpressurization of the lower pressure piping.

Each LPCI injection line has a swing check valve (RHR-V-41A, RHR-V-41B, and RHR-V-41C) to protect it from higher vessel pressures. Additionally, a gate valve (RHR-V-42A, RHR-V-42B, and RHR-V-42C) is locate d in series and has pressure interlocks to prevent opening at high reactor vessel pressure. No single active failu re or operator error will result in overpressurization of the lower pressure piping.

The head spray piping ha s three swing check valv es in series [two belonging to the RCIC system and one (RHR-V-19) belonging to the RHR system], to protect it from higher vessel pressures. Two of the swing check valves ha ve air operators but ar e only capable of opening the testable check va lve if the differential pressure is less than 5.0 psid. Additionally, a globe valve (RHR-V-23) is located in series and has a pressure interlock to prevent opening at high reactor pressures. No single active failure or operator error will result in the overpressurization of the lower pressure piping.

Overpressurization protection of the RHR discharge piping for therma l expansion or from leakage past the head spray, shutdown injection, and LPCI isolation va lves is provided by RHR-RV-25A, RHR-RV-25B, and RHR-RV-25C.

The RHR drain system to radwaste is protected from thermal expansion or from leakage past the isolation valves RHR-V-71A, RHR-V-71B, RHR-V-71C, RHR-V-72A, RHR-V-72B, and RHR-V-72C by RHR-RV-30.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-36 5.4.7.1.4 Design Basis With Resp ect to General Design Criterion 5 The RHR system for this unit doe s not share equipment or struct ures with any other nuclear unit.

5.4.7.1.5 Design Basis for Reliability and Operability

The design basis for the shutdown cooling modes of the RHR system is that these modes are controlled by the operator from the control r oom. The operations performed outside of the control room using the normal shutdown is manual operation of a local flushing water admission valve, which is the means of ensuring that the suc tion line of the shutdown portions of the RHR system is filled and vented. In addition, the 0.75-in. bypass around RHR-V-6A would be isolated if necessary.

Two modes of operation provide the shutdown cooling function for the RHR system. One mode, the normal Shutdown Cooling Mode, is the preferred operational mode. Although preferred, this mode of RHR does not meet the redundancy and single fa ilure requirements of IEEE 279 and 10 CFR 50 Appendix A, GDC 34. As a result, a second shutdown cooling mode, the Alternate Shutdown Cooling Mode, is provided and is the shutdown cooling mode credited to meet the requirements of IEEE 279 a nd GDC 34. This mode is safety related, Quality Class 1, Seismic Cate gory 1, redundant and single failure proof. Since the normal Shutdown Cooling Mode of RHR is preferre d for CGS, the components required for the operation of this mode are maintained as safety related, Quality Class 1.

For the normal shutdown cooling mode, two separate shutdown cooling loops are provided. The reactor coolant temperature can be brought to 212°F in less than 36 hr with only one loop in operation. With the exception of the shutdown suction including the reactor recirculation loop suction and discharge valves, and shutdown return, the entir e RHR system is safety grade and redundant, is part of the ECCS and containment cooling syst ems, and is designed with the flooding protection, piping protection, power separation, etc., requi red of such systems. See

Section 6.3 for an explanation of the design bases for ECCS systems. Shutdown cooling suction and discharge valves are required to be powered from both offsite and standby emergency power for purposes of isolation and shutdown following a loss of offsite power. In the event that the outboard shutdown cooling suction supply valve (RHR-V-8) fails to open from the control room, an operator ma y be sent to open the valve by hand.

If the attempt to open the outboard valve proves unsuccessful, or the inboard shutdown cooling suction supply valve (RHR-V-9) fails to open, the operator will establish the alternate shutdown cooling mode path as described in the notes to Figure 15.2-10, Activity C1 or C2.

For the alternate shutdown cooli ng mode, if vessel depressuri zation were to be achieved by manual actuation of relief valves, three valves would need to be actuated to pass sufficient steam flow to depressurize the vessel.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-37 Low-pressure liquid flow test results are presented in NED E-24988-P. This test program adequately demonstrated the ability to use SR Vs in the alternate shutdown cooling mode.

Following reactor depressurization (i.e., 100°F/hr), an alternate shutdown coolant flow rate of 2600 gpm would be required to bring the reactor to a shutdown condition. This flow capacity can be achieved by using one AD S valve. However, three valves are always available.

Calculations demonstrate that in the alternate shutdown cooling mode, with one RHR pump in operation, the total system resist ance head is 550 ft using one SR V valve. At this calculated head, the pump capacity is 4000 gpm and the reactor pressure is 160 psig.

The air supply for the ADS valves is discussed in Sections 5.2.2, 6.2.2, and 7.3.1. 5.4.7.1.6 Design Basis for Prot ection from Physical Damage

The RHR system is designe d to the requirements of Table 3.2-1. With the exception of the common shutdown cooling line, redundant com ponents of the RHR system are physically located in different quadrants of the reactor building, and ar e supplied from independent and redundant electrical divisions. Further discussion on protecti on from physical damage is provided in Section 6.3. 5.4.7.2 Systems Design

5.4.7.2.1 System Diagrams

All of the components of the RHR system are shown in Figure 5.4-15 . A description of the controls and instrumentati on is presented in Section 7.3.1.1.1 . A process diagram and pro cess data are shown in Figures 5.4-16 and 5.4-17. All of the sizing modes of the system are shown in the process data. The functional control diagram for the RHR system is shown in Figure 7.3-10 . Interlocks are provided (a) to prevent draining vessel water to the suppression pool, (b) to prevent opening vessel suction va lves above the suction line de sign pressure, or above the discharge line design pressure with the pum p operating at shutoff head, (c) to prevent inadvertent opening of drywell spray valves, and (d) to prevent pump start when suction valve(s) are not open. This interlock is defeated for the RHR FPC assist mode (see Section 9.1.3).

The RHR system may be used to supplement the cooling capacity of the FPC system. This mode requires the installation of spool pieces and the opening of normally locked closed valves (see Section 9.1.3.2 for details).

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-38 The normal shutdown cooling mode of RHR loop B can be aligned to return a portion of the cooling flow back into the reactor ve ssel via the RCIC head spray nozzle.

The LPCS system may be cross tied with the RHR system to prov ide a flow path from the CST to the LPCS system via RHR. This preoperational alignment provided clean water to the LPCS system during flushing and provided a flowpath to the vesse l for the core spray sparger test. This spoolpiece is not expected to be used again during the lifetime of the plant. The administrative controls used for these spoolpieces, interlocks , and valves are procedurally regulated to ensure pr oper system function. 5.4.7.2.2 Equipment and Component Description

a. System main pumps The RHR main system pumps are mo tor-driven deepwell pumps with mechanical seals. The pumps are sized on the basis of the LPCI mode (modes A1 and A2, see Figure 5.4-17

). Design pressure for the pump suction structure is 220 psig with a temperatur e range from 40°F to 360°F. Design pressure for the pump discharge structur e is 500 psig. The bases for the design temperature and pressure are maximum shutdown cut-in pressures and temperature, minimum ambient temperature, and maximum shutoff head. The pump housing is carbon st eel and the shaft is stainless steel. System configuration (elevation, piping design, etc.) ensures that minimum pump NPSH

requirements are met with margin. Figures 5.4-18 through 5.4-20 are the actual pump performance curves.

The RHR pumps are designed for the life of the plant (40 years) and tested for operability assurance and performance as follows:

1. In-shop tests, including: (a) hydrosta tic tests of pressu re retaining parts at 1.5 times the design pressure, (b) performance tests to determine the total developed head at zero flow and design flow, and (c) NPSH requirements.

2. After the pumps were installed in the plant, they underwent (a) the system hydro test, (b) fu nctional tests, (c) peri odic testing to verify operability in accordance with the Inservice Testing (IST) Program Plan, and (d) about 1 month of operation each year for a refueling shutdown (shutdown operation time has been re duced coincident with reduced outage times).

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-39 3. In addition, the pumps are designed for a postulated single operation of 3 to 6 months for one accident during the 40 year life of the plant.

A listing of GE operating e xperience of Ingersoll-Rand RHR pumps is provided in Tables 5.4-3 and 5.4-4. b. Heat exchangers The RHR system heat exchangers are sized on the basis of the duty for the shutdown cooling mode (mode E of the Process Data). All other uses of these exchangers require less cooling surface. Flow rates are 7450 gpm (rated) on the sh ell side and 7400 gpm (rated) on the tube side (service water side). Rated inlet temperat ure is 95°F tube side. Design temperature range of both shell a nd tube sides are 40°F to 480°F. The tube side water temperature may be as low as 32°F. The low temperature condition is acceptable, base d on compliance with the AS ME III, Class 2, code. Design pressure is 500 psig on both side

s. Fouling allowances are 0.0005 shell side and 0.002 tube side.

The construction materials are carbon steel for the pressure vessel with stainless steel tubes and stainless steel clad tube sheet.

c. Valves All of the directional valves in the system are conventi onal gate, globe, and check valves designed for nuclear service.

The injection valv es, reactor coolant isolation valves, and pump minimum flow valves are high speed valves, as operation for LPCI injection or vessel isolation requires. Valve pressure ratings are specified as necessary to provide the control or isolation function: i.e., all vessel isolation valves are rated as Class 1 nuclear va lves rated at the same pressure as the primary system. The pump minimum flow valves (RHR-FCV -64) open automatically at main line flows less than approximately 800 gpm. This allows flow to return to the suppression pool through the minimum flow bypass line, which branches off the main line upstream of the flow element. The minimum flow valve closes at main line flows greater than approximately 900 gpm and forces the entire pump discharge flow through the main line. The minimum flow valve controls meet IEEE-279 requirements. To prevent loss of vessel inventory to the suppression pool when operating shutdown cooling or RHR/FP C assist mode, the mini mum flow valve is not

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-12-036 5.4-40 permitted to open. Administrative controls ensure that the valve is returned to normal status following the conclusion of shutdown cooling.

d. Restricting orifices The metering orifices in the discharge lines do not serve as restricting orifices.

The piping for each mode of RHR operation has been investigated to ensure that

the resistance is low enough to allow the rated flows given in Figure 5.4-17 yet high enough to prevent pump runout. Restricting orifices are necessary in the system test lines to prevent excessive runout during SP C and test modes and in the main discharge line to prevent exces sive runout for LPCI A & C systems. In addition, restriction orifices are installed ahead of the RHR-V-53A and RHR-V-53B valves to prevent excessive pump runout or valve cavitation during the

shutdown cooling mode. Figure 5.4-15 indicates the loca tion of restricting orifices. Additionally, two orifices are installed in the FPC system to minimize cavitation and limit flow when RHR is used to assist FPC.

e. ECCS portions of the RHR system The ECCS portions of the RHR system include those sectio ns described in Figure 5.4-16

. The route includes suppression pool suction strainers, suction piping, RHR pumps, discharge piping, injection valv es, and drywell piping into the vessel nozzles and core region of the reactor vessel. The SPC components include pool suction strainers, suction piping, pumps, heat exchangers, and po ol return lines. Containment spray components are the sa me as SPC except that the spray headers replace the pool return lines.

5.4.7.2.3 Controls and Instrumentation

Controls and instrumentation for the RHR system are described in Section 7.3. The RHR system relief valve capacities and settings are listed in Section 5.4.7.1.3 . 5.4.7.2.4 Applicable C odes and Classifications

See Section 3.2. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-41 5.4.7.2.5 Reliability Considerations The RHR system has included the re dundancy requireme nts of Section 5.4.7.1.5 . Two redundant loops have been provided to re move residual heat. With the exception of the common shutdown cooling line and the shutdown return valves (RHR-V-53A and RHR-V-53B) which are powered from the same division power source, all mechanical and electrical components are separate. Either loop is cap able of cooling down the reactor within a reasonable length of time.

5.4.7.2.6 Manual Action

RHR (shutdown cooling mode)

In the shutdown cooling mode of operation, when reactor vessel pressure is 48 psig or less, a service water pump is started a nd cooling water flow establishe d through a heat exchanger. The RHR pump suction valve RHR-V-4A and/or RHR-V-4B is then closed and shutdown cooling isolation valves RH R-V-9 and RHR-V-8 opened. RHR pump suction valve RHR-V-6A and/or RHR-V-6B is then opened. Pump suction piping is prewarmed and provided a nominal flush by opening valves to radwaste. These effluent valv es to radwaste are then closed and the RHR pump is started. The cooldown rate is contro lled by adjusting the heat exchanger outlet valve and heat exchanger bypass valve to ach ieve the desired temperature of the water returning to the r eactor vessel while maintaining th e total flow at approximately 7450 gpm.

If prewarming valves were acci dentally left open following in itiation of shutdown cooling, reactor pressure vessel (RPV) coolant inventory would drain to radwaste. If loss of inventory remained undetected and makeup did not occur, isolation valves RHR-V-8 and RHR-V-9 would automatically close at the RPV scram leve l specified in the Tec hnical Specifications; depressurization or loss of water from the RHR system causes a low pressure alarm in the RHR discharge piping.

If the bypass around RHR-V-6A were inadvertently left open following the initiation of shutdown cooling using RHR loop B, the RP V coolant inventory would drain to the

suppression pool at a flow rate of 1 gpm or less. If this loss of inventory remained undetected and makeup did not occur, RHR-V-8 and RHR-V-9 would auto matically close at the RPV scram level.

The manual actions required for the most limiting failure are discussed in Section 5.4.7.1.5 . 5.4.7.3 Performance Evaluation

Thermal performance of the RHR heat exchangers is based on the capability to remove enough sensible and decay heat from th e reactor system to reduce the bulk reactor coolant temperature COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-42 to 125°F within 25 hours after control rod in sertion, with two RHR loops in operation. Because cooldown is usually a controlled operation, maximum service water temperature less 10°F is used as the service water inlet temper ature. These are nominal design conditions; if the service water temperature is higher, the exchanger capabilities are reduced and the cooldown time may be longer or vice versa. 5.4.7.3.1 Shutdown Cooling W ith All Components Available

No typical curve is included here to show vessel cooldown temperatures versus time due to the infinite variety of such curves due to (a) clea n steam systems that use the main condenser as the heat sink when nuclear steam pressure is insufficien t to maintain steam air ejector performance, (b) the fouling of the heat exchangers, (c) opera tor use of one or two cooling loops, (d) coolant water temperature, and (e) sy stem flushing time. Si nce the exch angers are designed for the fouled condition with relatively high service water temper ature, the units have excess capability to cool when first used at high vessel temperatures. Total flow mix temperature is controlled to avoid exceeding 100°F/hr cooldown rate. See Figure 5.4-21 for minimum shutdown cooling time to reach 212°F.

5.4.7.3.2 Shutdown Cooling With Most Limiting Failure

Shutdown cooling under cond itions of the most limiting failure is discussed in Section 5.4.7.1.5. The capability of the heat exchanger for any time period is balanced against residual heat, pump heat, and sensible heat. The excess over re sidual heat and pump heat is used to reduce the sensible heat.

5.4.7.4 Preoperational Testing

The preoperational test program and startup test program were used to generate data to verify the operational capabilities of equipment in the system, such as ea ch instrument, setpoint, logic element, pump, heat exchanger, valve, and limit switch. In addition these programs verified the capabilities of the system to provide the flows, pressure s, cooldown rate s, and reaction times required to perform all syst em functions as spec ified for the system or component in the System Data Sheets and Process Data. Logic elements were tested electrically; valves, pumps, controllers, relief valves were tested mechanically; finally the system was tested for total system performance against the design requireme nts as specified above using both the offsite power and standby emergency power. Preliminar y heat exchanger performance was evaluated by operating in the pool cooling mode, but a ve ssel cooldown was used fo r the final check due to the small temperature differences available with pool cooling (see Section 14.2). COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December2005 5.4-43 5.4.8 REACTOR WATER CLEANUP SYSTEM The reactor water clean up (RWCU) system is an auxiliary system, a small part of which is part of the RCPB up to and includi ng the outermost containment is olation valve. The other portions of the system are not part of th e RCPB and are isolat ed from the reactor.

5.4.8.1 Design Bases

5.4.8.1.1 Safety Design Bases The RCPB portion of the RWCU system meets the requirements of Regulatory Guides 1.26 and 1.29 to

a. Prevent excessive loss of reactor coolant,

b. Prevent the release of radioactive material from the reactor,

c. Isolate the cleanup syst em from the RCPB, and

d. Prevents loss of liquid reactivity control material from the reactor vessel during standby liquid control (S LC) system operation.

5.4.8.1.2 Power Gene ration Design Bases

The RWCU system

a. Removes solid and dissolved impurities from reactor coolant such that the water purity meets Regulatory Guide 1.56,

b. Discharges excess reactor water during startup, shutdown, and hot standby conditions,

c. Minimizes temperature gradients in the recirculation pi ping and vessel during periods when the main recircul ation pumps are unavailable,

d. Minimizes cleanup sy stem heat loss, and

e. Enables the major portion of the RWCU system to be serviced during reactor operation.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.4-44 5.4.8.2 System Description The RWCU system (see Figures 5.4-22 and 5.4-23) continuously purifies reactor water during all modes of reactor operation. The system take s suction from the inle t of each reactor main recirculation pump and from the reactor pressure vessel bottom head. Processed water is returned to the reactor pressure vessel, to the main condenser, or radwaste.

The cleanup system can be opera ted at any time during planned operations, or it may be shut down. The cleanup system is classified as a primary power generation system. The cleanup system is not an engineered safety system.

Major equipment of the RWCU sy stem is located in the reacto r building. This equipment includes the pumps and the regenerative and nonregenerative heat exchangers. Filter-demineralizers and suppor ting equipment are located in the radwaste building. The entire system is connected by associated valves and piping; controls and instrumentation provide proper system operation. Design data for the major pieces of equipment are presented in Table 5.4-5 . Reactor water is cooled in the regenerative and nonregenerativ e heat exchangers, filtered, demineralized, and returned to the reactor pr essure vessel through the shell side of the regenerative heat exchanger.

The system pump is capable of producing a nom inal flow of 181,300 lbm/hr. Two filter demineralizer units are used to process this quantity of water. The system can operate at reduced flow rates with one filter demineralizer unit.

The temperature of water processed through the filter-demineral izers is limited by the resin operating temperature. Therefore, the reactor water must be cooled before being processed in the filter-demineralizers. The regenerative heat exchanger transfers heat from the tube side (hot process) to the shell side (cold process). The shell side flow returns to the reactor. The nonregenerative heat exchanger c ools the process further by tran sferring heat to the reactor building closed cooling water system.

The filter-demineralizers (see Figure 5.4-24 ) are pressure precoat type filters using ion exchange resins. Spent resins are not regenerable and are sluiced from the filter-demineralizers to a backwash receiving tank from which they are transferred to the radwaste system for processing and disposal . To prevent resins from entering the RRC in the event of complete failure of a filter-demineralizer resin septum, a strainer is installed on each filter-demineralizer. Each strainer and filter-demineralizer vessel has a control room alarm that is energized by high differential pressure. Further increase in diffe rential pressure will isolate the filter-demineralizer. The backwash and precoat cycle for a filter-demineralizer is automatic to prevent operational errors such as inadvertent ope nings of valves that would initiate a backwash or contaminate reactor water with resins. The filter-demineralizer piping

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.4-45 configuration is arranged to ensure that transfers are complete and crud traps are avoided. A bypass line is provided around the filter-dem ineralizers. On low flow or loss of flow in the system, flow is maintained through each filter-demineralizer by its own holding pump. Sample points are pr ovided in the common influent header and in each effluent line of the filter-demineralizers for continuous indi cation and recording of system conductivity. High conductivity is annunciated in the control room. The influent sample point is also used as the normal source of reactor coolant grab samples. Sample analysis also indicates the effectiveness of the filter-demineralizers. The suction line of the RCPB portion of the RWCU system contains two motor-operated isolation valves that automatically close in response to signals from the RPV low water level and the leak detection system. The outboard isolation valve, RWCU-V-4, automatically closes in response to signals from actuation of th e SLC system and high nonregenerative heat exchanger outlet water temperature. These actions prevent (a) loss of reactor coolant, (b) release of radioactive material from the reactor, (c) removal of liquid reactivity control material, and (d) thermal damage to ion-exchange resins. The RCPB isolation valves may be remote manually operated to isolate the system equipment for maintenance or servicing.

A remote manual-operated gate valve on the return line to the reactor provides long-term leakage control. Instantaneous reverse flow isolation is provided by check valves in the RWCU piping.

Operation of the RWCU system is controlled from the main control room. Resin-changing operations, which include backwashing and precoating, are controlled from the radwaste control room in the radwaste building.

A functional control diagram is provided in Figure 7.3-1 . 5.4.8.3 System Evaluation

The RWCU system in conjunction with the condensate treatmen t system and FPC and cleanup system maintains reactor water quality during all reactor operating m odes (normal, standby, startup, shutdown, and refueling). The RWCU components provide a system with the capability to support reactor operations at power levels up to 3629 MWt.

The component pressure and temperat ure design conditions are shown in Table 5.4-5 . The process containing components (p iping, valves, vesse ls, heat exchangers, pumps) are designed to the requirements of Section 3.2. The control requirements for the RCPB isolation valves are designed to the requirements of Table 7.3-5. The nonregenerative h eat exchanger is sized to maintain the process temperature required for the cleanup demineralizer resin when the cooling capacity of the regenerative heat exchanger is reduced at times when flow is partially bypassed to the main condenser or radwaste.

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-10-010 5.4-46 5.4.8.4 Demineralizer Resins

Regulatory Guide 1.56 complian ce is described in Section 1.8. 5.4.8.5 Reactor Water Cleanup Water Chemistry

5.4.8.5.1 Analy tical Methods

Chemical analyses methods used for determinati on of conductivity, pH, a nd chloride content of primary coolant are as follows: Conductivity measured in accordance to ASTM-D-1125 pH measured in accord ance to ASTM-D-1293

Chloride determined by ion chromat ography in accordance with the vendor's operating manual

5.4.8.5.2 Relationship of Filter-Demineralizer Condition to Water Chemistry

The filter-demineralizer condition during norm al power operation is related to inlet conductivity and water volume proce ssed through the unit. The in let conductivity is related to impurity concentration through the equivalent c onductance of the constitu ents of the process fluid. System flow rates are measured and reco rded to determine quantity of water processed. Periodically, an On-Line NobleChem application will be performe d, which injects platinum into the reactor coolant, resu lting in a microscopic layer of the noble metal to be deposited onto the reactor internals.

Conductivity instrumentation is calibrated against laboratory flow cel ls in accordance with ASTM-D-1125. The alarm setpoints for the conductivity instrument ation at the inlet and outlet of the filter-demineralizers are set to indicate marginal performance or breakthrough of the filter-demineralizers.

The quantity of the principle ion(s) likely to cause demineralizer breakthrough are not calculated using conductivity as di scussed in position 4.C of Regulatory Guide 1.56. Instead, actual ion sample data is taken and used to determine ion levels at the outlet of the filter-demineralizer. When sample da ta indicates resin breakthrough or the allowable pressure drop is exceeded, the filter-demin eralizer is regenerated.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-04-002 5.4-47 5.4.9 MAIN STEAM LINES AND FEEDWATER PIPING

5.4.9.1 Safety Design Bases

To satisfy the safety bases, the main steam and feedwate r lines have been designed

a. To accommodate operational stresses, such as internal pressures and SSE loads, without a failure that could lead to the release of radi oactivity in excess of the guideline values in pub lished regulations, and

b. With suitable accesses to permit IST and inspections.

5.4.9.2 Power Gene ration Design Bases

To satisfy the design bases

a. The main steam lines have been designed to conduct steam from the reactor vessel over the full range of re actor power operation, and

b. The feedwater lines have been designed to conduct water to the reactor vessel over the full range of reactor power operation.

5.4.9.3 Description

The main steam piping is described in Section 10.3. The main steam and feedwater piping is shown in Figure 10.3-2 . The feedwater piping consists of two 24-in. O.D. lines which penetrate the containment and drywell and branch into three 12-in. lines each, which connect to the r eactor vessel. Each 24-in. line includes three containm ent isolation valves consisting of one check valve inside the drywell and one motor-operated gate valve and one check valve outside the containment. The design pressure and temperature of the feedwa ter piping between the re actor and maintenance valve is 1300 psig and 575°F. The Seismic Category I design requirements are placed on the feedwater piping from the reactor through the out board isolation valve and connected piping up to and including the first isolati on valve in the connected piping.

The materials used in the piping are in acco rdance with the applicable design code and supplementary requirement s described in Section 3.2. The feedwater system is furt her described in Sections 7.7.1, 7.7.2, and 10.4.7. COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-48 5.4.9.4 Safety Evaluation Differential pressure on reactor internals under the assumed acc ident condition of a ruptured steam line is limited by the use of flow restrictor s and by the use of four main steam lines. All main steam and feedwater pipi ng is designed in accordance with the requirements defined in Section 3.2. 5.4.9.5 Inspection and Testing Inspection and testing of the main steam lines and feedwater piping is performed in accordance with the ISI Program Plan to ensure compliance w ith applicable codes. 5.4.10 PRESSURIZER

Not Applicable to BWRs.

5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM

Not Applicable to BWRs.

5.4.12 VALVES

5.4.12.1 Safety Design Bases

Line valves such as gate, globe, and check valves are located in the fluid systems to perform a mechanical function. Valves are components of the system pressure boundary and, having moving parts, are designed to operate efficiently to maintain the integrity of this boundary.

The valves operate under the in ternal pressure/temperature lo ading as well as the external loading experienced during the various system transient operating conditions. The design criteria, the design loading, and acceptability criteria are as required in Section 3.9.3 for ASME Class 1, 2, and 3 valves. Complia nces with ASME Code s are discussed in Section 5.2.1.

5.4.12.2 Description

Line valves furnished are manufactured standard types, designe d and constructed in accordance with the requirements of ASME Section III for Class 1, 2, and 3 valves. All materials, exclusive of seals, packing and wearing compone nts, are designed to en dure the 40-year plant life under the environmental conditi ons applicable to the particul ar system when appropriate maintenance is peri odically performed.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-49 Power operators have been si zed to operate successfully und er the maximum differential pressure determined in the design speci fication or design basis calculations. 5.4.12.3 Safety Evaluation

Line valves are shop tested by the manufacturer for performability. Pressure retaining parts are subject to the testing and ex amination requirements of Secti on III of the ASME Code. To minimize internal and external leakage past seating surfaces, maximum allowable leakage rates are stated in the design specifica tions for both back seat as well as the main seat for gate and globe valves.

Valve construction materials are compatible with the maximum anticipated radiation dosage for the service life of the valves.

5.4.12.4 Inspection and Testing

Valves serving as containment isolation valves and which must remain closed or open during normal plant operation may be partially exercised during this period to assure their operability at the time of an emergency or faulted conditions . Other valves, serving as a system block or throttling valves, may be exer cised when appropriate.

Motors used with valve actuators are furn ished in accordance with applicable industry standards. Each motor actuator has been assembled, factory te sted or tested in-situ, and adjusted on the valve for proper operation, position and torque switch setting, position transmitter function (where applicable), and speed requirements. A selected set of motor-

operated valves with active safety functions (Generic Letter 89-10 Program and Generic Letter 96-05 Program) have additionally been tested to demonstrate adequate stem thrust (or torque) capability to open (or clos e) the valve within the specified time at specified maximum expected differential pressure. Modifications have been made to several gate valves to eliminate the possibility for internal pressure locking forces wh ich could prevent the actuator from unseating the valve (G eneric Letter 95-07 Program).

Tests verified no mechanical damage to valve components during full st roking of the valve. Suppliers were required to furnish assurance of acceptability of the equipment for the intended service based on any combination of

a. Test stand data, b. Prior field performance,

c. Prototype testing, and

d. Engineering analysis.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-50 Preoperational and operational testing performed on the installed valves consists of total circuit check out and performance tests to verify de sign basis capability including speed requirements at specified differential pressure.

5.4.13 SAFETY AND RELIEF VALVES

A listing of the safety and re lief valves is provided in Table 5.4-6 . 5.4.13.1 Safety Design Bases

Overpressure protection is provi ded at isolatable portions of systems in accordance with the rules set forth in the ASME Code, Secti on III for Class 1, 2, and 3 components.

5.4.13.2 Description

Pressure relief valves are desi gned and constructed in accordance with the same code class as that of the line valves in the system.

The design criteria, design loading, and de sign procedure are described in Section 3.9.3. 5.4.13.3 Safety Evaluation

The use of pressure relieving devices will ensure that overpressure will not exceed 10% above the design pressure of the system . The number of relieving devices on a system or portion of a system have been determined on an individual component basis.

5.4.13.4 Inspection and Testing

The valves are inspected and tested in accordance with ASME Section XI, if required.

Other than the main steam relief valves, no prov isions are to be made for inline testing of pressure relief valves, other than set pressure and leakage. Certified set pressures and relieving capacities are stampe d on the body of the valves by the manufacturer and further examinations would necessitate removal of the component. For subsequent set pressure changes, the valve body will be stamped or a st amped tag will be attached indicating the new pressure.

5.4.14 COMPONENT AND PIPING SUPPORTS

Support elements are provided for those compon ents included in the RC PB and the connected systems.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-51 5.4.14.1 Safety Design Bases Design loading combinations, design procedures, and acceptability criteria are as described in Section 3.9.3. Flexibility calculations and seismic anal ysis for Class 1, 2, and 3 component and piping supports within the ASME boundary of jurisdiction conform with the appropriate requirements of ASME Secti on III, Subsection NF. Outside the ASME boundary steel structures conform to the AISC manual of Steel Construction.

Spacing and size of pipe suppor t elements were based on the piping analysis performed in accordance with ASME Section III a nd further described in Section 3.7. Standard manufacturer hanger types were used and fabricated of mate rials per ASME Section III, Subsection NF.

5.4.14.2 Description

The use and location or rigid-t ype supports, variable or constant spring-type supports, and anchors or guides are determined from the results of static and dynamic analyses of the associated piping systems. The normal and transient (including seismic) support point loads generated by the piping analyses are combined as prescribed by Sections 3.9.3 and 3.7, and then utilized as the design basis loadings for each affected pipe support.

Typically, components support elements are manufacturers' standard items which are purchased with certified load capacity data reports. Nonstandard support structures and pressure boundary attachments are qualified by detailed structural analyses in compliance with applicable load combinations and governing design codes.

As described by Sections 5.4.14.1 and 5.4.14.2, each component suppor t system has been rigorously evaluated with all due consideration for extreme load ing conditions and satisfaction of conservative design allowable stresses. This demonstration of structural adequacy combined with a comprehensive testing a nd inspection program (see Section 5.4.14.3) constitutes the safety evaluation basis for th ese passive support elements.

5.4.14.3 Inspection and Testing

After completion of the installa tion and balancing of a support system, all hanger elements were visually examined to ensu re that they were in correct adjustment to their cold setting position. On initial hot startup operations, ther mal growth was observe d and it was confirmed that all spring-type hangers a nd snubbers were functioning properly between their hot and cold setting positions. In addition, during power ascension testing critical systems were instrumented and monitored for vibration response under normal a nd plant transient conditions. The results of these tests showed all systems to be functioning as predicted by design analyses and thus all systems were accepted as operable and in compliance with the governing ASME Code. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-06-054 5.4-52 5.4.15 HIGH-PRESSURE CORE SPRAY SYSTEM

See Section 6.3 for a description of the HPCS system.

5.4.16 LOW-PRESSURE CORE SPRAY SYSTEM

See Section 6.3 for a description of the LPCS system. 5.4.17 STANDBY LIQUID CONTROL SYSTEM

See Section 9.3.5 for a description of the SLC system.

5.4.18 REFERENCES

5.4-1 Ianni, P. W., "Effect iveness of Core Standby Cooling Systems for General Electric Boiling Water React ors," APED-5458 , March 1968.

5.4-2 "Design and Performance of General Electric Boiling Water Reactor Main Steam Line Isolation Valves," APED-5750, General Electric Co., Atomic Power Equipment Depa rtment, March 1969.

5.4-3 "Power Uprate with Extended Load Line Limit Safety Analysis for WNP-2," NEDC-32141P, General Electric Company.

5.4-4 "Generic Evaluations of General Electric Boiling Wa ter Reactor Power Uprate - Volume I," NEDC-31984P, Ge neral Electric Company.

5.4-5 "Reactor Core Isolation Cooling System (RCIC)," Design Basis Document, Section 315.

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-98-113 5.4-53 Table 5.4-1 Reactor Coolant Pr essure Boundary Pump

and Valve Descriptio na Location Active /Inactive Valve Reference Figure Valve Description RHR vessel in Active Active Active Active Active Active

Inactive Inactive Inactive RHR-V-41A

RHR-V-41B RHR-V-41C (E12F041A, B, C) RHR-V-42A

RHR-V-42B

RHR-V-42C

(E12F042A, B, C) RHR-V-111A

RHR-V-111B

RHR-V-111C

(E12F111A, B, C) 5.4-15 5.4-15 5.4-15 5.4-15 5.4-15 5.4-15

5.4-15 5.4-15 5.4-15 RHR/recirculation

line in Active Active

Active Active

Inactive Inactive

Inactive Inactive RHR-V-50A

RHR-V-50B

(E12F050A, B) RHR-V-53A

RHR-V-53B

(E12F053A, B) RHR-V-112A

RHR-V-112B

(E12F112A ,B) RHR-V-123A

RHR-V-123B

(E12F099A, B) 5.4-15 5.4-15

5.4-15 5.4-15

5.4-15 5.4-15

5.4-15 5.4-15 Head spray Active Active RHR-V-19 (E12F019) RHR-V-23 (E12F023) 5.4-15 5.4-15 RHR shutdown

cooling suction Active Active Inactive RHR-V-8 (E12F008) RHR-V-9 (E12F009) RHR-V-113 (E12F113) 5.4-15 5.4-15 5.4-15 RCIC vessel out Active Active Active Active RCIC-V-8 (E51F008)

RCIC-V-63 (E51F063)

RCIC-V-64 (E51F064)

RCIC-V-76 (E51F0076) 5.4-11 5.4-11 5.4-11 5.4-11 COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-98-113 5.4-54 Table 5.4-1

Reactor Coolant Pr essure Boundary Pump

and Valve Descriptio na (Continued) Location Active /Inactive Valve Reference Figure (Nuclear boiler) Reactor vessel head

Inactive Inactive

MS-V-1 (B22F001)

MS-V-2 (B22F002)

10.3-2 10.3-2 Feedwater in Active Active

Inactive Inactive

Active Active

Active Active RFW-V-10A

RFW-V-10B (B22F010A, B)

RFW-V-11A

RFW-V-11B (B22F011A, B)

RFW-V-32A

RFW-V-32B (B22F032A, B)

RFW-V-65A

RFW-V-65B (B22F065A, B) 10.3-2 10.3-2

10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 Safety relief Active Active Active Active Active Active Active Active

Active Active Active Active Active Active

Active Active MS-RV-2A MS-RV-3A

MS-RV-2D

MS-RV-2C

MS-RV-1B

MS-RV-2B

MS-RV-3C

MS-RV-3B

(B22F013A -H) MS-RV-1A

MS-RV-1D

MS-RV-1C

MS-RV-4C

MS-RV-5C (B22F013J-N) MS-RV-4D

(B22F013P)

MS-RV-4B MS-RV-4A 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2

10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2

10.3-2 10.3-2 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-55 Table 5.4-1 Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued) Location Active/Inactive Valve Reference Figure Active Active (B22F013R-S)

MS-RV-5B

MS-RV-3D

(B22F013U-V)

10.3-2 10.3-2 Reactor water

cleanup system Inactive RWCU-V-103 (G33F103) 5.4-22 Line suction Active Active Inactive Inactive Inactive Inactive RWCU-V-1 (G33F001)

RWCU-V-4 (G33F004) RWCU-V-100 (G33F100)

RWCU-V-101

(G33F101)

RWCU-V-102

(G33F102)

RWCU-V-106

(G33F106) 5.4-22 5.4-22 5.4-22 5.4-22

5.4-22

5.4-22 Line discharge Active RWCU-V-40 (G33F040) 5.4-22 Drain to condenser Active Active MS-V-16 (B22F016)

MS-V-19 (B22F019) 10.3-2 10.3-2 MSIV Active Active Active Active Active Active Active Active MS-V-22A

MS-V-22B

MS-V-22C

MS-V-22D (B22F022)

MS-V-28A

MS-V-28B

MS-V-28C MS-V-28D (B22F028) 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009, 06-000 5.4-56 Table 5.4-1

Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued) Location Active/Inactive Valve Reference Figure Drain to condenser

(Recirculation) Active Active Active Active MS-V-67A

MS-V-67B

MS-V-67C

MS-V-67D (B22F067) 10.3-2 10.3-2 10.3-2 10.3-2 Recirculation pump

suction Inactive Inactive RRC-V-23A RRC-V-23B (B35F023) 5.4-7 5.4-7 Flow control (pump

discharge) Inactiveb Inactiveb Inactive Inactive RRC-V-60A

RRC-V-60B (B35F060)

RRC-V-67A

RRC-V-67B

(B35F067) 5.4-7 5.4-7

5.4-7 5.4-7 RCIC vessel head in Active Active Active RCIC-V-13 (E51F013) RCIC-V-65 (E51F065)

RCIC-V-66 (E51F066) 5.4-11 5.4-11 5.4-11 HPCS in Active Active Inactive HPCS-V-4 (E22F005)

HPCS-V-5 (E22F004) HPCS-V-38 (E22F038) 6.3-4 6.3-4 6.3-4 LPCS in Active Active Inactive LPCS-V-5 (E21F005) LPCS-V-6 (E21F006)

LPCS-V-51 (E21F051) 6.3-4 6.3-4 6.3-4 Standby liquid

control in Active Active Active Active Inactive SLC-V-4A

SLC-V-4B

SLC-V-6 SLC-V-7 SLC-V-8 9.3-14 9.3-14 9.3-14 9.3-14 9.3-14 Pump description Recirculation pump Inactive Inactive RRC-P-1A RRC-P-1B (B35C001) 5.4-7 5.4-7 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-57 Table 5.4-1 Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued) a In addition to the process valves listed herein, there are instrument test conditions, drain valves, and sampling valves less than 1 in. nominal size within the RCPB. See associated system flow diagram figures.

b Mechanically blocked in the full open position.

NOTE: Active components are those whose operability is relied on to perform a safety function during the transients or accidents.

Inactive components are those whose operab ility (e.g., valve opening or closure, pump operation or trip) is not relied on to perform the system's safety function during the transients or accidents. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-07-011 5.4-58 Table 5.4-2

Reactor Recirculation System Design Characteristics

Description External loops 2 Pump sizes (nominal O.D.) Pump suction, in. 24 Pump discharge, in. 24 Discharge manifold, in. 16 Recirculation inlet lines, in. 12 Design pressure (psig)/design temperature ( °F) Suction piping and valve up to and including pump suction nozzle 1250/575 Pump, discharge valves, and piping between 1650/575 Piping after discharge blocking valve up to vessel 1550/575 Vessel bottom drain 1275/575 Operation at pump related conditions Recirculation pump Flow, gpm 47,200 Flow, lb/hr 17.85 x 10 6 Total developed head, ft 805

Suction pressure (static), psia 1025 Required NPSH, ft 115 Water temperature (maximum), °F 533 Pump brake hp (minimum) 8340 Flow velocity at pump suction (approximate), ft/sec 41.5 Pump motor Voltage rating 6600 Speed, rpm 1780 Motor rating, hp 8900

Phase 3 Frequency 60

Motor rotor inertia (lb-ft

2) 21,500 (RRC-M-P/1B) 20,600 (RRC-M-P/1A)

Jet pumps Number 20

Total jet pump flow, lb/hr 108.5 x 10 6 Total I.D., in. 6.4

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-59 Table 5.4-2

Reactor Recirculation System Desi gn Characteristics (Continued) Description Diffuser I.D., in. 19.0 Nozzle I.D. (five each), in. 1.3 Diffuser ex it velocity, f t/sec 16.2 Jet pump head, ft 88.19 Flow control valve a Type Ball

Material Austenitic stainless steel

Valve wide open CV (minimum), gpm/psi 7000 Valve size diameter, in. 24 Recirculation block valve Type Gate valve Actuator Motor

Material Austenitic stainless steel

Valve size diameter, in. 24 Recirculation pu mp flow measurement Type Elbow taps Rated flow (gpm) 47,200 Flow element location Pump suction line Range 20-115% rated pump flow Accuracy (% rated pressure drop) 9% Repeatability (% rate d pressure drop) 4% a Mechanically blocked in the full open position. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-60 Table 5.4-3

Operating Experience of Ingersoll-Rand

Emergency Core Cooling Systems Pump sa,b Plant Pump Time (hr) Hatch 2 RHR 2A 864 2B 1112 2C 629 2D 569 LPCS 2A 13.5 2B 11.8 Chinshan 1 RHR 100 Core spray 30 Chinshan 2 RHR 75 Core spray 20 a The italicized information is historical and was provided to support the application for an operating license.

bNo problems have been reported on these pum ps. Pump design principles applied by Ingersoll-Rand to these units are not unique. Assu rance of a predictable functional reliability is also provided by a history of design, production, and applic ation of pumps for similar pumping requirements in other nuc lear and nonnuclear applications. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-61 Table 5.4-4

Operating Experience of Similar Ingersoll-Rand Pumps for BWR Projects

Under Reviewa,b Year Size Range (g pm) Number of P umps 1963 <4000 12 1964 <3000 24 1965 <5000 32 1966 <4500 39 1967 <5000 8000 39 3 1968 <6500 9000 11000 25 6 9 1969 <6500 8000-9000 39 9 1970 <6500 8000 12,000 33 14 6 1971 <6500 9000 10,000-12,000 53 3 12 1972 <6500 8000 10,000-12,000 44 18 18 1973 <6500 8000 10,000-13,800 41 8 20 1974 <6500 8000 10,000-13,800 32 2 30 1975 <7500 8500 10,000-13,800 76 18 50 1976 8500 9 a The italicized information is historical and was provided to support the application for an operating license. b The vertical pumps used for ECCS functions at CGS are sized at 1200 to 8100 gpm. They are multistaged axial pumps. Included here is a partial list of the application history for similar pumps made by the same vendor. Although the operating experience in nuclear applications is just beginning, the postoperating experience in nonnuclear applications with these vertical pumps is very extensive. It indicates that the CGS ECCS pumps can be expected to operate as required. In reviewing this table, the generic pump design should be recalled because larger capacity pumps are configured from stages that comprise the smaller capacity pumps. Design refinements are evident in the capacity growth of these stages, whether in single, double, or multiple axial stackups.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-62 Table 5.4-5 Reactor Water Cleanup System

Equipment Design Data Main Cleanup Recirculation Pumps Number 2 Capacity (each) 100% (@90 bhp) Design te mperature, F 575 Design pressure, psig 1420 Discharge head at shutoff, ft 575 Minimum available NPSH, ft 16 Heat Exchangers Regenerative Nonregenerative Number 1 (3 shells) 1 (2 shells) Shell design pressure, psig 1420 150 Shell design temperature, F 575 370 Tube design press ure, psig 1420 1420 Tube design temperature, F 575 575 Filter-De mineralizers Type Pressure precoat Number 2 Design temperature, F 150 Design pressure, psig 1450

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-056 5.4-63 Table 5.4-6 Safety and Relief Valves for Piping Systems

Connected to the React or Coolant Pressure Boundary Main steam line safety/relief valves MS-RV-1A (B22F013J-N) MS-RV-1B (B22F013A -H) MS-RV-1C (B22F013J-N)

MS-RV-1D (B22F013J-N) MS-RV-2A (B22F013A -H) MS-RV-2B (B22F013A -H) MS-RV-2C (B22F013A -H) MS-RV-2D (B22F013A -H) MS-RV-3A (B22F013A -H) MS-RV-3B (B22F013A -H) MS-RV-3C (B22F013A -H) MS-RV-3D (B22F013U-V)

MS-RV-4A (B22F013R -S) MS-RV-4B (B22F013R -S) MS-RV-4C (B22F013J-N)

MS-RV-4D (B22F013P)

MS-RV-5B (B22F013U-V)

MS-RV-5C (B22F013J-N) RCIC system discharge line RCIC-RV-3 RCIC system suction l ine RCIC-RV-17 (E51F017) RCIC lube oil cooler supply line RCIC-RV-19T RCIC vacuum tank RCIC-RV-33 (E51F033) a Shutdown cooling supp ly line RHR-RV-5 (E12F005) Shutdown cooling retu rn line RHR-RV-25A RHR-RV-25B (F12F025A, B) Suppression pool supply for RHR RHR-RV-88A RHR-RV-88B RHR-RV-88C

(E12F088A, B, C) RHR flush line RHR-RV-30 (E12F030) RHR heat exchanger (shell side) RHR-RV-1A RHR-RV-1B RWCU regenerative heat exc hanger (shell side) RWCU-RV-1a COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-64 Table 5.4-6 Safety and Relief Valves for Piping Systems Connected to the Reactor Coolan t Pressure Bounda ry (Continued) RWCU regenerative heat exchanger (tube side) RWCU-RV-3 a RWCU blowdown to radwaste system or condenser RWCU-RV-36 (G33F036) a HPCS suction line HPCS-RV-14 (E22F014) HPCS discharge line HPCS-RV-35 (E22F035) LPCS discharge line LPCS-RV-18 (E21F018) LPCS suction line LPCS-RV-31 (E21F031) SLC pump discharge line SLC-RV-29A SLC-RV-29B (C41F029A, B) a These relief valves are instal led in a B31.1 system; not subject to Section XI testing and inspection.

Driving Flow Recirculation PumpJet PumpSimplified SchematicPictorial View Recirculation Outlet Recirculation InletDischarge Shutoff ValveFlow Control Valve (Note 1)Suction Shutoff ValveNote 1: FCVs Are Mechanically Blocked Full Open. SuctionFlowCoreRecirculation System Evaluation and Isometric 960690.07 5.4-1FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report 110% Speed 105% Speed 100% Speed System Resistance 10,00020,00030,00040,00050,00060,000Flow - GPM Dynamic Head - Ft. 1,4001,2001,000800600400 2000RRC Pump Dynamic Head-Flow Curve 960690.05 5.4-2FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report 020040060080010001200140016001800 25% Flow - 535F Water25% Flow - Cold Water 100% Flow - 535F Water100% Flow - Cold WaterBreakaway Torque is 1200 Ft. Lbs. Pump Speed - RPM Pump Torque - Ft. Lbs. 36,00032,00028,00024,000 20,000 16,000 12,0008,000 4,0000RRC Pump Speed - Torque Curve 960690.06 5.4-3FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.59Recirculation Pump Head, NPSH, Flow and Efficiency Curves 5.4-4400200010,0005,000 090807060504030201001200 1000800600 400010.00020,00030,00040,00050,00060,00070,000 NPSH at C imp.Efficiency % HeadBHP at 0.755 SP. GR. Total Dynamic Head (Ft) BHPNPSH (Ft)Efficiency % Gallons Per Minute LColumbia Generating StationFinal Safety Analysis Report Operating Principle of Jet Pump 960690.58 5.4-5SuctionFlowDriving FlowSuctionFlowPDrivingFlowPPressureDriving Flow FlowSuctionDriving Nozzle Throator Mixing SectionDiffuserFigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.60Core Flooding Capability of Recirculation System 5.4-6SteamSeparation Distribution PlenumWater Level After Break in Recirculation LoopNormalWaterLevelSteamSeparators Active Core Columbia Generating StationFinal Safety Analysis Report Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-7.211M530-2Reactor Recirculation System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-7.210M530-2Reactor Recirculation System - P&IDRev.FigureDraw. No. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.61Main Steam Line Flow Restrictor Location 5.4-8Reactor Vessel Steam Flow Restrictor DrainsMain Steam LineIsolation Valves PrimaryContainmentTestConnection Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.84Main Steam Line Isolation Valve 5.4-9Air Cylinder (Closing Piston Inside) MSIV SpeedControl Valves Hydraulic Dash PotActuator Support

And Spring Guide

ShaftClosing Spring Spring Seat Member StemStem PackingLeak OffConnection (Plugged) Bonnet Bolts BonnetBalancing OrificeMain Valve

SeatBodyPilotPilot Seat AccumMain Disk Columbia Generating StationFinal Safety Analysis Report Flow RCIC Pump Performance Curve (Constant Flow) 960690.55 5.4-10NPSH-ft at 625 GPM EFF% at 625 GPM HEAD at 625 GPMBHP at SP. GR 1.0 at 625 GPM 320028002400 2000160012008004000BHP Required NPSH-Required 30201006004002000800Eff.%9080706050 40 30201001500200025003000350040004500 Speed Revolutions Per MinuteWitness Test Performance Bingham-Willamette Co.

Portland, Oregon FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report5.4-1198M519RCIC System - P&IDRev.FigureDraw. No. Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-121002E51-04,4,1RCIC System Process DiagramRev.FigureDraw. No. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.86 RCIC Pump Performance Curve 5.4-1312001400 1600 1800 2000010 20 30 40506070 8090Eff. %12005001000BHP02550NPSH-ft100Gallons Per MinuteTest Speed RG. 3591-3585 RPM HeadEff%BHP at SP. GR 1.0 NPSH at C Imp. L100080060040020000Whitness Test Performance Bingham-Willamette Co.

Portland, Oregon. Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.87Typical Strainer 5.4-14Notes:1. Flow stated above is per penetration with two (2) units described above

required per penetration.

2. Units are designed, manufactured and inspected in accordance with ASME

Section III, Class 2 (not stamped) 1974 Ed. with Addenda thru Winter 1976.

3. Design temp: 220FMeasurements for Strainers at Penetration X-33

Rated Flow: 600 gal/min Columbia Generating StationFinal Safety Analysis Report Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-15.1115M521-1Residual Heat Removal System - P&IDRev.FigureDraw. No.~~~~~~~~~~~~~~~~~~~~~~~~~~ Columbia Generating StationFinal Safety Analysis Report 5.4-15.2114M521-2Residual Heat Removal System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai LDCN-14-020 Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 05.4-15.4 5M521-4Residual Heat Removal System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-161002E12-04,1,1Residual Heat Removal System Process DiagramRev.FigureDraw. No. Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-17.1802E12-04,22,1Residual Heat Removal System Process DataRev.FigureDraw. No.

Draw. No. Rev.Figure FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.89 RHR (LPCI) Pump Characteristics(S/N 0473113) P-2A 5.4-18BHPEfficiency HeadNPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 01020 30 40 50 60 70 80 90012 3 4 5 6 7 80102030400510Brake Horsepower x 100 NPSH in FeetEfficiency, % Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet x 100 960690.90 Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev. 1FigureAmendment 62 December 2013 5.4-19Form No. 960690FH LDCN-12-036 RHR (LPCI) Pump Characteristics (S/N 0801MP004399-1) P-2BEfficiency BHPHeadNPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 10020304050607080901000 12345 67801020 30 400510Brake Horsepower NPSH in FeetTotal Head in Feet x100Efficiency, % 960690.91 Columbia Generating Station Final Safety Analysis Report RHR (LPCI) Pump Characteristics(S/N 0473112) P-2CDraw. No.Rev.FigureAmendment 58 December 2005 5.4-20Form No. 960690FH LDCN-05-000 BHPEfficiency HeadNPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 1020 30 40 50 60 70 80901234 5 6 78010 2030400510Brake Horsepower x 100 NPSH in FeetTotal Head in Feet x 100Efficiency, % 0 FigureAmendment 55 May 2001Form No. 960690Draw. No.Rev.960690.88Vessel Coolant Temperature Versus Time(Two Heat Exchangers Available) 5.4-21100F/hrAssumed FlushTime100F/hr212F600500 4003002001000012345678Hours After Control Rods InsertedVessel TemperatureVersus TimeTwo Exchangers Available Columbia Generating StationFinal Safety Analysis Report Vessel Water Temperature (°F) Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-22.1115M523-1Reactor Water Cleanup System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-22.28M523-2Reactor Water Cleanup System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Columbia Generating StationFinal Safety Analysis Report 5.4-22.3M523-3Reactor Water Cleanup System - P&IDRev. 10FigureDraw. No. Form No. 960690ai

Draw. No.

Rev. Figure Amendment 55 May 2001FigureForm No. 960690Draw. No.Rev.960690.92Vessel Coolant Temperature Versus Time(One Heat Exchanger Available) 5.4-25Hours After Control Rods Inserted012345678 0100200 300 400 500600100F/hrAssumed FlushTime212FColumbia Generating StationFinal Safety Analysis Report Vessel Water Temperature (°F) COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS

Section Page LDCN-13-052 6-i 6.1 ENGINEERED SAFETY FEATURE MATERIALS................................ 6.1-2 6.1.1 METALLIC MATERIALS ............................................................ 6.1-2 6.1.1.1 Materials Selec tion and Fabri cation ................................................ 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 Cool ants .................................................................. 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 Suppr ession Containm ent ................................................. 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 Summary Evaluation ............................................................. 6.2-5 6.2.1.1.3.2 Containment Design Parameters ............................................... 6.2-5 6.2.1.1.3.3 Accident Response Analys is .................................................... 6.2-6 6.2.1.1.3.3.1 Recirculation Line Rupture .................................................. 6.2-7 6.2.1.1.3.3.1.1 Assumptions for Reactor Bl owdown ..................................... 6.2-7 6.2.1.1.3.3.1.2 Assumptions for Containment Pressurization .......................... 6.2-9a 6.2.1.1.3.3.1.3 Assumpti ons for Long-Term Cooling .................................... 6.2-9a 6.2.1.1.3.3.1.4 Initia l 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 Standby A ccident 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 Contai nment Response ..................................................... 6.2-16 6.2.1.1.3.3.5.3 Recovery Operations ........................................................ 6.2-17 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-10-004, 15-011 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-Pr essure Core Spray ......................................................... 6.3-5 6.3.1.2.2 Low-Pressu re Core Sp ray ......................................................... 6.3-5 6.3.1.2.3 Low-Pressure Coolant Injection .................................................. 6.3-5 6.3.1.2.4 Automa tic Depressurizati on System ............................................. 6.3-6 6.3.2 SYSTEM DESIGN ...................................................................... 6.3-6 6.3.2.1 Schematic Piping and Instrumenta tion Diagrams ................................ 6.3-6 6.3.2.2 Equipment and Component Descrip tions .......................................... 6.3-6 6.3.2.2.1 High-Pressure Core Spray System ............................................... 6.3-6 6.3.2.2.2 Automa tic Depressurizati on System ............................................. 6.3-9 6.3.2.2.3 Low-Pressure Core Spray System ............................................... 6.3-9 6.3.2.2.4 Low-Pressure Cool ant 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 Cooling System Suc tion Strainers .......................... 6.3-14 6.3.2.3 Applicable Codes and Classifications .............................................. 6.3-18 6.3.2.4 Materials Specifica tions 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 ........................................ 6.3-22 6.3.3.5 Use of Dual Function Components for Emergency Core Cooling System .. 6.3-23 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 .......................................... 6.3-24 6.3.3.6.2 Loss-of-Coolant Accident Analysis Procedures and Input Variables ...... 6.3-25 6.3.3.6.2.1 LOCA Analysis Methodology, GE Hitachi Nuclear Energy ............. 6.3-26 6.3.3.6.2.2 DELETED ......................................................................... 6.3-26 6.3.3.6.2.3 LOCA Analysis Input Variables ............................................... 6.3-26 6.3.3.7 Break Spectrum Calculations ........................................................ 6.3-27 6.3.3.7.1 Break Spectrum Calculation, GE Hitachi Nuclear Energy .................. 6.3-27 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-10-004, 15-011 6-vii 6.3.3.7.2 D ELETED. .......................................................................... 6.3-27 6.3.3.8 Loss-of-Coolant Acci dent Analysis Conclusions ................................. 6.3-28 6.3.4 TESTS AND IN SPECTIONS ......................................................... 6.3-28 6.3.4.1 Emergency Core Cooling System Performance Tests .......................... 6.3-28 6.3.4.2 Reliability Tests and Inspections .................................................... 6.3-29 6.3.4.2.1 High-Pressu re Core Spray Testing ............................................... 6.3-29 6.3.4.2.2 Automatic Depressurization System Testing ................................... 6.3-29 6.3.4.2.3 Low-Pressure Co re Spray Testing ............................................... 6.3-30 6.3.4.2.4 Low-Pressure Cool ant Injection Te sting ........................................ 6.3-30 6.3.5 INSTRUMENTATION REQUIREMENTS ........................................ 6.3-30 6.

3.6 REFERENCES

........................................................................... 6.3-31 

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 En velope ..................................... 6.4-2 6.4.2.2 Ventilation Sy stem Design ........................................................... 6.4-2 6.4.2.3 Leakti ghtness ........................................................................... 6.4-2 6.4.2.4 Interaction With Other Zones and Pressure Containing Equipment .......... 6.4-2 6.4.2.5 Shielding Design ....................................................................... 6.4-3 6.4.3 SYSTEM OPERATIO NAL 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 Ch lorine .............................................................................. 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 COLUMBIA GENERATING STATION Amendment 60  FINAL SAFETY ANALYSIS REPORT December 2009   Chapter 6

ENGINEERED SAFETY FEATURES

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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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF TABLES (Continued)

Number Title Page LDCN-10-004, 15-011 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 DELETED

6.3-2a Plant Operational Parameters ................................................. 6.3-38

6.3-2b Fuel Parameters ................................................................. 6.3-39

6.3-2c ECCS Parameters ............................................................... 6.3-40

6.3-3 Single Failure Considered in ECCS Performance Evaluation ........... 6.3-44

6.3-4 DELETED

6.3-4a Event Scenario for 100% DBA Recirculation Suc tion Line Break HPCS DG Failure (App endix K) ............................................ 6.3-45 6.3-4b Event Scenario for 0.07 ft 2 Recirculation Suction Line Break HPCS DG Failure (App endix K) ............................................ 6.3-46 6.3-5 ECCS Performance An alysis Results ........................................ 6.3-47

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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES

Number Title 6-xii 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xiii 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xiv 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 Pressure 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 Arrange ment 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xv 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 Penetrations X-46 and X-101

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

6.2-52 Isolation Valve Arra ngement 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xvi 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

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT 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 800F by means other than welding or th ermal cutting are either resolution COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment58 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 hours post-accident. This action is disc ussed in the dose consequences analysis in Section 15.6.5. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.1-1 Engineered Safety Features Systems and Related Systems Component Materials (Continued) Component Form Material Specification (A/SA) a LDCN-14-018 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

Forging Carbon steel 105 or 105 Grade 2 Disc Casting Carbon steel 216 Grade WCB Casting Alloy steel 217 Grade WC6 Forging Carbon steel 105 or 105 Grade 2 Stem Bar Stainless steel 479 Type 410 Bar Stainless steel 461 Grade 630 Studs Bar Alloy steel 193 Grade B7 Nuts Bar Alloy steel 194 Grade 7

Bar Carbon steel 194 Grade 2H 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 Grade 630 Forging Stainless steel 182 Grade F6a Stud Bar Alloy steel 540 Grade B23 Bar Alloy steel 193 Grade B7 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.1-1 Engineered Safety Features Systems and Related Systems Component Ma terials (Continued) Component Form Material Specification (A/SA) a LDCN-14-018 6.1-9 Isolation valves (Continued) Nuts Bar Alloy 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 Bar Alloy steel 194 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 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

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 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 COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-03-003 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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.

In addition to the power uprate analysis (Reference 6.2-35), an additional containment analysis was performed (Reference 6.2-42) to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS). Tables 6.2-2 through 6.2-6 detail this analysis. The power uprate analysis remains bounding. Additionally, Reference 6.2-42 documents an analysis to address General Electric (GE) Safety Communication (SC) 06-01. GE SC 06-01 indicated that long-term low-pressure injection with all pumps operating and one RHR heat exchanger inoperable ma y impact suppression pool temperature. The analysis c oncludes that, when only one RHR heat exchanger is operable, two LPCI pumps and the LPCS pump must be secure

d. The timing for this action is detailed in Reference 6.2-42. This action is required to not exceed the bounding suppression pool temperature of 204.5°F.

6.2.1.1.3.3 Accident Response Analysis. The containment f unctional 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-7 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 uprat e to 3486 MWth (References 6.2-32, 6.2-33, and 6.2-35), only the recirculation line rupture (Case C), the bounding event fo r containment response, was reanalyzed. The contai nment response analyses are not cycle specific nor are they part of the analyses performed to support core reload analyses. For further discussion, see Sections 6.2.1.1.3.3.4 and 6.2.1.1.3.3.5 . For the containment analysis performed to eval uate reduced ECCS flow rates (RHR/LPCI and LPCS), the recirculation line rupture (Cases A, B, and C) were re-analyzed. For further discussion, see Section 6.2.1.1.3.2 . 6.2.1.1.3.3.1 Recirculation 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 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 re sponse 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 containment analysis perfor med to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS), the re actor is operating at 3556 MWt.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-8 This power corresponds to 102% of 3486 MWt. ANS 5.1-1979+2 with GE Service Information Letter (SIL) 636 is used to determine decay heat release.

4. For the nonlimiting events which we re not reanalyzed for power uprate, the standby service water (SW) te mperature is assumed to be 95F, which exceeds the maximum expected temperature. For power uprate, a less conservative value of 90F was assumed. For the containment analysis performed to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS), 85°F is assumed for the first 10 hours and 90°F thereafter.

5. The suppression pool mass is at the low water level.

6. 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 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 depressuriza tion period. The resulting high-energy COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-9 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 550F is released to the vessel fluid along with the stored energy in the vessel and internals as vessel fluid temperatures decrease below approximately 550F 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-energy water into the drywe ll. For the containment analysis performed to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS), MSIV closure was assumed to st art at 0 seconds after the accident.

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.

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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-9a 6.2.1.1.3.3.1.2 Assumptions fo r 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 Assumptions 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;

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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.

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 even ts 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, 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-14 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 330F. 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 recirculation 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 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-15 6.2.1.1.3.3.3 Hot Standby Accide nt Analysis. This section is not applicable to BWR-5. 6.2.1.1.3.3.4 Intermediate Size Breaks. The failure of a recirc ulation 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 submer gence 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 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. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-16 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 Containment 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 lead to a high drywell pressure COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-040 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 C onsideration. The energy balan ce 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 simultaneous operation of both containment spray loops afte r large and small-break LOCA could be a limiting transient for the containmen t negative pressure. However this event is based on more than one single failure or operator error and neglects the consideration for adequate core cooling by using both RHR loops. Using the single-failure criterion and considering the need for adequate core cooli ng following a large-break LOCA, 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 vacuum breaker to open. This scenario is nonlimiting with respect to floor uplift or negative pressure. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-040 6.2-19 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 negative pressure after large and small-line-break LOCA made the following conservative assumptions:

a. Maximum spray flow of 8200 gpm (combined drywell and wetwell flow),

b. 100% spray efficiency,

c. 50F 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.

g. Reactor Power is 3702 MWth.

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 . 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) .

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 ft2, 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 117F, 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, COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 6.2-25 6.2.1.1.8.3 Post-LOCA. The un it 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 and MELLLA 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 singl e 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 th e corresponding paramete rs with power uprate and MELLLA (Reference 6.2-32 and 3.6-24). Therefore, the ba sis for the subcompart ment pressurization loads is not affected by power uprate. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 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/ft2-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 and 6.2-42. The result of the case of a 60-node model of the shield wall annulus for pressure transient calculation was confirmed by the NRC, and the analysis was considered acceptable for the shield wall base design and th e design of the shield wall above the base, as stated in NRC letters (References 6.2-12 and 6.2-13). For the MELLLA evaluati on a 400-node model of the shield wall was analyzed and the results were bounded by the original 60-node model. (Reference 3.6-24). 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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;

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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 56F 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 the re actor power level specified in Table 6.2-4, 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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 accide nt period. These assu mptions conservatively bound the heat sink temperature to which the containment heat is rejected. In addition, the RHR heat exchanger is assumed to be in a fully fouled cond ition at the time the accident occurs. This conservatively minimizes the heat exchanger heat removal capacity. The resultant suppression pool temperature transient is described in Section 6.2.1 and is shown in Figure 6.2-12 . Even with the degraded conditions outlined above, the maximum uprate temperature is 204.5F, which is less than the original 220°F. The results of the containment analysis performed to evalua te reduced ECCS flow rates (RHR/LPCI and LPCS) are bounded by the power uprate analysis. 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 the RHR heat exchanger. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-35a GE SC 06-01 addresses the unlikely event of an inoperable RHR heat exch anger with all ECCS pumps running post-accident. This event was evaluated in Reference 6.2-42 and found that if all four low pressure pumps (LPCS, 3-LPCI) were injecting post-accident the suppression pool bounding temperature may be exceeded. The timi ng for this action is de tailed in Reference 6.2-42. In the event of an inoperable RHR heat exchanger, operating pro cedures ensure that the three low pressure pumps not providing ope rational heat exchanger flow will be secured before suppression pool temperature limits are exceeded. It can be concluded that the conservative evaluation demonstrates that the RHR system in the suppression pool cooling mode limits the pos t-DBA containment te mperature transient. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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).

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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; COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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, COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-066 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 Conclusion on Cr iterion 56. To ensure protecti on against 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 requirement s, the pressure reta ining 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 Evaluation Against Criterion 57. Lines forming a closed system outside the primary reactor containment must have one isolation valve outside if the system boundary penetrates the containment. All closed system s outside primary containment at Columbia have at least one isolation valve if they penetrate primary containment which provides isolation capabilities in accordance with Criterion 57. 6.2.4.3.2.4 Evaluation Against Regulatory Guide 1.11, Revisi on 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 . COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 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 less than 2000F. At this temperature virtua lly 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 . COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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).

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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)," dated 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 Letter, JW Clifford (NRC) to JV Parrish (Washington Public Power Supply System), "Issuance of Amendment for the Washington Public Power Supply System Project No. 2 (TAC NOS. M87 076 and M88625)," da ted May 2, 1995.

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. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052, 10-004, 15-011 6.2-68 6.2-36 Deleted.

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."

6.2-42 GE Hitachi Nuclear Energy, "Tec hnical Specification Change Support for RHR/LPCI and LPCS Flow Rate Long -Term LOCA Containment Response and ECCS/Non-LOCA Evaluations," NEDC -33813P, Class III (Proprietary), Revision 2, September 2013.

6.2-43 ARTS/MELLLA Task T0401A (CVI-1133-00,20) "Subcompa rtment (Annulus) Pressurization Loads-Mass and Energy Releases."

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-69 Table 6.2-1

Containment Design Parameters

Drywell Suppression Chamber A. Drywell and Suppression Chamber

1. Internal design pr essure, 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 ft3 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 1.995 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)

LDCN-13-052 6.2-70 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 Reduced ECCS Flow Case C A. Drywell Spray System

1. Number of pumps 2 2 1 N/A N/A 2. Number of lines 2 2 1 N/A N/A 3. Number of headers/line 1 1 1 N/A N/A 4. Spray flow rate, gpm/pump 7450 6713b,d 6713b N/A N/A 5. Spray thermal efficiency, % 100 100 100 N/A N/A B. Suppression Pool Spray

1. Number of pumps 2 2 1 N/A N/A 2. Number of lines 2 2 1 N/A N/A 3. Number of headers/line 1 1 1 N/A N/A 4. Spray flow rate, gpm/pump 450 353b 353b N/A N/A 5. Spray thermal efficiency, % 100 100 100 N/A N/A C. Containment Cooling System

1. Number of pumps 2 2 1 1a 1 2. Pump capacity, gpm/pump 7900 7067b 7067b 7067b 6713 LDCN-13-052 6.2-71 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-2 Engineered Safety Systems Information for Containment Response Analyses (Continued)

Value Used in Containment Analysis Full Capacity Case A Case B Case C Reduced ECCS Flow Case C

3. Heat Exchangers RHR system inverted U tube, single pass shell, multi pass tubes, vertical mounting

a. Number 2 2 1 1a 1 b. Heat transfer area, ft 2/Unit 7641 7641 7641 7641 7641 c. Overall heat transfer coefficient, Btu/hr ft 2 F 195(fouled) 400(clean) 195 195 195 195 d. Standby service water flow rate per exchanger, gpm 7400 7400 7400 N/A N/A e. RHR heat exchanger K value Btu/sec-°F 414(fouled) 849(clean)

N/A N/A 289 f f. Design service water temperature minimum, °F maximum, °F 32°F 85°F 95b 95b 90 f g. Containment heat removal capability per loop, using 85°F service water and 165°F pool

temperature; Btu/hr 83.23 x 10 6 LDCN-13-066, 13-052 6.2-71a COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-2 Engineered Safety Systems Information for Containment Response Analyses (Continued ) Value Used in Containment Analysis Full Capacity Case A Case B Case C Reduced ECCS Flow Case C D. ECCS Systems

1. High pressure core spray (HPCS)

a. Number of pumps 1 1 1 1a 1 b. Number of lines 1 1 1 1a 1 c. Flow rate, gpm 6350 6250 6250 6250a 6250 2. Low pressure core spray (LPCS)

a. Number of pumps 1 1 0 0a 0 b. Number of lines 1 1 0 0a 0 c. Flow rate, gpm 6350 6250 0 0a 0 3. Low-pressure coolant injection (LPCI)

a. Number of pumps 3 1e 1 1a 1 b. Number of lines 3 1e 1 1a 1 c. Flow rate, gpm 1 pump 7450c 7067b 7067b 7067a,b 6713 LDCN-13-052 6.2-71b COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-2 Engineered Safety Systems Information for Containment Response Analyses (Continued)

Value Used in Containment Analysis Full Capacity Case A Case B Case C Reduced ECCS Flow Case C

4. Residual heat removal (RHR)

a. Pump flow rate: shell side 7450 0 0 0 0 tube-side 7400 0 0 0 0 b. Source of cooling water Standby service water E. Automatic Depressurization System

1. Total number of safety/relief valves 18a 2. Number actuated on ADS 7a a No change due to uprate. Reference 6.2-35 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. f SW temperature is 85°F for 10 hours then 90°F thereafter; RHR heat exchanger K value varies from 284.5 to 288.8 Btu/sec-°F with suppression pool temperature.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-72 Table 6.2-3

Accident Assumptions and Initial Conditions for Recirculation Line Break

A. Effective accident break area (total), ft 2 3.106/3.189 d B. Components of ef fective break area: 1. Recirculation line suction nozzle area, ft 2 2.508a 2. RWCU cross tie line ft 2 0.078a 3. Jet pump nozzles, ft 2 0.520a C. Break area/vent area ratio 0.0105/0.0103 d D. Primary system energy distribution b 1. Steam and liquid energy, 10 6 Btu 414/361d 2. Sensible energy, 10 6 Btu a. Reactor vessel 106.1/220 d b. Reactor internals (less core) 58.6e c. Primary system piping 34.6e d. Fuel (c) E. Assumptions used in pressure transient analysis 1. Feedwater flow coastdown time 39.6 2. MSIV closure time (sec) 3.5/3.0 d 3. Scram time (sec) <1a 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 Second value represents conserva tive value used in analysis. e Reactor vessel sensible ener gy includes reactor internals (l ess core) and primary system piping. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-73 Table 6.2-4

Initial Conditions Employed in Containment Response Analyses

Original Rated Power Cases Uprated Power Reduced ECCS Flow A. Reactor coolant system (at 105% of rated steam flow and at normal liquid levels)

1. Reactor power level, MWt 3462 3702 3556 2. Average coolant pressure, psig 1020 1020 1020 Peak coolant pressure, psia 1055 1055 1055 3. Average coolant temperature, °F 547 551 551 4. Mass of reactor coolant system liquid, lb 676,700 634,300 634,300 5. Mass of reactor coolant system steam, lb 24,900 24,740 24,740 6. Volume of water in vessel, a ft3 12,743 13,282 13,282 7. Volume of steam in vessel, b ft3 10,167 10,397 10,397 8. Volume of water in recirculation loops, ft 3 670 (a) (a) 9a. Volume of water in feedwater line, c ft3 543 9b. Mass of water in feedwater line, lb 693,034 693,034 10. Volume of wate r in miscellaneous lines,c ft3 121 (a) (a) 11. Total reactor coolant volume, ft 3 23,580 23,679 23,679 12. Stored water

a. Condensate storage tanks, gal (min) 135,000 N/A N/A b. Fuel storage pool, gal 350,000 N/A N/A COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-74 Table 6.2-4

Initial Conditions Employed in Containment Respons e Analyses (Continued) Original Rated Power Cases Uprated Power Reduced ECCS Flow Drywell/ Suppression Chamber Drywell/ Suppression Chamber Drywell/ Suppression Chamber B. Containment

1. Pressure, psig 0.7/0.7 2.0/2.0 2.0/2.0 2. Inside temperature, °F 135/90 135/90 150/90 3. Outside temperature, °F NA/NA NA/NA NA/NA 4. Relative humidity, % 50/100 50/100 20/100 5. Service water temperature, °F 95/95 90/90 (d)/(d) 6. Water volume, ft 3 NA/ 107,850 NA/ 107,850 NA/ 107,850 7. Vent submergence, ft NA/12 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 85°F for 10 hours then 90°F thereafter

LDCN-13-052 6.2-75 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Original Rated Power Uprated Power Reduced ECCS Flow Accident Parameters Recirculation Line Break a Steam Line Breakb Recirculation Line Break Recirculation Line Break

1. Peak drywell pressure, psig 34.69 34.0 37.4 c,d 35.3c 2. Peak drywell diaphragm floor differential pressure, psid 19.39 19.1 21.7 (f) 3. Time (S) of Peak Pressures, Sec. 19.0 12.0 11.9 (g)

4. Peak drywell temperature, °F 280.2 328 283 c 281c 5. Peak suppression chamber pressure, psig 27.3 31.3 30.3 6. Time of peak suppression chamber pressure, sec. 55 55 139 (g)

7. Peak suppression pool temperature during blowdown, °F (~100 sec.) 140 140 146 148.3

8. Peak suppression pool temperature, long term, °F 220 220 204.5 203.8

9. Calculated drywell margin, %

e 22.9 24.5 16.9 (f)

10. Calculated suppression chamber margin,

%e 38.6 38.0 30.4 24.6 11. Calculated deck differential pressure margin, % 22.44 23.6 13.2 (f)

12. Energy released to containment at time of peak pressure, 10 6 Btu 260 204 174 (f)

13. Energy absorbed by passive heat sinks at time of peak pressure, 10 6 Btu 0 0 0 0 Table 6.2-5 Summary of Accident Re sults for Containment Response to Limiting Line Breaks

LDCN-13-052 6.2-75a COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-5 Summary of Accident Results for Containment Response to Limiting Li ne Breaks (Continued) 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 testin g was conservatively c hosen to be 38 psig. e (Design Pressure - Maximum Calculated Pressure) Design Pressure f Parameter determined in short-term containment analysis (Reference 6.2-35) and not updated based on the long term analysis presented in Reference 6.2-42. g Values are proprietary. See Reference 6.2-42.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-76a Table 6.2-6 Loss-of-Coolant Accident Long-Term Primary Containment Response (Continued) 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) C Reduced ECCS Flow 3556 MWt Before 600 seconds After 600 seconds 2/0 1/0 2 2 0 0 6250 6250 13,426/0 6713/0 203.8 15.9 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 106 107 x 10 6 107 x 10 6 40 x 106/66.6 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 106 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 106 629 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 ---- ----

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 ---- ----

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 102 0.0381 0.03436 103 0.0223 0.01956 104 0.0119 0.01012 105 0.00668 0.00546 106 0.00267 3 x 106 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 106 ft3; 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 . COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015

LDCN-15-038 6.2-84a Table 6.2-14 Containment Penetrations Subject to Type B Tests (continued) Penetration Number Type Service Comments II. Personnel And Equipment Access Penetrations (continued) X-3 CEP-V-2A Inboard flange X-53 CSP-V-2 Inboard flange X-66 CSP-V-4 CSP-V-5 Inboard flanges X-67 CSP-V-4A CSP-V-6 Inboard flanges X-119 CSP-V-9 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 2011LDCN-10-028 6.2-86CIA 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-036 6.2-90 Rad 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 globe 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 globe 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-036 6.2-91 PASS DW atm 80b 6.2-57 56 B PSR-V-X80-1 SO globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe O ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 50, 56, 64, 48a RCC 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 globe O 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-09-007 6.2-97 Table 6.2-16

Primary Containment Isol ation Valves (Continued)

ISOLATION SIGNAL CODES a Signal Description Ab Reactor vessel low-low water level (Trip level 2) Cb High radiation - main steam line Db Line break - main steam line (ste am line tunnel high temperature, high differential temperature or steam line high flow) Eb Reactor water cleanup system high diffe rential flow or hi gh blowdown flow Fb High drywell pressure Gb Low condenser vacuum Jb Line break in RWCU system - area high temperature or high differential temperature Kb 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] Lb 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) Mb Line break in RHR shutdown cooling (high suction flow) Pb Low main steam line pressure at turbine inlet (RUN mode only) Rb RHR equipment area high temperature or high differential temperature RM Remote manual switch located in main control room U High reactor vessel pressure

Vc 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

Zb 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. COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 positive closingSO Solenoid operated Location I inside containment O outside containment Power to Open/Close AC ac electrical power DC dc electrical powerEF excess flowpp process fluid overpressurization pro 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 steamW water Termination Zone CS condensate storage tan kRR reactor buildingRW radwaste buildingSB service buildingTB turbine building COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 lobe, 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 Electric, 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-040 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 50 Pool temperature, F N/A 50 3. Relative humidity, % 100 100 Spray temperature is equivalent to suppression pool temperature.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-040 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 1a 1a 0.57 0.55 1.38 0.61 1.88 1.11 (3) DBA 7 7 2 3 1a 2 0.55 0.67 0.71 0.81 1.21 1.31 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 (ft3) 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 (ft2) Inertia (L/A, ft-1) Form Loss Coefficient Friction Factor f KF* KR** 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. KF* = KForward KR** = KReverse

• Original rated power.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 (ft2) Inertia (L/A, ft-1) Form Loss Coefficient Friction Factor f KF* KR** 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. KF* = KForward KR** = KReverse

• Original rated power.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 seca - 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 hrb - 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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) q1 = 33,161 (t pcw-tair), for tair< tpcw q1 = 0, for t air > tpcw tpcw = 105°F constant tair, r = reactor building air temperature Normal equipment decay heat Electrical equipment (combined) q2 = 1475 (150e -T-tair), for tair < 150e-T q2 = 0, for t air > 150e-T Max. eq. surface

Temperature = 150°F

for T < 0 Piping (combined) q3 = 664 (182e -T -tair ), for t air < 182 e-T q3 = 0, for t air > 182e-T Max. eq. surface Surface temp= 182°F for t < 0 Emergency equipment Emergency lighting (t > 0 sec) q4 = 203,700 Standby gas treatment system (T > 34 sec) q5 = 8800 Emergency core cooli ng system (T > 30 sec) q6 = 4476 (t cw - tair), for tair < tcw q6 = 0, for t air > tcw T,hr tcw,* oF 0 95 2 180 50 143 100 132

• cw = cooling water COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 q7 = 299.2 (t pw-tair)4/3 tpw= pool water temp. oF Pool evaporation heat q8 = 1385.19 (t pw - tair)1/3 (Wps- Wair)p tpw = pool water temp. °F Wps = humidity ratio Saturated moist air Evaluated at t pw of wet surface (1bw/1ba) Wps = humidity ratio of moisture air (1bw/1ba)p = heat of vaporization (1bw/1ba) Infiltration air heat-up q9 = -0.24945 (t air - 100)> Structural steel heat-up q10 = - 11400 (t air - tsteel)4/3 tsteel = steel temp (°F) Total Q = q 1 + q2 + q3 + q4 + q5 + q6 + q7 +q8+ q9 +q10 Qq110101 Typical 24 in. Downcomer Vent with Jet Deflector 900547.40 6.2-1FigureAmendment 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" W121'-2"4"El. 501'-0" Saddle Clamps Downcomer Open End1'-1/4"1 1/4"1/2"Columbia Generating StationFinal Safety Analysis Report Diagram of the Recirculation Line Break Location 900547.36 6.2-2FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.CABRecirculation ReactorVesselPoint Of Critical Flow A. Recirculation Line B. Cleanup Line C. Combined Area of All Jet Pump Nozzles Associated with the

Broken Loop Recirculation LoopPumpTo Reactor Water

Cleanup System Columbia Generating StationFinal Safety Analysis Report Pressure Response for Recirculation Line Break(Initial Containment Pressure 2 psig) 900547.37 6.2-3FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.7550 250010203040Drywell PressureWetwell PressureTime (Seconds) Pressure (Pisa) Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Temperature Response for Recirculation LineBreak (Initial Containment Pressure 2 psig) 960222.02 6.2-401020304050150250350Time (Seconds)Drywell Temperature Temperature (degrees F)Wetwell Temperature Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev. Drywell Floor P Response for Recirculation Line Break (Initial Containment Pressure 2 psig) 960222.03 6.2-50102030400153045Time (Seconds) Pressure Difference (psid) Drywell-Wetwell Columbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Containment Vent System Flow Rate for Recirculation (Initial Containment Pressure 2 psig) 960222.04 6.2-60102030400123x104Time (Seconds) Vent Flow Rate (lb/seconds) AirVaporLiquidColumbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Containment Pressure Response Cases A, B, and C - Original Rated Power 960222.67 6.2-7Time (Seconds) Containment Pressure (psig) 40200102103104105106a) 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 3010cbaColumbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Drywell Temperature Response Cases A, B, and C - Original Rated Power 960222.26 6.2-8a) 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 abc400300200 1000101102103104105Time (Seconds) 106Columbia Generating Station Final Safety Analysis Report Drywell Temperature (°F) FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Suppression Pool Temperature Response, Long-Term Response - Original Rated Power 960222.27 6.2-9ab.c4003002001000101103104105106Time (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) FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Containment Pressure Response - Case C Uprated Power 960222.05 6.2-100204060Pressure (psia) Time (Seconds) Drywell Pressure Wetwell Pressure Drywell Pressure Wetwell Pressure 101102103104105Columbia Generating Station Final Safety Analysis Report FigureAmendment 57 December 2003 Form No. 960690 Draw. No. Rev.Drywell Temperature Response - Case C Uprated Power 960222.06 6.2-11101100200300400Time (Seconds) Drywell Airspace Temperature Temperature (Degrees F) 102103104105Columbia Generating Station Final Safety Analysis Report LDCN-02-000 FigureForm No. 960690 Draw. No. Rev.Suppression Pool Temperature Response - Case C Uprated Power 960222.07 6.2-120100200300Time (Seconds) Temperature (Degrees F) Suppression Pool Temperature 101102103104105Columbia Generating Station Final Safety Analysis Report Amendment 57 December 2003 LDCN-02-000 FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Residual Heat Removal Rate 960222.15 6.2-13050100Time (hour) 12525750248101216182022242628303234363840424448 61501752002 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) FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Effective Blowdown Area Main Steam Line Break 960222.28 6.2-1443 2 1 0Time (Seconds) Flow Area (Ft 2)10030050060040020005Columbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Bounding Pressure Response - Main Steam Line Break Original Rated Power 960222.30 6.2-15Pressure (psig) Wetwell30201000.1110102103Time (Seconds) Drywell40Columbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Bounding Temperature Response - Main Steam Line Break Original Rated Power 960222.29 6.2-16Wetwell30020010000.1110102103Time (Seconds) Temperature (°F) DrywellColumbia Generating Station Final Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Pressure Response - Recirculation Line Break (0.1 ft2) Original Rated Power 960222.31 6.2-17Pressure (psig)Wetwell30201000.1110102103Time (Seconds) Drywell40Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Temperature Response - Recirculation Line Break (0.1 ft2) Original Rated Power 960222.32 6.2-18Temperature (Degrees F)Wetwell300200 10000.1110102103Time (Seconds) Drywell400Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Schematic of ECCS Loop 900547.39 6.2-19ReactorVesselSuppression Pool MWshsmDohDmsoRHR HeatExchanger hc, meccsqHxPump= 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 mDohDmsomeccsqHxhcMWshsqDqeColumbia Generating StationFinal Safety Analysis Report Allowable Leakage Capacity (A/ K ft 2)FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Allowable Leakage Capacity 960222.39 6.2-20( )ADBA2ADBA0.400.35 0.30 0.25 0.20 0.15 0.10 0.0500.41.02.03.04.0Primary System Break Area (ft 2)AKSColumbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Containment Transient for Maximum Allowable Bypass Capacity A x = 0.050 960222.38 6.2-21100100010,000500400300200100070(45)60(35)50(25)40(15)30(15)20Time (seconds) abdca 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. Timeduringwhichdrywellspraysmust beactivated (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 FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Containment Transient for A/ K = 0.0045 ft 2960222.37 6.2-22100100010,000500400 300200 10007060 504030 20Time (seconds) Pressure (psia)Containment Vessel Design Pressure abdca 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 20.5"Venting Through Bulkhead Plate 920843.15 6.2-24FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.21.25"AllDrawingsnot toScaleBlindFlange20.5"FanVentPathVentPathVentilation Supply Duct Azimuth195, 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 0315255195180Vent135751514.29'1.36'Columbia Generating StationFinal Safety Analysis Report Absolute Pressure in Upper Head Region andLower Region from 6 in. RCIC Line Break920843.11 6.2-25FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.28242016128 40Absolute 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) 00.51.01.52.0Time, 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 6.2-26FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.706050403020100Absolute 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) 00.51.01.52.0Time, Seconds Absolute Pressure, psia Columbia Generating StationFinal Safety Analysis Report Downward Pressure Differential Across BulkheadPlate from 6 In. Line Break 920843.13 6.2-27FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.1412108 642000.51.01.52.0Time, 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 6.2-28FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.1412108 642000.51.01.52.0Time, Seconds Differential Pressure, psiUpward Pressure Differential Across Bulkhead Plate from a 24 Inch Recirculation Line Break Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Recirculation Break Blowdown Flow Rates Liquid Flow - Short-Term Original Rated Power 960222.10 6.2-29020401201400102035Time (Seconds) Vessel Liquid Blowdown Flow Rate (lb/sec x 1E3) 60801003025515Columbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Recirculation Break Blowdown Flow Rates Steam Flow - Short-Term Original Rated Power 960222.11 6.2-300204012014001.02.03.5Time (Seconds) Vessel Steam Blowdown Flow Rate (lb/sec x 1E3) 60801003.02.50.51.5Columbia Generating Station Final Safety Analysis Report Main Steam Line Break Blowdown Flow Rates FigureAmendment 53November 1998 Form No. 960690 Draw. No. Rev.960222.36 6.2-31051015202530354045505560 01 2 3 4Liquid Flow Steam Flow Time (Seconds) Vessel Flow Rates (lb/sec x 10 4)Columbia Generating Station Final Safety Analysis Report Post-LOCA Time (sec) 6.2-34920843.17Long-Term Post-LOCA Secondary ContainmentTemperature Transient Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 59 December 2007 Form No. 960690FH LDCN-05-009 150140130120100908070102103104105106107101ECCS Pump Rooms Bulk Reactor Bldg Refuel Floor110Temperature (F) 6.2-35920843.16Short-Term Post-LOCA Secondary ContainmentPressure Transient Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 59 December 2007 Form No. 960690FH LDCN-05-009 14.7414.7214.70 14.6814.6614.6414.6214.6014.5814.5614.541ECCS Pump Rooms Atmospheric PressureBulk Reactor Bldg Refuel FloorPost-LOCA Time (sec) 102103104105106101Pressure (psia) Notes on Type C Testing 920843.20 6.2-36FigureForm 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 6.2-37FigureForm 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 AOAOMOMOMOCSP-V-1CSP-V-3CSP-V-2 CSP-V-4For X-66 Only See Fig. 6.2-52 X-53 (Drywell)X-66 (Wetwell) PurgeSupplyTCN2 SupplyCSP-V-97 CSP-V-98CSP-V-96 CSP-V-93SOSORFW-V-65BRFW-V-32BRWCU-V-40RFW-V-65ARFW-V-32A X-17BRFW-V-10B TCX-17ARFW-V-10A TCTCTCColumbia 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 6.2-38FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 1 on Figure 6.2-36 RRC Pump Seal PurgeContainment Instrument Air MONote: See Note 1 on Figure 6.2-36 MOCIA-V-30ACIA-V-30BCIA-V-20CIA-V-31A CIA-V-31BCIA-V-21TCTCX-89BX-91 X-56DrywellRRC-V-16A,B TCTCRRC-V-13A,B X-43A,BDrywellColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-117, X-118 and X-77Aa 920843.21 6.2-39Note: See Note 1 on Figure 6.2-36 Note: See Note 5 on Figure 6.2-36 X-77AaRRC-V-19TCTCSample PointRRC-V-20WetwellMOStructural SectionTCTCX-117X-118RHR-RV-1A,BRHR-RV-30(X-118 Only) MOMOMORHR-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.FigureForm No. 960690FH LDCN-08-028 RCC Sample Line RHR Steam Lines LCDeactivated 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 6.2-40FigureAmendment 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-21TCX-45Notes: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 AOMORCIC-V-13RCIC-V-65 X-2RCIC-V-66 TCMORCIC-V-63 LCMORCIC-V-8To MS Line MORCIC-V-76RCIC-V-742 LCSamplePointTCTCMORHR-V-23RPVTCDrywellColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-49, X-63, X-26 and X-22 950021.13 6.2-41FigureForm No. 960690FH LDCN-08-028Draw. No.Rev.MONote: See Note 4 on Figure. 6.2-36 MS Drain Line MOMOMOMS-V-19MS-V-16X-22TCX-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 TCX-49X-63X-26WetwellHPCS-RV-14 LPCS-RV-18RHR-RV-25CHPCS-RV-35 LPCS-RV-31RHR-RV-88C RHR Loop C OnlyHPCS-V-23LPCS-V-12RHR-V-21Columbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 6.2-42920843.08 Isolation Valve Arrangement for Penetrations X-11A and X-11B Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 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,BMORHR-V-17A,B TC Isolation Valve Arrangement for PenetrationsX-65, X-25A and X-25B 920843.09 6.2-43FigureForm No. 960690FH LDCN-08-028Draw. No.Rev.Note: See Note 2 on Figure 6.2-36RHR Wetwell SprayWetwellRCIC Pump Min. Flow MONote: See Note 5 on Figure 6.2-36RCIC-V-19 TCX-65MORHR-V-27A, B X-25AX-25BTCLoop A OnlyTCColumbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 Isolation Valve Arrangement for Penetration X-100 920843.10 6.2-44FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.WetwellSuppression Pool Cleanup Suction Line MONote: See Note 4 on Figure 6.2-36FPC-V-154 TCX-100MOFPC-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 6.2-45FigureAmendment 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 RPVX-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 AOAOCEP-V-1A CEP-V-3AAOAOCEP-V-2B CEP-V-4BCEP-V-1B CEP-V-3BTCForm 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 6.2-46MONote: See Note 1 on Figure 6.2-36 for X-23 And X-24 X-20X-14MORHR-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-20OnlyAOEDR-V-20AOX-23WetwellTCAOFDR-V-4AOX-24WetwellFDR-V-15L.O.FDR-V-3EDR-V-19TCTCNote: See Notes 1 (X-20 Only), and 4 (X-14 Only) on Figure 6.2-36 TCTCTCDrywellColumbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 58 December 2005 Form No. 960690FH LDCN-05-007 EDR-V-18L.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 6.2-47FigureForm 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 RPVMORHR-V-42 (A,B,C)HPCS-V-4LPCS-V-5RHR-V-41 (A,B,C)HPCS-V-5LPCS-V-6X-12A,B,C X-6 X-8TCTCPrimary Containment "Drywell" TCDW-V-156LCDW-V-157LCNote: 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 6.2-48FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.MORHR-V-53A,B Note: See Note 2 on Fig. 6.2-36 TCRHR SHUTDOWN COOLING RETURN X198B Only X-19A,BTCTCTCAODrywellRHR-V-50A,BRHR-V-123A,B E*SLC-V-4BNote: See Note 2 on Fig. 6.2-36 SLC SYSTEM INJECTION LINE X-13TCDrywellTCHPCS-V-76 RPVSLC-V-7E*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 6.2-49FigureForm 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)WetwellNote: See Note 5 on Fig. 6.2-36 X-33 X-31X-35X-32X-36X-34X-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 TCColumbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 Isolation Valve Arrangement for Penetrations X-46 and X-101 920843.26 6.2-50FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 4 on Figure 6.2-36 RCC Return Line X-46Suppression Pool Cleanup Return Line MOFPC-V-149 X-101TCTCNote: See Note 4 on Figure 6.2-36 MORCC-V-40RCC-V-219RCC-V-220RCC-V-221 MOFPC-V-156 MORCC-V-21Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-47 and X-48 950021.14 6.2-51FigureAmendment 61 December 2011 Form No. 960690FH LDCN-08-028Draw. No.Rev.MONote: See Note 5 on Figure 6.2-36 RHR Combined Return Line to Suppression Pool MOX-47, X48RHR-V-120 FDRSystem(X-47 Only) 2" Blind FlangeRHR-RV-88A,B MOSeeFigure 6.2-56 See Figure 6.2-39 Structural ConnectionRHR-RV-25A,BRHR-RV-5(X-48 Only)RHR-V-121 LCLCLCRHR-V-11A,BRHR-V-24A,B LORHR-V-172A,B X47 OnlyRHR-FCV-64 A,BValve Disk RemoveRHR-V-46A,BRHR-V-18A,B LOColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-66, X-67, X-119, X-64 920843.27 6.2-52FigureForm 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 AOX-64TCTCTCNote: See Note 5 on Figure 6.2-36 AOX-66X-67 X-119WetwellRCIC-V-28WetwellX-119 OnlyFor X-66 Only See 6.2-37For X-67 Only See 6.2-45CSP-V-5 CSP-V-6 CSP-V-9CSP-V-7 CSP-V-8CSP-V-10Columbia 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 6.2-53Amendment 56December 2001 FigureForm 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 N2/Air Supply for Testing Wetwell to Drywell Vacuum Breakers TCNote: See Note 8 on Figure 6.2-36WetwellDrywellLCNONCLCLCX-82ECAS-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 TestersLCLDCN-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 6.2-54FigureAmendment 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 TCNote: See Note 1 on Figure 6.2-36 DrywellPI-VX-250 PI-VX-256 SOPI-VX-251

PI-VX-257 SOX-85C X-29CX-85A X-29API-VX-253

PI-VX-259 SOPI-EFC-72F PI-EFC-73E X-72FX-73EColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-5 and X-93 920843.30 6.2-55FigureAmendment 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-5X-93MORCC-V-5MODrywellSA-V-109Pipe CapColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-4 and X-116 920843.31 6.2-56FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.RCIC Turbine Exhaust andTurbine Exhaust Vacuum Breaker Note: See Note 4 on Figure 6.2-36WetwellX-116X-4RCIC-V-68 MOWetwellMOMOSee Fig 6.2-51RCIC-V-40 TCTCColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-73F, X-77Ac, X-77Ad, X-80B 920843.32 16.2-57FigureAmendment 63December 2015 Form No. 960690 LDCN-15-036Draw. 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 SODrywellX-73FX-80BPSR-V-X73-1 PSR-V-X80-1 SOPSR-V-X77A2 PSR-V-X77A4 SOX-77AcX-77AdPSR-V-X77A1 PSR-V-X77A3 SOX-77Ac Jet Pump #10 Sample Line X-77Ad Jet Pump #20 Sample Line TCTCColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-82D, X-82F, X-83A, X-84F, X-88 920843.33 16.2-58FigureDraw. No.Rev.Note: See Note 1 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 1 on Figure 6.2-36WetwellX-83AX-84FX-82FPSR-V-X82-1 PSR-V-X88-1 SOX-82DX-88PSR-V-X82-2 PSR-V-X88-2 SOX-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 SOTC(X-88 Only)Wetwell(X-88 Only) Columbia Generating StationFinal Safety Analysis Report Amendment 63December 2015 Form No. 960690 LDCN-15-036 Isolation Valve Arrangement for Penetrations X-94 and X-95 920843.34 6.2-59FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.X-94X-95MWR-V-124 MWR-V-125 X Decon Solution Supply Header X Decon Solution Return Header DrywellT.C.Columbia Generating StationFinal Safety Analysis Report FigureAmendment 54 April 2000 Form No. 960690Draw. No.Rev.960222.68 6.2-60Columbia Generating StationFinal Safety Analysis Report DELETED(SHEETS 1 THROUGH 4) Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 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)200100030102103104105106107Service Water Temperature = 95FMinimum ECCS COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 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 evalua tion. Subsection 6.3.1 discusses the design bases. Subsection 6.3.2 describes the systems. Subsection 6.3.3 discusses the system res ponses 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. 6.3.1 DESIGN BASES AND 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) break 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.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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,

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-010, 03-003 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 system consists 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

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-010, 03-003 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 the reactor vessel press ure is less than the value in 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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,

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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 204.5F and bounding flowrates for the time of peak pool temperature. This is the bounding configuration for minimizing available NPSH. The analysis which established the 204.5F 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;

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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 90F. Standby servi ce water, which cools the RHR heat exchanger, is also at 90F. 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 90F to 204.5F, 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 204.5F 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 204.5F 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 hours) 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 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), Maximum Extended Load Line Limit Analysis (MELLLA), 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 accident (DBA) event. The NSSS vendor analyses are described in References 6.3-1, 6.3-2, 6.3-4, 6.3-5, and 6.3-7. 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 References 6.3-15 and 6.3-5. The GNF2 analysis confirms the small break of 0.07 ft 2 in the recirculation suction line as still limiting, with top peaked axial power shape and fa ilure of the HPCS diesel generator assumed. The GNF2 analysis is described in Reference 6.3-16. A summary description of the re load design basis LOCA analysis methods is provided in this section. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-21 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. 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 level 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.

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 . Criterion 4, Cool able Geometry "Calculated changes in core geometry shall be such that th e core remains amenable to cooling." Conformance to Criterion 4 is demonstrat ed by conformance 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." COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-22 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.

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 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.

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 operating parameters, fuel parameters and ECCS initiation parameters used in the LOCA analysis are provided in Tables 6.3-2a, 6.3-2b and 6.3-2c, respectively. The representative COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-23 sequences of events are presented in Tables 6.3-4a and 6.3-4b. 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.

6.3.3.5 Use of Dual Function Components 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.3-24 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 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-25 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 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 Anal ysis Procedures a nd Input Variables

The GE Hitachi Nuclear Energy ECCS-LOC A licensing evaluation methodologies are described in References 6.3-7 through 6.3-14. The GE14 analysis is documented in Reference 6.3-5 and 6.3-15, consistent with References 6.3-1 and 6.3-2. The GNF2 analysis is documented in Reference 6.3-16, consistent with References 6.3-1, 6.3-2 and 6.3-5. These vendor methodologies cover the time from the even t until the reactor has been reflooded. The NSSS vendor, GE, performed the long term ECCS evaluation, as described in Reference 6.3-7. The evaluation documents that the ECCS satisfy the requi rements describe d in Section 6.3.3.2. As documented in Reference 6.3-1, the reactor power uprate and the new fuel did not impact the conclusions reached in Reference 6.3-7. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-26 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, TASC, PRIME, and SAFER (References 6.3-7 through 6.3-14). Together, these models evaluate the short-term and long-term reactor vessel blowdown response to a pipe rupture, the subsequent co re 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 TASC model for calculating blowdown heat transfer and fuel dryout time. The TASC model completes the transient short-term thermal-hydraulic calculation for large recirculation line breaks. "TASC" is used to predict the time and locat ion 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 PRIME model provides the parameters to in itialize the fuel stored energy and fuel rod fission gas inventory at the ons et of a postulated LOCA for input to SAFER. PRIME also establishes the transient pelle t-cladding gap conductance for i nput to both SAFER and 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 Deleted. 6.3.3.6.2.3 LOCA Anal ysis Input Variables The significant input variables used by the LOCA codes are listed in Table 6.3-1, Table 6.3-2a and Table 6.3-2b. The limiting calculation was perfor med at 3629 MWt (104. 1% power) and 108.5 Mlb/hr (100% core flow), References 6.3-5 and 6.3-16. Alternate operating modes of SLO, increased core flow (ICF), reduced core flow (MELLLA) and reduced feedwater temperature (FFWTR/FWHOOS) have been confirmed as non-limiting. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-27 6.3.3.7 Break Spectrum Calculations

Break spectrum analyses have been performed to establish the limiting break for the CGS boiling water reactor BWR5 reactor system. Pr evious analyses by GE, the NSSS vendor have shown that a large pipe break in the recirculation line on the suc tion side of the recirculation pump is the most limiting break for a BWR5. The GE analysis incl udes breaks in both recirculation and non-recirculation piping. Figure 6.3-9 shows the original plant break spectrum analysis for initial core fuel. For reload fuel, the break spectrum is determined and documented in Reference 6.3-5 (MELLLA), 6.3-15 (GE14) and 6.3-16 (GNF2), consistent with the original plant break spectrum analysis in References 6.3-1 and 6.3-7. 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. 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 Calculati on, 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 0.07 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 are also performed with the limiting single failure. The 100%, 80%, and 60 % DBA cases also satisfy the Appendix K requirement for using th e Moody Slip Flow Model with three discharge coefficients of 1.0, 0.8, and 0.6, respectively. The limiting A ppendix K case for large break is the 100% DBA with top-peaked axial power shape and HPCS DG failure. The overall limiting LOCA is the small recirculation suct ion line break of 0.07 ft 2 for Appendix K assumptions with top peaked axial power shape and HPCS DG failure.

The analysis also considers the non-recirculati on line breaks (CS line, LPCI line and etc.) as well as alternate operating modes (MELLLA, IC F, FFWTR/FWHOOS and SLO) References 6.3-5, 6.3-15 and 6.3-16 documents all the analysis results.

6.3.3.7.2 Deleted.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-28 6.3.3.8 Loss-of-Coolant Accide nt Analysis Conclusions

The ECCS will perform the required design functions and comply with 10 CFR 50.46 acceptance criteria.

The limiting large break for two loop operation is the recircula tion suction line break of DBA with HPCS diesel generator failure at 104.1% rated power (3629 MWt)/100% rated flow conditions with a mid peaked axial power shape (References 6.3-5, 6.3-15 and 6.3-16). The overall limiting LOCA is the small reci rculation suction line break of 0.07 ft 2 for Appendix K and nominal assumptio ns, respectively, with high pr essure core spray diesel generator failure at 104.1% ra ted power (3629 MWt)/100% rated flow conditions and a top peaked axial power shape (References 6.3-5, 6.3-15 and 6.3-16). 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 (References 6.3-5, 6.3-15 and 6.3-16). Extended operation in the MELLLA domain is not analyzed for SLO. 6.3.4 TESTS AND INSPECTIONS

6.3.4.1 Emergency Core Cooli ng 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. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.3-29 6.3.4.2 Reliability Te sts 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 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. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.3-30 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.

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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-31 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 GE Hitachi Nuclear Energy Report 0000-0105-1741-R0, "E nergy Northwest Columbia Generating Station ARTS /MELLLA Task T0407: ECCS-LOCA Evaluations," October 2009.

6.3-6 Deleted.

6.3-7 General Electric Company, "General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10CFR50 Appendix K," NEDO-20566-A, September 1986.

6.3-8 "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-23785-1-PA, Revision 1, October 1984.

6.3-9 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 2, SAFER - Long Term I nventory Model for BWR Loss-of-Coolant Analysis," NEDE-2378 5-1-PA, Revision 1, October 1984.

6.3-10 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 3, SAFER/GESTR- Appli cation Methodology," NEDE-23785-1-PA, Revisi on 1, October 1984.

• psid - differential pressure be tween RPV and pump suction source.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-32 6.3-11 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 3, Supplement 1, Additional Information for Upper Bound PCT Calculation," NEDE-23785P-A, Revision 1, March 2002.

6.3-12 "TASC-03A A Computer Program for Transient Analysis of a Single Channel," NEDC-32084P-A, Revisi on 2, July 2002.

6.3-13 "Compilation of Improvements to GENE's SAFER ECCS-LOCA Evaluation Model," NEDC-32950P, Re vision 1, July 2007.

6.3-14 "The PRIME Model for Analysis of Fuel Rod Thermal-Mechanical Performance," Part 1 - Technical Bases - NEDC-33256P-A, Part 2 - Qualification - NEDC-33257P-A, and Part 3 Application Methodology - NEDC-33258P-A, Revision 1, September 2010.

6.3-15 "Columbia Generati ng Station GE14 ECCS-LOCA Evaluation," GE Hitachi Nuclear Energy, 0000-0090-6853-R0, February 2009.

6.3-16 "Columbia Generati ng Station GNF2 ECCS-LOC A Evaluation," 001N0373-R2, February 2015.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-066 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) 8100 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-38 Table 6.3-2a Plant Operational Parameters Parameter Nominal Assumption Appendix K Assumption Rated Case Core Thermal Power (MW) 3629 3702 Rated Case Core Flow (Mlbm/hr) 108.5 108.5 MELLLA Case Core Thermal Power (MW) 3629 3702 MELLLA Case Core Flow (Mlbm/hr) 93.04 93.04 ELLLA SLO Case Core Thermal Power (MW) 2684.2 2737.9 ELLLA 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) Feedwater temperature: Nominal - 65°F or 355°F, whichever is lower.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-39 Table 6.3-2b Fuel Parameters Parameter GE14 GNF2 PLHGR (kW/ft) - LOCA Analysis Limit - Appendix K

- Nominal 13.40 13.40 x 1.02 

12.80 14.40 14.40 x 1.02 13.75 MAPLHGR (kW/ft) - LOCA Analysis Limit - Appendix K - Nominal 12.82 12.82 x 1.02 12.24 13.78 13.78 x1.02 13.15 Peak Pellet Exposure (MWd/MTU) 16,000 14600 Initial Operating MCPR - LOCA Analysis Limit

- Appendix K 
- Nominal 1.25 1.25 ÷ 1.02 

1.25 + 0.02 1.25 1.25 x1.02 1.25 + 1.02 Fueled Rods per Assembly 92 92 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-40 Table 6.3-2c ECCS Parameters 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 which injection valve may open psig 336 f. Maximum delay time from pump start until pump is at rated speed sec 26 g. Maximum injection valve stroke time-opening sec 26 h. Delay time to process initiation signal sec 5

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-41 Table 6.3-2c ECCS Parameters (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 which injection valve may open psig 336 f. Maximum delay time from pump start until pump is at rated speed sec 7 g. Maximum injection valve stroke time-opening sec 22 h. Delay time to process initiation signal sec 5

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-42 Table 6.3-2c ECCS Parameters (Continued) High Pressure Core Spray (HPCS) System Variable Units Analysis Value a. Vessel Pressure at which flow may commence psid (vessel to source) 1160 b. Minimum rated flow a nd 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-43 Table 6.3-2c ECCS Parameters (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 below 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 5 e. 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-44 Table 6.3-3 Single Failure Considered in ECCS Performance Evaluation 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-45 Table 6.3-4a Event Scenario for 100% DBA Re circulation Suc tion Line Break HPCS DG Failure (Appendix K) Event GNF2 GE14 Time (sec) Time (sec) Break Occurs 0.00 0.0 Scram Initiated and Occurs 0.01 0.01 Level 1 Trip 4.88 4.97 Feedwater Flow Reaches Zero 4.00 5.00 First Peak PCT Occurs 6.90 5.50 Jet Pump Suction Uncovers 5.94 5.98 Main Steamline Flow Stops 6.66 6.14 Suction Line Uncovers 8.76 8.54 Lower Plenum Flashes 9.61 9.15 LPCS/LPCI IV Pressure Permissive Reached 30.53 30.45 LPCS Injection Occurs 57.53 57.45 LPCI Injection Occurs 61.53 61.45 Second Peak PCT Occurs 142.50 148.18

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-46 Table 6.3-4b Event Scenario for 0.07 ft 2 Recirculation Suction Line Break HPCS DG Failure (Appendix K) Event GNF2 GE14 Time (sec) Time (sec) Break Occurs 0.00 0.0 Scram Initiated and Occurs 0.01 0.01 Feedwater Flow Reaches Zero 4.00 5.00 Level 1 Trip 107.23 114.50 SRVs Open 170.02 178.47 Jet Pump Suction Uncovers 212.86 221.47 ADS Valves Open 232.23 239.50 Main Steamline Flow Stops 240.12 246.99 Lower Plenum Flashes 242.98 248.61 Suction Line Uncovers 366.89 369.46 LPCS/LPCI IV Pressure Permissive Reached 384.79 394.23 LPCS Injection Occurs 411.79 421.23 LPCI Injection Occurs 415.79 425.23 Peak PCT Occurs 445.67 450.81

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-47 Table 6.3-5 ECCS Performance Analysis Results Parameter GE14 Value GNF2 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) 106.2% rated power (3702 MWt) 78.5% rated power (2737.9 MWt) Core flow 100% rated flow (108.5 Mlb/hr) 57% rated flow (61.845 Mlb/hr) 100% rated flow (108.5 Mlb/hr) 57% rated flow (61.845 Mlb/hr) Limiting break 0.07 ft2 Recirculation suction line, HPCS DG failure 100% DBA Recirculation suction line, HPCS DG failure 0.07 ft2 Recirculation suction line, HPCS DG failure 100% DBA Recirculation suction line, HPCS DG failure Peak cladding temperature

(Appendix K) 1647°F 1210°F 1637°F 1316°F Licensing basis peak

cladding temperature 1710°F 1700°F Maximum cladding

oxidation 1% 1% Total core hydrogen

generation 0.1% 0.1%

FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Head Versus Low-Pressure Core Spray Flow used in LOCA Analysis 960222.13 6.3-1010002000600070000100200Flow (gpm)300040005000 30025050150Columbia Generating Station Final Safety Analysis Report Pressure Vessel Head Over Drywell (psid) FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Head Versus Low-Pressure Coolant Injection Flow used in LOCA Analysis 960222.14 6.3-2010002000600070000100200Flow (gpm)300040005000 25050150Columbia Generating Station Final Safety Analysis Report Pressure Vessel Head Over Drywell (psid) Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 06.3-3.1702E22-04,7,1High-Pressure Core Spray - Process DiagramRev.FigureDraw. No.

Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 6.3-4103M520High-Pressure Core Spray and Low-Pressure Core Spray Flow DiagramsRev.FigureDraw. No. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Head Versus High-Pressure Core Spray Flow used in LOC A Analysis960222.12 6.3-5010002000600070000400800Flow (gpm) Pressure Vessel Head Over Drywell (psid)300040005000 12001000200600Columbia Generating StationFinal Safety Analysis Report Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 6.3-6802E21-04,4,1Low-Pressure Core Spray - Process DiagramRev.FigureDraw. No. Typical 48 in. Diameter Strainer 920843.07 6.3-7FigureAmendment 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 6.3-8FigureAmendment 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 FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Peak Cladding Temperature and Maximum LocalOxidation Versus Break Area - Hanford Original Rated Power 960222.23 6.3-9Suction 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 0100020000.010.11.0Break Area (Square Feet) Peak Cladding Temperature (°Fahrenheit) 01020Maximum Local Oxidation (%) Columbia Generating StationFinal Safety Analysis Report COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-044 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 hours 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-044 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. In the event of a hazardous radio activity release, the operators may respond by closing the appropriate remote intake isolation valves. Portable breathing 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/m3 2-minute toxicity limit specified in Reference 6.4-4. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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). COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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).

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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;

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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 30C 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT 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 200F. The Preservice Inspection Program Plan (Reference 5.2-6) addresses 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Chapter 4 REACTOR TABLE OF CONTENTS

Section Page LDCN-02-022, 03-003 4-i 4.1 SUMMARY DESCRIPTION............................................................4.1-1 4.1.1 REACTOR VESSEL....................................................................4.1-1 4.1.2 REACTOR INTERN AL COMPONENTS..........................................4.1-1 4.1.2.1 Reactor Core...........................................................................4.1-2 4.1.2.1.1 General............................................................................... 4.1-2 4.1.2.1.2 Core C onfiguration.................................................................4.1-4 4.1.2.1.3 Fuel Assembly Description........................................................4.1-4

4.1.2.1.3.1 Fuel Rod...........................................................................4.1-4 4.1.2.1.3.2 Fuel Bundle........................................................................4.1-4 4.1.2.1.4 Assembly Support and Control Rod Location.................................4.1-5 4.1.2.2 Shroud...................................................................................4.1-5 4.1.2.3 Shroud Head and Steam Separators................................................4.1-6 4.1.2.4 Steam Dryer Assembly...............................................................4.1-6 4.1.3 REACTIVITY CO NTROL SYSTEMS..............................................4.1-7 4.1.3.1 Operation...............................................................................4.1-7 4.1.3.2 Description of Rods...................................................................4.1-7 4.1.3.3 Supplementary Reactivity Control..................................................4.1-9 4.1.4 ANALYSIS TECHNIQUES...........................................................4.1-9 4.1.4.1 Reactor Internal Components.......................................................4.1-9 4.1.4.1.1 MASS (Mechanical Analysis of Space St ructure)..............................4.1-10 4.1.4.1.1.1 Pr ogram Description.............................................................4.1-10 4.1.4.1.1.2 Program Version and Computer...............................................4.1-10 4.1.4.1.1.3 History of Use.....................................................................4. 1-10 4.1.4.1.1.4 Exte nt of Application.............................................................4.1-10 4.1.4.1.2 SNAP (M ULTISHELL).............................................................4.1-10 4.1.4.1.2.1 Pr ogram Description.............................................................4.1-10 4.1.4.1.2.2 Program Version and Computer...............................................4.1-10 4.1.4.1.2.3 History of Use.....................................................................4. 1-11 4.1.4.1.2.4 Exte nt of Application.............................................................4.1-11 4.1.4.1.3 GASP.................................................................................. 4.1-11 4.1.4.1.3.1 Pr ogram Description.............................................................4.1-11 4.1.4.1.3.2 Program Version and Computer...............................................4.1-11 4.1.4.1.3.3 History of Use.....................................................................4. 1-11 4.1.4.1.3.4 Exte nt of Application.............................................................4.1-11 4.1.4.1.4 NOHEAT............................................................................. 4.1-11 4.1.4.1.4.1 Pr ogram Description ............................................................. 4.1-11 COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Chapter 4 REACTOR

TABLE OF CONTENTS (Continued)

Section Page LDCN-02-000, 02-022, 03-003 4-ii 4.1.4.1.4.2 Program Version and Computer...............................................4.1-12 4.1.4.1.4.3 History of Use.....................................................................4. 1-12 4.1.4.1.4.4 Exte nt of Application.............................................................4.1-12 4.1.4.1.5 FINITE................................................................................ 4.1-12 4.1.4.1.5.1 Pr ogram Description.............................................................4.1-12 4.1.4.1.5.2 Program Version and Computer...............................................4.1-12 4.1.4.1.5.3 History of Use.....................................................................4. 1-12 4.1.4.1.5.4 Extent of Use......................................................................4. 1-12 4.1.4.1.6 DYSEA................................................................................ 4.1-12 4.1.4.1.6.1 Pr ogram Description.............................................................4.1-12 4.1.4.1.6.2 Program Version and Computer...............................................4.1-13 4.1.4.1.6.3 History of Use.....................................................................4. 1-13 4.1.4.1.6.4 Exte nt of Application.............................................................4.1-13 4.1.4.1.7 SHELL 5.............................................................................. 4.1-13 4.1.4.1.7.1 Pr ogram Description.............................................................4.1-13 4.1.4.1.7.2 Program Version and Computer...............................................4.1-13 4.1.4.1.7.3 History of Use.....................................................................4. 1-14 4.1.4.1.7.4 Exte nt of Application.............................................................4.1-14 4.1.4.1.8 HEATER.............................................................................. 4.1-14 4.1.4.1.8.1 Pr ogram Description.............................................................4.1-14 4.1.4.1.8.2 Program Version and Computer...............................................4.1-14 4.1.4.1.8.3 History of Use.....................................................................4. 1-14 4.1.4.1.8.4 Exte nt of Application.............................................................4.1-14 4.1.4.1.9 FAP-71 (Fatigue Analysis Program)............................................. 4.1-14 4.1.4.1.9.1 Pr ogram Description.............................................................4.1-14 4.1.4.1.9.2 Program Version and Computer...............................................4.1-14 4.1.4.1.9.3 History of Use.....................................................................4. 1-15 4.1.4.1.9.4 Extent of Use......................................................................4. 1-15 4.1.4.1.10 CREE P/PLAST.....................................................................4. 1-15 4.1.4.1.10.1 Program Description...........................................................4.1-15 4.1.4.1.10.2 Program Version and Computer.............................................4.1-15 4.1.4.1.10.3 History of Use...................................................................4. 1-15 4.1.4.1.10.4 Exte nt of Application...........................................................4.1-15 4.1.4.2 Fuel Rod Thermal Analysis.........................................................4.1-15 4.1.4.3 Reactor Systems Dynamics..........................................................4.1-15 4.1.4.4 Nuclear Engineering Analysis.......................................................4.1-16 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page LDCN-10-029 4-iii 4.1.4.5 Neutron Fluence Calculations ....................................................... 4.1-16 4.1.4.6 Thermal Hydraulic Calculations .................................................... 4.1-16 4.

1.5 REFERENCES

........................................................................... 4.1-16 

4.2 FUEL SYSTEM DESIGN ................................................................ 4.2-1

4.2.1 DESIGN

BASES ......................................................................... 4.2-1 4.2.1.1 Fuel System Damage Limits ......................................................... 4.2-1 4.2.1.1.1 Stress/Strain Limits ................................................................. 4.2-1 4.2.1.1.2 Fatigue Limits ....................................................................... 4.2-1 4.2.1.1.3 Fretting Wear Limits ............................................................... 4.2-1 4.2.1.1.4 Oxidation, Hydridi ng, and Corrosion Limits .................................. 4.2-1 4.2.1.1.5 Dimensi onal Change Limits ....................................................... 4.2-1 4.2.1.1.6 Internal Ga s Pressure Limit ....................................................... 4.2-1 4.2.1.1.7 Hydraulic Loads Limits ............................................................ 4.2-2 4.2.1.1.8 Control Rod Reactivity Limits .................................................... 4.2-2 4.2.1.2 Fuel Rod Failure Limits .............................................................. 4.2-2 4.2.1.2.1 Hydrid ing Limits .................................................................... 4.2-2 4.2.1.2.2 Claddi ng Collapse Limits .......................................................... 4.2-2 4.2.1.2.3 Fretting Wear Limits ............................................................... 4.2-2 4.2.1.2.4 Overheating of Cladding Lim its .................................................. 4.2-2 4.2.1.2.5 Overheating of Pellet Limits ...................................................... 4.2-2 4.2.1.2.6 Excessive Fuel Enthalpy Li mits .................................................. 4.2-2 4.2.1.2.7 Pellet-Cladding Interaction Limits ............................................... 4.2-2 4.2.1.2.8 Bursting Limits ...................................................................... 4.2-2 4.2.1.2.9 Mechanical Fracturing Limits .................................................... 4.2-3 4.2.1.3 Fuel Coolability Limits ............................................................... 4.2-3 4.2.1.3.1 Cladding Embrittlement Limits ................................................... 4.2-3 4.2.1.3.2 Violent Expulsi on of Fuel Limits ................................................ 4.2-3 4.2.1.3.3 Generalized Cl adding Melt Limits ............................................... 4.2-3 4.2.1.3.4 Fuel Rod Ballooning Limits ....................................................... 4.2-3 4.2.1.3.5 Structural De formation Limits .................................................... 4.2-3 4.2.2 DESCRIPTION AND DESIGN DRAWINGS ..................................... 4.2-3 4.2.2.1 Contro l Rods ........................................................................... 4.2-3 4.2.2.2 Velocity Limiter ....................................................................... 4.2-5 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page LDCN-10-029 4-iv 4.2.3 DESIGN EVALUATION .............................................................. 4.2-6 4.2.3.1 Fuel System Damage Evalua tion ................................................... 4.2-6 4.2.3.1.1 Stress/Strain Evaluatio n............................................................ 4.2-6 4.2.3.1.2 Fatigue Evaluati on .................................................................. 4.2-6 4.2.3.1.3 Fretting Wear Evaluation .......................................................... 4. 2-6 4.2.3.1.4 Oxidation, Hydriding, and Corrosion Evaluation ............................. 4.2-6 4.2.3.1.5 Dimensional Change Evaluation ................................................. 4.2-6 4.2.3.1.6 Internal Gas Pressure Evaluation ................................................. 4.2-6 4.2.3.1.7 Hydraulic Lo ad Evaluation ........................................................ 4.2-7 4.2.3.1.8 Control Rod Reactivity Evaluation .............................................. 4.2-7 4.2.3.2 Fuel Rod Failure ....................................................................... 4.2-7 4.2.3.2.1 Hydridi ng Evaluation .............................................................. 4. 2-7 4.2.3.2.2 Cladding Collapse Evalua tion .................................................... 4.2-7 4.2.3.2.3 Fretting Wear Evaluation .......................................................... 4. 2-7 4.2.3.2.4 Overheati ng of Cladding Evaluation ............................................. 4.2-7 4.2.3.2.5 Overheating of Pellet Limits ...................................................... 4.2-7 4.2.3.2.6 Excessive Fuel Enthalpy Evaluation ............................................. 4.2-7 4.2.3.2.7 Pellet-Cladding Interaction Evaluation .......................................... 4.2-8 4.2.3.2.8 Bursti ng Evaluation ................................................................. 4.2-8 4.2.3.2.9 Mechanical Fr acturing Evaluation ............................................... 4.2-8 4.2.3.3 Fuel C oolability Evaluation .......................................................... 4.2-8 4.2.3.3.1 Cladding Embrittlement Evaluation ............................................. 4.2-8 4.2.3.3.2 Violent Expulsion of Fuel Evaluation ........................................... 4.2-8 4.2.3.3.3 Generalized Cl adding Melt Eval uation .......................................... 4.2-8 4.2.3.3.4 Fuel Rod Ba llooning Evalua tion ................................................. 4.2-8 4.2.3.3.5 Structural De formation Evaluation .............................................. 4.2-9 4.2.4 TESTING, INSPECTION, AND SURVEILLANCE PLANS .................. 4.2-9 4.2.4.1 Fuel Testing, Insp ection, and Surv eillance ....................................... 4.2-9 4.2.4.2 Online Fuel Sy stem Monitoring .................................................... 4.2-9 4.2.4.3 Post-Irradiation Surveillance ........................................................ 4.2-9 4.2.4.4 Channel Manage ment Program ..................................................... 4.2-10 4.

2.5 REFERENCES

........................................................................... 4.2-11 

4.3 NUCLEAR DESIGN ...................................................................... 4.3-1

4.3.1 DESIGN

BASES ......................................................................... 4.3-1 4.3.1.1 Reactivity Basis ........................................................................ 4.3-1 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page LDCN-15-011 4-v 4.3.1.2 Overpow er Bases ...................................................................... 4.3-1

4.3.2 DESCRI

PTION .......................................................................... 4.3-1 4.3.2.1 Nuclear Desi gn Descripti on ......................................................... 4. 3-1 4.3.2.2 Power Di stribution .................................................................... 4.3-1 4.3.2.2.1 Power Distribution Calcula tions.................................................. 4.3-1 4.3.2.2.2 Power Distribu tion Measurements ............................................... 4.3-1 4.3.2.2.3 Power Distri bution Accuracy ..................................................... 4.3-1 4.3.2.2.4 Power Di stribution Anomalies .................................................... 4.3-1 4.3.2.3 Reactivity Coefficients ............................................................... 4.3-2 4.3.2.4 Control Requirements ................................................................ 4. 3-2 4.3.2.4.1 Shutdown Reactivity ................................................................ 4.3-2 4.3.2.4.2 Reactivity Variations ............................................................... 4.3-2 4.3.2.5 Control Rod Patterns and Reactivity Worths ..................................... 4.3-2 4.3.2.6 Criticality of React or During Refu eling ........................................... 4.3-3 4.3.2.7 Stability ................................................................................. 4.3-3 4.3.2.7.1 Xenon Tr ansients ................................................................... 4.3-3 4.3.2.7.2 Thermal H ydraulic Stability ...................................................... 4.3-3 4.3.2.8 Vessel Irradiations ..................................................................... 4.3-3 4.3.3 ANALYTICAL METHODS ........................................................... 4.3-4 4.3.4 CHAN GES ................................................................................ 4.3-5 4.

3.5 REFERENCES

........................................................................... 4.3-5 

4.4 THERMAL-HYDRAULIC DESIGN ................................................... 4.4-1

4.4.1 DESIGN

BASES ......................................................................... 4.4-1 4.4.1.1 Safety Design Bases ................................................................... 4.4-1 4.4.1.2 Requirements for St eady-State Cond itions ........................................ 4.4-1 4.4.1.3 Requirements for Anticipated Operational Occurrences (AOOs) ............. 4.4-1 4.4.1.4 Summary of Design Bases ........................................................... 4. 4-1 4.4.2 DESCRIPTION OF THERMAL-HYDRAULIC DESIGN OF REACTOR CORE ....................................................................... 4.4-1 4.4.2.1 Summary Comparison ................................................................ 4.4-1 4.4.2.2 Critical Power Ratio .................................................................. 4.4-2 4.4.2.3 Linear Heat Generation Rate ........................................................ 4.4-2 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page LDCN-15-011, 10-004 4-vi 4.4.2.4 Void Fracti on Distribution ........................................................... 4.4-2 4.4.2.5 Core Coolant Flow Distri bution and Orifici ng Pattern ......................... 4.4-2 4.4.2.5.1 Flow Distribution Data Comparison ............................................. 4.4-2 4.4.2.5.2 Effect of Channel Flow Uncertainties on the MCPR Uncertainty .......... 4.4-2 4.4.2.6 Core Pressure Drop and Hydraulic Loads ........................................ 4.4-3 4.4.2.7 Correlation and Physical Data ...................................................... 4.4-3 4.4.2.8 Thermal Effects of Operational Transients ....................................... 4.4-3 4.4.2.9 Uncertainties in Estimates ........................................................... 4.4-3 4.4.2.10 Flux Tilt Considerations ............................................................ 4.4-4 4.4.3 DESCRIPTION OF THE TH ERMAL AND HYDRAULIC DESIGN OF THE REACTOR COOL ANT SYSTEM ........................................ 4.4-4 4.4.3.1 Plant Confi guration Data ............................................................. 4.4-4 4.4.3.1.1 Reactor Coolant System Configuration ......................................... 4.4-4 4.4.3.1.2 Reactor Coolant System Thermal Hydraulic Data ............................ 4.4-4 4.4.3.1.3 Reactor Coolant Sy stem Geometric Data ....................................... 4.4-4 4.4.3.2 Operating Rest rictions on Pu mps ................................................... 4.4-4 4.4.3.3 Power-Flow Operating Map ......................................................... 4. 4-5 4.4.3.3.1 Limits for Normal Opera tion ..................................................... 4.4-5 4.4.3.3.2 Regions of the Power-Flow Map ................................................. 4.4-5 4.4.3.3.3 Design Features fo r Power-Flow C ontrol ...................................... 4.4-5 4.4.3.4 Temperature-Po wer Operating Map ............................................... 4.4-7 4.4.3.5 Load-Following Characteris tics ..................................................... 4.4-7 4.4.3.6 Thermal and Hydraulic Characteristics Summary Table ....................... 4.4-7 4.4.4 EVAL UATION .......................................................................... 4.4-7 4.4.4.1 Bypass Flow ............................................................................ 4.4-7 4.4.4.2 Thermal Hydr aulic Stability Analysis .............................................. 4.4-7 4.4.5 TESTING AND VERIFICATION ................................................... 4. 4-8 4.4.6 INSTRUMENTATIO N REQUIREMENTS ........................................ 4.4-8 4.4.6.1 Loose Parts ............................................................................. 4.4-8 4.

4.7 REFERENCES

........................................................................... 4.4-8 

4.5 REACTOR MATERIALS ................................................................ 4.5-1 4.5.1 CONTROL ROD SYSTEM STRUCTURAL MATERIALS .................... 4.5-1 4.5.1.1 Material Specifications ............................................................... 4.5-1 4.5.1.2 Special Materials ...................................................................... 4.5-3 4.5.1.3 Processes, Insp ections and Te sts ................................................... 4.5-3 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page 4-vii 4.5.1.4 Control of Delta Ferrite Content .................................................... 4.5-4 4.5.1.5 Protection of Materials During Fabrication, Shipping, and Storage.......... 4.5-4 4.5.2 REACTOR INTERN AL MATERIALS

............................................. 4.5-5 4.5.2.1   Material Specifications ............................................................... 4.5-5 4.5.2.2   Controls on Weldi ng ..................................................................

4.5-7 4.5.2.3 Nondestructive Examination of Wrought Seamless Tubular Products ....... 4.5-7 4.5.2.4 Fabrication and Processing of Austenitic Stainless Steel - Regulatory Guide Conformance ................................................................... 4.5-8 4.5.2.5 Contamination, Protection, and Cleaning of Austenitic Stainless Steel ...... 4.5-8 4.5.3 CONTROL ROD DRIVE HOUSING SUPPORTS ................................ 4.5-9 4.6 FUNCTIONAL DESIGN OF REACTIVITY CONTROL SYSTEMS ........... 4.6-1 4.6.1 INFORMATION FOR THE CONTROL ROD DRIVE SYSTEM ............. 4.6-1 4.6.1.1 Control Rod Dr ive System De sign ................................................. 4.6-1 4.6.1.1.1 Desi gn Bases ......................................................................... 4.6-1 4.6.1.1.1.1 Sa fety Design Bases .............................................................. 4.6-1 4.6.1.1.1.2 Power Gene ration Design Basis ............................................... 4.6-1 4.6.1.1.2 Desc ription ........................................................................... 4.6-1 4.6.1.1.2.1 Control Rod Drive Mechanisms ............................................... 4.6-2 4.6.1.1.2.2 Drive Components ............................................................... 4.6-3 4.6.1.1.2.2.1 Dr ive Piston ..................................................................... 4.6-3 4.6.1.1.2.2.2 I ndex Tube ...................................................................... 4.6-3 4.6.1.1.2.2.3 Collet Assembly ................................................................ 4.6-3 4.6.1.1.2.2.4 Pi ston Tube ..................................................................... 4.6-4 4.6.1.1.2.2.5 St op Piston ...................................................................... 4.6-4 4.6.1.1.2.2.6 Flange a nd Cylinder Assembly .............................................. 4.6-5 4.6.1.1.2.2.7 Lock Plug ....................................................................... 4.6-5 4.6.1.1.2.3 Materials of Construction ....................................................... 4.6-5 4.6.1.1.2.3.1 I ndex Tube ...................................................................... 4.6-6 4.6.1.1.2.3.2 C oupling Spud .................................................................. 4.6-6 4.6.1.1.2.3.3 Collet Fingers .................................................................. 4.6-6 4.6.1.1.2.3.4 Seals and Bushings ............................................................ 4.6-6 4.6.1.1.2.3.5 Summary ........................................................................ 4.6-6 4.6.1.1.2.4 Control Rod Dr ive Hydraulic System ........................................ 4.6-7 4.6.1.1.2.4.1 Hydrau lic Requireme nts ...................................................... 4.6-7 4.6.1.1.2.4.2 System Description ............................................................ 4. 6-8 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page 4-viii 4.6.1.1.2.4.2.1 Supply Pump ................................................................. 4.6-8 4.6.1.1.2.4.2.2 Accumulato r Charging Pressure .......................................... 4.6-9 4.6.1.1.2.4.2.3 Drive Water Pressure ....................................................... 4.6-9 4.6.1.1.2.4.2.4 Cooling Water Header ...................................................... 4.6-10 4.6.1.1.2.4.2.5 Scram Discharge Volume .................................................. 4.6-10 4.6.1.1.2.4.3 Hydraulic Control Units ...................................................... 4.6-11 4.6.1.1.2.4.3.1 Insert Drive Valve ........................................................... 4.6-12 4.6.1.1.2.4.3.2 Insert Exhaust Valve ........................................................ 4.6-12 4.6.1.1.2.4.3.3 Withdr aw Drive Valve ..................................................... 4.6-12 4.6.1.1.2.4.3.4 Withdraw Exhaust Valve ................................................... 4.6-12 4.6.1.1.2.4.3.5 Speed Control Units ........................................................ 4.6-12 4.6.1.1.2.4.3.6 Scram Pilot Valves .......................................................... 4.6-12 4.6.1.1.2.4.3.7 Scra m Inlet Valv e ........................................................... 4.6-12 4.6.1.1.2.4.3.8 Scram Exhaust Valve ....................................................... 4.6-12 4.6.1.1.2.4.3.9 Scra m Accumulator ......................................................... 4.6-13 4.6.1.1.2.5 Control Rod Drive System Operation ......................................... 4.6-13 4.6.1.1.2.5.1 Rod Insertion ................................................................... 4.6-13 4.6.1.1.2.5.2 Rod Withdrawal ................................................................ 4.6-13 4.6.1.1.2.5.3 Scram ............................................................................ 4.6-14 4.6.1.1.2.6 Instru mentation ................................................................... 4.6-15 4.6.1.2 Control Rod Drive Housing Supports ............................................. 4.6-15 4.6.1.2.1 Safety Objective ..................................................................... 4.6-15 4.6.1.2.2 Safety Design Bases ................................................................ 4.6-15 4.6.1.2.3 Desc ription ........................................................................... 4. 6-15 4.6.2 EVALUATION OF THE CO NTROL ROD DRIVES ............................ 4.6-16 4.6.2.1 Control Rods ........................................................................... 4.6-17 4.6.2.1.1 Materials Adequacy Throughout Design Lifetime ............................ 4.6-17 4.6.2.1.2 Dimens ional and Tolerance Analysis ............................................ 4.6-17 4.6.2.1.3 Thermal Analysis of the Tendency to Warp ................................... 4.6-17 4.6.2.1.4 Forces fo r Expulsion ............................................................... 4.6-17 4.6.2.1.5 Functional Failure of Critical Components ..................................... 4.6-18 4.6.2.1.6 Precluding Excessive Rates of Reactivity Addition ........................... 4.6-18 4.6.2.1.7 Effect of Fuel Rod Failure on Control Rod Channel Clearances ........... 4.6-18 4.6.2.1.8 Mechanical Damage ................................................................ 4.6-18 4.6.2.1.9 Evaluation of Control Rod Velocity Limiter ................................... 4.6-19 4.6.2.2 Control Rod Drives ................................................................... 4.6-19 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page 4-ix 4.6.2.2.1 Evalua tion of Scram Time ......................................................... 4.6-19 4.6.2.2.2 Analysis of Malfunction Relating to Rod Withdrawal ........................ 4.6-19 4.6.2.2.2.1 Drive Housing Fails at Attachment Weld .................................... 4.6-19 4.6.2.2.2.2 Rupture of Hydraulic Line(s) to Drive Housing Flange ................... 4.6-20 4.6.2.2.2.2.1 Pressure-U nder Line Break

.................................................. 4.6-20 4.6.2.2.2.2.2   Pressure-O ver Line Break .................................................... 4.6-20 4.6.2.2.2.2.3   Simultaneous Breakage of the Pressure

-Over and Pressure-Under Lines ............................................................................. 4.6-21 4.6.2.2.2.3 All Drive Flange Bolts Fail in Tension ....................................... 4.6-21 4.6.2.2.2.4 Weld Joining Flange to Housing Fails in Tension .......................... 4.6-22 4.6.2.2.2.5 Hous ing Wall Ruptures .......................................................... 4.6-23 4.6.2.2.2.6 Flange Plug Blows Out .......................................................... 4.6-23 4.6.2.2.2.7 Ball Check Va lve Plug Blows Out ............................................ 4.6-24 4.6.2.2.2.8 Drive/Coo ling Water Pressure Control Valve Failure ..................... 4.6-24 4.6.2.2.2.9 Ball Check Valve Fails to Close Passage to Vessel Ports ................. 4.6-25 4.6.2.2.2.10 Hydrau lic Control Unit Valv e Failures ..................................... 4.6-25 4.6.2.2.2.11 Collet Fingers Fail to Latch ................................................... 4.6-26 4.6.2.2.2.12 Withdrawal Speed Control Valve Failure .................................. 4.6-26 4.6.2.2.2.13 Slow or Partial Loss of Air to the Scram Discharge Valves ............ 4.6-26 4.6.2.2.3 Scram Reliability .................................................................... 4.6-27 4.6.2.2.4 Control Rod Supp ort and Operation ............................................. 4.6-27 4.6.2.3 Control Rod Drive Housing Supports ............................................. 4.6-27 4.6.3 TESTING AND VERIFICATION OF THE CONTROL ROD DRIVES ..... 4.6-28 4.6.3.1 Control Rod Drives ................................................................... 4.6-28 4.6.3.1.1 Testing and Inspection ............................................................. 4.6-28 4.6.3.1.1.1 Devel opment Tests ............................................................... 4.6-28 4.6.3.1.1.2 Factory Quality Control Tests .................................................. 4.6-28 4.6.3.1.1.3 Opera tional Tests ................................................................. 4.6-29 4.6.3.1.1.4 Accepta nce Tests ................................................................. 4.6-30 4.6.3.1.1.5 Surveillance Tests ................................................................ 4.6-30 4.6.3.1.1.6 Functi onal Tests .................................................................. 4.6-31 4.6.3.2 Control Rod Drive Housing Supports ............................................. 4.6-32 4.6.4 INFORMATION FOR COMBINED PERFORMANCE OF REACTIVITY CONTROL SYSTEMS .................................................................. 4.6-32 4.6.4.1 Vulnerability to Co mmon Mode Failures ......................................... 4. 6-32 4.6.4.2 Accidents Taking Credit for Multiple Reactivity Systems ..................... 4.6-33 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued)

Section Page 4-x 4.6.5 EVALUATION OF COMBINED PERFORMANCE ............................. 4.6-33 4.6.6 ALTERNATE ROD INSERTION SYSTEM ....................................... 4.6-33 4.6.6.1 System Description .................................................................... 4.6-33 4.6.6.2 Alternate R od Insertion Redundancy ............................................... 4.6-34 4.

6.7 REFERENCES

........................................................................... 4.6-34 

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR LIST OF TABLES

Number Title Page 4-xi 4.2-1 Control Rod Pa rameters ....................................................... 4.2-15 4.3-1 Summary of Neutron Fluence Results ....................................... 4.3-7 4.3-2 Reload Fuel Neutr onic Design Values ...................................... 4.3-8

4.3-3 Neutronic Desi gn Values ...................................................... 4.3-9

4.4-1 Thermal and Hydraulic Design Characteristics of the Reactor Core ..................................................................... 4.4-11

4.4-2 Mixed Core Thermal Hydraulic Analysis Results ......................... 4.4-12

4.4-3 Reactor Coolant System Geometric Data ................................... 4.4-13

4.4-4 Lengths and Sizes of Safe ty Injection Lines ................................ 4.4-14

4.4-5 Core Pressure Drop and Leakage Flow Results for Core Configurations ................................................................... 4.4-15

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR LIST OF FIGURES

Number Title 4-xii 4.1-1 Steam Separator 4.1-2 Steam Dryer Panel

4.1-3 Columbia Generating Stati on Cycle 19 Reference Loading Map

4.2-1.1 Original Equipment (OEM) Control Rod Blade Assembly

4.2-1.2 Duralife 215 Control Rod Blade Assembly

4.2-1.3 Marathon Control Rod Blade Assembly

4.2-1.4 Marathon Control R od Blade Absorber Details

4.2-1.5 Marathon Control Rod Blade Absorber Placement

4.2-2 Control Rod Velocity Limiter

4.3-1 Core Layout and Vessel Internal Components

4.4-1 Power-Flow Operating Map, Two Loop Operation

4.4-2 Power-Flow Operating Map, Single Loop Operation

4.6-1 Control Rod to C ontrol Rod Drive Coupling

4.6-2 Control Rod Drive Unit

4.6-3 Control Rod Drive Unit (Schematic)

4.6-4 Model 7RDB144B or C C ontrol Rod Drive (Breakdown)

4.6-5 Control Rod Drive Hydrau lic System (Sheets 1 and 2)

4.6-6 Control Rod Drive System Pr ocess Diagram (Sheets 1 through 3)

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR LIST OF FIGURES (Continued)

Number Title 4-xiii 4.6-7 Control Rod Drive Hydraulic Control Unit 4.6-8 Control Rod Drive Housing Support

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-1 Chapter 4 REACTOR 4.1 SUMMARY DESCRIPTION

This section was prepared using the licensing topical report, "General Electric Standard Application for Reactor Fuel" (GESTAR II) Reference 4.1-1, GESTAR II compliance documents (References 4.1-4 and 4.1-5), the cy cle-specific design report (Reference 4.1-2) and the "Fuel Bundle Informati on Report" (Reference 4.1-3).

The reactor assembly consists of the reactor vessel, internal components of the core, shroud, steam separator and dryer assemblies, and jet pumps. Also included in the reactor assembly are the control rods, control rod drive housings, and the cont rol rod drives. Figure 5.3-5 shows the arrangement of reacto r assembly components. A summary of the important design and performance characterist ics is given in Section 1.3. Loading conditions for reactor assembly components are specified in Section 3.9. The core load varies for each cycle and is shown in Reference 4.1-2. 4.1.1 REACTOR VESSEL

The reactor vessel design and desc ription are discussed in Section 5.3. 4.1.2 REACTOR INTERNAL COMPONENTS

The major reactor internal components are the core (fuel, channels, control blades, and instrumentation), the core support structure (inc luding the shroud, top guide and core plate), the shroud head and steam sepa rator assembly, the steam dr yer assembly, the feedwater spargers, the core spray spargers, and the jet pumps. Except for the Zi rcaloy in the reactor core, these reactor internals are stainless steel or other corrosion resistant alloys. All major internal components of the vessel can be removed except the jet pump diffusers, the jet pump risers, the shroud, the co re spray lines, spargers, and the fe edwater sparger. The removal of the steam dryers, shroud head and steam sepa rators, fuel assemblies, in-core assemblies, control rods, orificed fuel supports, and control rod guide tubes can be accomplished on a routine basis. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-2 4.1.2.1 Reactor Core

4.1.2.1.1 General

The reactor core is composed of fuel assemblies manufactured by Global Nuclear Fuel (GNF).

A number of important features of the BWR core design are summarized in the following paragraphs:

a. The BWR core mechanical design is ba sed on conservative app lication of stress limits, operating experience, and experimental test results. The moderate pressure levels characteristics of a direct cycl e reactor (approximately 1035 psia) result in mode rate cladding temperatures and stress levels;

b. The low coolant saturation temperature, high heat transfer coefficients, and neutral water chemistry of the BWR are significant, advantag eous factors in minimizing Zircaloy temperature and associated temperature-dependent corrosion and hydride buildup; The relatively uniform fuel cladding te mperatures throughout the core minimize migration of the hydrides to cold cla dding zones and reduce thermal stresses;

c. The basic thermal and mechanical cr iteria applied in th e design have been proven by irradiation of statistically significant quantities of fuel. The design heat transfer rates and lin ear heat generation rates ar e similar to values proven in fuel assembly irradiation;

d. The design power distribution used in sizing the core represents a worst expected state of operation;

e. The thermal margin analyses ensure that more than 99.9% of the fuel rods in the core are expected to avoid boiling transition for the most severe anticipated operational occurrences described in Chapter 15

. The possibility of boiling transition occurring during normal reactor operation is insignificant; and

f. Because of the large ne gative moderator density coef ficient of reactivity, the BWR has a number of inherent advantages. These are th e uses of coolant flow for load following, the inherent self-flatt ening of the radial power distribution, the ease of control, the spatial xenon stability, and the ability to override xenon to follow load.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 4.1-3 Boiling water reactors do not usually have inst ability problems due to xenon. This has been demonstrated by special tests which were conducted on operating BWRs and by calculations. Xenon transients are highly damped in a BWR due to the large negative power coefficient of reactivity (Reference 4.1-7). Columbia Generating Station (CGS ) has installed a stability de tect and suppress system to ensure hydrodynamic stability while operating in re gions susceptible to instability. Stability system limits are specified in the Technical Specifications and in the Core Operating Limits Report. Important features of the reactor core arrangement are as follows:

a. The original bottom-entry cruc iform control rods consist of B 4C in stainless steel tubes surrounded by a stainless steel sheath;

b. The bottom-entry cruciform Duralife 215 control rods consist of 18 high-purity stainless steel tubes at each wing filled with boron-carbide and three hafnium rods at the edge of each wing and a hafnium plate at the top;

c. The bottom-entry cruciform Marathon control rods consist of 17 high-purity stainless steel tubes in each wing. Eleven of the tubes are filled with boron-carbide, two of the tubes are partially filled with boron-carbide and four tubes are filled with hafnium rods (thr ee at the outer edge of each wing and one at the center of the wing). See Figure 4.2-1.5 for details;

d. The in-core location of the startup and power range instruments provides coverage of the large reactor core and provides an acceptable signal-to-noise

ratio and neutron-to-gamma ratio. All in-core instrument leads enter from the bottom and the instruments are in se rvice during refueling. In-core instrumentation is furthe r discussed in Sections 7.6.1.4 and 7.7.1.6;

e. As shown by experience obtained at other plants, the operator, utilizing the in-core flux monitor system, can maintain the desired power distribution within a large core by proper control rod scheduling;

f. The Zircaloy-2 and 4 channe ls provide a fixed flow pa th for the boiling coolant, serve as a guiding surface for the cont rol rods, and protect the fuel during handling operations;

g. The mechanical reactivity control perm its criticality checks during refueling and provides maximum plant safety. The core is designed to be subcritical at any time in its operating history with any one control rod fully withdrawn; and

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-4 h. The selected control rod pitch represents a practical value of individual control rod reactivity worth and allows ample clearance below the pressure vessel between control rod drive mechanisms for ease of maintenance and removal.

4.1.2.1.2 Core Configuration

The reactor core is arranged as an upright circular cylinder c ontaining a large number of fuel cells and is located within the reactor vessel. The coolant flows upward through the core. The BWR core is composed of essentially two components: fuel assemblies and control rods. The General Electric Company (GE) control rod mechani cal configuration (see Figure 4.2-1 ) is basically the same as used in all GE BWRs.

4.1.2.1.3 Fuel Assembly Description

The GNF reload fuel asse mblies are GNF2 (Reference 4.1-4) and GE14 (Reference 4.1-5). 4.1.2.1.3.1 Fuel Rod. A fuel rod consists of UO 2 pellets and a Zircaloy-2 cladding tube. A fuel rod is made by stacking pellets into a Zircaloy-2 cladding tube , which is sealed by welding Zircaloy end plugs in each end of the tube. The GNF fuel rods are pressurized to 10 atmospheres (References 4.1-4 and 4.1-5). The BWR fuel rod is designed as a pressure vessel. The ASME Boiler and Pressure Vessel (B&PV) Code, Section III, is used as a guide in the mechanical design and stress analysis of the fuel rod.

The rod is designed to withstand the applied loads, both external and internal. The fuel pellet is sized to provide sufficient vol ume within the fuel tube to accommodate differential expansion between fuel and clad. Overa ll fuel rod design is conservativ e in its accommodation of the mechanisms affecting fuel in a BWR environmen

t. Fuel rod design bases are discussed in more detail in Section 4.2.1.

4.1.2.1.3.2 Fuel Bundle. The fuel bundle has two important design features:

a. The bundle design places minimum external forces on a fuel rod; each fuel rod is free to expand in the axial direction, and

b. The unique structural design permits the removal and replacement, if required, of individual fuel rods.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-5 The fuel bundles are designed to meet all the criteria for core performance and to provide ease of handling. Selected fuel rods in each bundl e differ from the others in uranium enrichment.

This arrangement produces more uniform power production acr oss the fuel bundle and thus allows a significant reduction in the amount of heat transfer su rface required to satisfy the design thermal limitations.

The GNF reload bundle contains 92 fuel rods a nd 2 large central water rods, all in a 10 x 10 array. 4.1.2.1.4 Assembly Support and Control Rod Location

Some peripheral fuel assemblies are supported by the core plate. Otherwise, individual fuel assemblies in the core rest on fuel support pieces mounted on top of the cont rol rod guide tubes. Each guide tube, with its fuel support piece, bears the we ight of four a ssemblies and is supported by a control rod drive penetration nozzl e in the bottom head of the reactor vessel. The core plate provides lateral support and guidan ce at the top of each control rod guide tube.

The top guide, mounted inside the shroud, provid es lateral support and guidance for each fuel assembly. The reactivity of the core is controlled by cruciform control rods and their associated mechanical hydraulic drive system. The control rods occupy alternate spaces between fuel assemblies. Each independent drive enters the core from the bottom and can accurately position its associated control rod during normal operation and yet insert the control rod in less than 7 sec during the scram mode of operation. Bottom entry allows optimum power shaping in the core, ease of refu eling, and convenient drive maintenance.

4.1.2.2 Shroud

The shroud is a cylindri cal, stainless-steel stru cture which surrounds the core and provides a barrier to separate the upward flow through the core from th e downward flow in the annulus and also provides a floodable volume in the unlikely event of an accident which would otherwise drain the reactor pressure vessel. A flange at the top of the shroud mates with a flange on the shroud head and st eam separators. The upper cyli ndrical wall of the shroud and the shroud head form the core discharge plenum . The jet pump discharge diffusers penetrate the shroud support below the core elevation to in troduce the coolant to the inlet plenum. To prevent direct flow from the in let to the outlet nozzl es of the recirculation loops, the shroud support is welded to the vessel wall. The shroud support is designed to support and locate the jet pumps, core support structure, and some peripheral fuel assemblies.

Mounted inside the upper shroud cylinder in the space between the top of the core and the upper shroud flange are the core spray spargers with spray nozzles fo r injection of cooling COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-6 water. The core spray spargers and nozzles do not interfere with the installation or removal of fuel from the core.

4.1.2.3 Shroud Head and Steam Separators

The shroud head consists of a fl ange and dome onto which is we lded an array of standpipes,

with a steam separator located at the top of each standpipe . The shroud head mounts on the flange at the top of the cylinde r and forms the cover of the core discharge plenum region. The joint between the shroud head and shroud flange does not require a gasket or other replacement sealing technique. The fixed ax ial flow type steam separators have no moving parts and are made of stainless steel.

In each separator, the steam-wat er mixture rising from the st andpipe impinges on vanes which give the mixture a spin to establish a vortex wherein the centrifugal forces separate the steam from the water. Steam leaves the separator at the top and passes into the wet steam plenum below the dryer. The separated water exits from the lower end of the separator and enters the pool that surrounds the standpipes to enter the downcomer annulus. An internal steam separator diagram is shown in Figure 4.1-1 . For ease of removal, the shroud head is bolted to the shroud top flange by long shroud head bolts that extend above the sepa rators for easy access during re fueling. The shroud head is guided into position on the shroud via guide rods on the inside of the vessel and locating pins located on the shroud head . The objective of the shroud head bolt design is to provide direct access to the bolts during reactor refueling ope rations with minimum-depth underwater tool manipulation during the removal and installation of the assemblies.

4.1.2.4 Steam Dryer Assembly

The steam dryer assembly is m ounted in the reactor vessel a bove the shroud head and forms the top and sides of the wet steam plenum. Ve rtical guide rods on the inside of the vessel provide alignment for the dryer a ssembly during installation. The dryer assembly is supported by pads extending from the vessel wall and is locked into position during operation by the reactor vessel top head. Steam from the separators flows upward into the dryer assembly. The steam leaving the top of the dryer assembly flows into vessel stea m outlet nozzles which are located alongside the steam dryer assembly. Moisture is removed by the dryer vanes and flows first through a system of troughs and pipes to the pool surrounding the separators and then into the downcomer annulus between the core shroud and reactor vessel wall. The diagram of a typical steam dryer panel is shown in Figure 4.1-2 . COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-022 4.1-7 4.1.3 REACTIVITY CONTROL SYSTEMS

4.1.3.1 Operation

The control rods perform dual functions of power distribution sh aping and reactivity control. Power distribution in the core is controlled during operation of the reactor by manipulation of selected patterns of rods. The rods, which enter from the bottom of the near-cylindrical reactor core, are positioned in such a manner to counter-balance steam voids in the top of the core and effect signifi cant power flattening.

These groups of control elements, used for power flattening, experi ence a somewhat higher duty cycle and neutron exposure than the other rods in the control system.

The reactivity control function requires that all rods be available for either reactor "scram" (prompt shutdown) or reactivit y regulation. Because of this, the control elements are mechanically designed to withstand the dynamic forces resulting from a scram. They are connected to bottom-mounted, hydraulically actuated drive mechanisms which allow either axial positioning for reactivity regulation or rapid scram insertion. The design of the rod-to-drive connection permits each blade to be attached or detached from its drive without disturbing the remainder of the control system . The bottom-mounted dr ives permit the entire control system to be left intact and operable for tests with the reactor vessel open.

4.1.3.2 Description of Rods

The cruciform shaped control rods contain 76 stai nless steel tubes (19 tubes in each wing of the cruciform) filled with vibrati on compacted boron-carbide powder. The tubes are seal welded with end plugs on either end. Stainless steel balls are used to separate the tubes into individual compartments. The stainless steel balls are held in position by a slight crimp in the tube. The individual tubes act as pressure vessels to contain the helium gas released by the boron-neutron capture reaction.

The tubes are held in a cruciform array by a stainless steel sheath exte nding the full length of the tubes. A top handle, shown in Figure 4.2-1 , aligns the tubes and provides structural rigidity at the top of the control rod. Rolle rs, housed in the handl e, provide guidance for control rod insertion and withdrawal. A bottom casting is also used to provide structural rigidity and contains positioning rollers and a parachute-shaped velocity limiter. The handle and lower casting are welded into a single structure by means of a small cruciform post located in the center of the control rod. A steel stiffener is located approximate ly at the midspan of each cruciform wing. The control rods can be positioned at 6-in. step s and have a nominal withdrawal and insertion speed of 3 in./sec.

The foregoing description of the c ontrol rods applies to the design of the original control rods. There have been two different replacement control rods used, Du ralife 215 and Marathon

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-022 4.1-8 control rods. These replacement rods have design changes that increase the neutron absorption and make other material property improvements. The newer control rods are similar to and are fully interchangeable with th e original control rod assemblies and are compatible with the existing nuclear steam s upply system hardware.

The Duralife 215 control rods differ from the previ ous control rods in that a hafnium absorber plate is used at the top of each cruciform section, hafnium absorber ro ds replace several of the boron carbide absorber rods on the periphery of each cruciform section, and the stainless steel stiffener is removed from each wing. There ar e 21 absorber rods in each wing, of which 18 are stainless-steel tubes contai ning boron carbide and three ar e hafnium rods. The outside diameter remains the same. The length of the absorber column in these rods has been reduced from 143 in. to 137 in. to accommodate the t op 6-in.-high hafnium plate. The increased volume of neutron absorber material increases the relative reactivit y worth in the cold condition and increases the nuclear lifetime.

The Marathon control rod blades are an improv ed version of the Duralife 215 control blades and have the absorber and sheath arrangement replaced with an array of square tubes, which results in reduced weight and in creased absorber volume. The square tubes each have four lobes to allow adjacent tubes to be welded to each other. The abso rber tubes are welded lengthwise to form the four wings of the control rod. Each wing is comprised of 17 absorber tubes. The absorber tu bes each act as an individual pre ssure chamber for the retention of helium. The region between each pair of square tubes is filled with he lium and sealed top and bottom by welding. The four wings are then welded to the tie rod to form the cruciform-shaped member of the control rod. The Marathon control rod blade has the full-length tie rod replaced with a segmente d tie rod, which also reduces weight.

The square tubes are circular inside and are loaded with either B 4C or hafnium. The B 4C is contained in separate capsules to prevent its migration. The capsules are placed inside the square absorber tubes and are smaller than the absorber tube inside diameter, allowing the B 4C to swell before making contact with the absorber tubes ther eby increasing stress corrosion resistance. Empty tubes may be used adjacent to the tie rods to achieve the desired reactivity worth. The combination of absorbers and ab sorber tubes is based on the needed initial reactivity worth. In addition, empty capsules are used in some absorber tubes to provide a plenum for helium released during B 4C burnup. The velocity limiter, shown in Figure 4.2-2, is a device which is an i ntegral part of the control rod and protects against the low probability of a rod drop accident . It is designed to limit the free fall velocity and reactivity insertion rate of a control rod so that minimum fuel damage would occur. It is a one-way device, in that control rod scram time is not significantly affected.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-035 4.1-9 Control rods are cooled by the co re leakage (bypass) flow. The co re leakage flow is made of recirculation flow that leaks through the severa l leakage flow paths, which are as follows:

a. The area between fuel channel and fuel assembly nosepiece,

b. The area between fuel assembly nosepiece and fuel support piece,

c. Holes in the lower tie plate,

d. The area between fuel s upport piece and core plate,

e. The area between core plate and shroud,

f. Holes in the core plate near power range monitor instru ment guide tubes,

g. Various leakage paths around th e control rod gu ide tubes, and

h. Control rod driv e cooling water.

4.1.3.3 Supplementary Reactivity Control

Supplemental reactivity control is achieved with burnable poison. The supplementary burnable poison is gadolinia (Gd 2O3) mixed with UO 2 in selected fuel rods in each fuel bundle.

4.1.4 ANALYSIS TECHNIQUES

4.1.4.1 Reactor Internal Components

Computer codes used for the analysis of the in ternal components as a basis for the original operating license are listed as follows:

a. MASS

b. SNAP (MULTISHELL)

c. GASP

d. NOHEAT

e. FINITE

f. DYSEA

g. SHELL 5

h. HEATER

i. FAP-71

j. CREEP-PLAST

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-10 The following italicized detailed descriptions of these programs ar e historical and were provided to support the application for an operating license. 4.1.4.1.1 MASS (Mechanical Anal ysis of Space Structure)

4.1.4.1.1.1 Program Description . This is a proprietary program of GE and is an outgrowth of the PAPA (Plate and Panel Anal ysis) program originally developed by L. Beitch in the early 1960s. The program is based on the principle of the finite elem ent method. Governing matrix equations are formed in terms of joint displacements using a "stiffness-influence -coefficient" concept originally proposed by L. Beitch (Reference 4.1-9). The program offers curved beam, plate, and shell elements. It can handle mechanical and thermal l oads in a static analysis and predict natural frequencies and mode shapes in a dynamic analysis.

4.1.4.1.1.2 Program Version and Computer . The Nuclear Energy Di vision is using a past revision of MASS. This revi sion is identified as revision "0" in the computer production library. The program operates on the Honeywell 6000 computer.

4.1.4.1.1.3 Hi story of Use . Since its development in the early 1960s, the program has been successfully applied to a wi de variety of jet-engine structural problems, many of which involve extremely complex geometries. The use of the program in the Nuclear Energy Division also started shortly after its development.

4.1.4.1.1.4 Extent of Application . Besides the Jet Engine and Nuclear Energy Divisions, the Missile and Space Division, the Appliance Division, and the Turb ine Division of GE have also applied the program to a wide r ange of engineering problems. The Nuclear Energy Division uses it mainly for piping and reactor internals analyses.

4.1.4.1.2 SNAP (MULTISHELL)

4.1.4.1.2.1 Program Description. The SNAP Program, which is also called MULTISHELL, is the GE code which determines th e loads, deformations, and stresses of axisymmetr ic shells of revolution (cylinders, cones, di scs, toroids, and rings) for axisymmetric th ermal boundary and surface load conditions. Thin shell theory is inherent in the solution of E. Peissner's differential equations for each shell's influence co efficients. Surfa ce loading capability includes pressure, average te mperature, and liner through wa ll temperature gradients; the latter two may be linearly varied over the shell meridian. The theoretical limitations of this program are the same as those of classical theory.

4.1.4.1.2.2 Program Version and Computer. The current version ma intained by the GE Jet Engine Division at Evandale, Ohio, is being used on the Honeywell 6000 computer in GE/NED.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-11 4.1.4.1.2.3 Hi story of Use. The initial version of the Shell Analysis Program was completed by the Jet Engine Division in 1961. Since then, a considerable amount of modification and addition has been made to accommo date its broadening area of application. Its application in the Nuclear Energy Division has a history longer than 10 years. 4.1.4.1.2.4 Extent of Application . The program has been used to analyze jet engine, space vehicle and nuclear reactor components. Becaus e of its efficiency and economy, in addition to reliability, it has been one of the main shell analysis programs in the Nuclear Energy Division of GE. 4.1.4.1.3 GASP

4.1.4.1.3.1 Program Description . GASP is a finite element pr ogram for the stress analysis of axisymmetric or plane two-dimensional geometries. The element representations can be either

quadrilateral or triangular. Axis ymmetric or plane structural loads can be input at nodal points. Displacements, temperat ures, pressure loads, and axial inertia can be accommodated. Effective plastic stress and stra in distributions can be calculat ed using a bilinea r stress-strain relationship by means of an ite rative convergence procedure.

4.1.4.1.3.2 Program Version and Computer. The GE version, originally from the developer, Professor E. L. Wilson, operates on the Honeywell 6000 computer.

4.1.4.1.3.3 Hi story of Use . The program was developed by Professor E. L. Wilson in 1965 (Reference 4.1-10). The present version in GE/NED has been in operation since 1967.

4.1.4.1.3.4 Extent of Application. The application of GASP in GE/NED is mainly for elastic analysis of axisymmetric and plane structures under thermal and pressure loads. The GE version has been extensively tested and used by engineers in the company.

4.1.4.1.4 NOHEAT

4.1.4.1.4.1 Program Description. The NOHEAT program is a two-dimensional and axisymmetric transient nonlinear temperature analysis program. An unconditionally stable numerical integration scheme is combined with iteration procedure to compute temperature distribution within the body subjected to arb itrary time- and temperat ure-dependent boundary conditions.

This program utilizes the finite element method. Included in the analysis are the three basic forms of heat transfer, conduc tion, radiation, and convection, as well as internal heat generation. In addition, coo ling pipe boundary conditions are also treated. The output includes temperature histories of all the nodal points established by the user. The program can handle multitransient temperature input.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-12 4.1.4.1.4.2 Program Version and Computer. The current version of the program is an improvement of the program originally deve loped by I. Farhoomand and Professor E. L. Wilson of University of California at Berkeley (Reference 4.1-11). The program operates on the Honeywell 6000 computer.

4.1.4.1.4.3 Hi story of Use. The program was developed in 1971 and installed in GE Honeywell computer by one of its original developers, I. Farhoomand, in 1972. A number of heat transfer problems related to the reactor pedestal have been sa tisfactorily solved using the program. 4.1.4.1.4.4 Extent of Application . The program using finite element formulation is compatible with the finite element stress-analysis computer program GASP. Such compatibility simplified the connection of the two analys es and minimizes human error.

4.1.4.1.5 FINITE

4.1.4.1.5.1 Program Description . FINITE is a general-pur pose finite element computer program for elastic stress analysis of two-dimensional structural problems including (1) plane

stress, (2) plane strain, and (3) axisymmetric structures. It has provisions for thermal, mechanical, and body force loads. The materials of the structure may be homogeneous or inhomogeneous and isotropic or orthotropic. The development of the FINITE program is based on the GASP program (see Section 4.1.4.1.3 ). 4.1.4.1.5.2 Program Version and Computer. The present version of the program at GE/NED was obtained from the develope r J. E. McConnelee of GE/Gas Turbine Department in 1969 (Reference 4.1-12). The NED version is used on the Honeywell 6000 computer.

4.1.4.1.5.3 Hi story of Use . Since its completion in 1969, the program has been widely used in the Gas Turbine and the Jet Engine Departmen ts of the GE for the analysis of turbine components.

4.1.4.1.5.4 Extent of Use . The program is used at GE/NED in the analysis of axisymmetric or nearly-axisymmetr ic BWR internals.

4.1.4.1.6 DYSEA 4.1.4.1.6.1 Program Description . The DYSEA (Dynamic and Seis mic Analysis) program is a GE proprietary program develope d specifically for seismic a nd dynamic analysis of RPV and internals/building system. It ca lculates the dynamic response of linear structural system by either temporal modal superposition or re sponse spectrum method. Fl uid-structure interaction effect in the RPV is taken into a ccount by way of hydrodynamic mass.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-13 Program DYSEA was based on program SA PIV with added capability to handle the hydrodynamic mass effect. Structural stiffness and mass matrices are formulated similar to SAPIV. Solution is obtained in time domain by calculating the dynamic response mode-by-mode. Time integration is performed by using Newmark's -method. Response spectrum solution is also available as an option.

4.1.4.1.6.2 Program Version and Computer. The DYSEA version now operating on the Honeywell 6000 computer of GE, Nuclear Energy Systems Division, was developed at GE by modifying the SAPIV program. Capability wa s added to handle the hy drodynamic mass effect due to fluid-structure interact ion in the reactor. It can handle three-dimensional dynamic problems with beam, trusses, and springs. Both acceleration time histories and response

spectra may be used as input.

4.1.4.1.6.3 History of Use. The DYSEA program was develope d in the Summer of 1976. It has been adopted as a standar d production program since 1977 and it has been used extensively in all dynamic and seismic analysis of the RPV and internals/building system.

4.1.4.1.6.4 Extent of Application . The current version of DY SEA has been used in all dynamic and seismic analys is since its development. Results from test problems were found to be in close agreement with thos e obtained from either verified programs or analytic solutions.

4.1.4.1.7 SHELL 5

4.1.4.1.7.1 Program Description . SHELL 5 is a finite shell element program used to analyze smoothly curved thin shell structures with any distribution of elasti c material properties, boundary constraints, and mec hanical thermal and displacement loading conditions. The basic element is a triangle whose membrane displace ment fields are linear polynomial functions, and whose bending displacement field is a cubic polynomial function (Reference 4.1-13). Five degrees of freedom (three displacements and two bending rotations) are obtained at each nodal point. Output displacem ents and stresses are in a lo cal (tangent) surface coordinate system.

Due to the approximation of element membrane di splacements by linear functions, the in-plane rotation about the surface normal is neglected. Therefore, the only rotations considered are due to bending of the shell cross section and application of the method is not recommended for shell intersection (or disconti nuous surface) problems where in-plane rotation can be significant.

4.1.4.1.7.2 Program Version and Computer . A copy of the sour ce deck of SHELL 5 is maintained by GE/NED by Y. R. Rashid, one of the originators of the program. SHELL 5 operates on the UNIVAC 1108 computer.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1-14 4.1.4.1.7.3 Hi story of Use . SHELL 5 is a program developed by Gulf General Atomic Incorporated (Reference 4.1-14) in 1969. The program has b een in production status at Gulf General Atomic, GE, and at other major computer operating systems since 1970. 4.1.4.1.7.4 Extent of Application. SHELL 5 has been used at GE to analyze reactor shroud support and torus. Satisfact ory results were obtained.

4.1.4.1.8 HEATER

4.1.4.1.8.1 Program Description. HEATER is a computer pr ogram used in the hydraulic design of feedwater spargers and their associated delivery header and pi ping. The program utilizes test data obtained by GE using full scale mockups of f eedwater spargers combined with a series of models which re presents the complex mixing pr ocesses obtained in the upper plenum, downcomer, and lower plenum. Mass and energy balances th roughout the nuclear steam supply system are m odeled in detail (Reference 4.1-15). 4.1.4.1.8.2 Program Version and Computer. This program was developed at GE/NED in FORTRAN IV for the Honeywell 6000 computer.

4.1.4.1.8.3 Hi story of Use. The program was developed by various individuals in GE/NED beginning in 1970. The present version of the program ha s been in operation since January 1972.

4.1.4.1.8.4 Extent of Application . The program is used in the hydraulic design of the feedwater spargers for each BW R plant, in the evaluation of design modifications, and the evaluation of unusual operational conditions.

4.1.4.1.9 FAP-71 (Fati gue Analysis Program)

4.1.4.1.9.1 Program Description . The FAP-71 computer code, or Fatigue Analysis Program, is a stress analysis tool used to aid in performing ASME-III Nu clear Vessel Code structural design calculations. Specifically, FAP-71 is used in determini ng the primary plus secondary stress range and number of allowa ble fatigue cycles at points of interest. For structural locations at which the 3S m (P+Q) ASME Code limit is exceeded, the program can perform either (or both) of two elastic-plastic fatigue life evaluations: 1) the method reported in ASME Paper 68-PVP-3, 2) the present method documented in Paragraph NB-3228.3 of the 1971 Edition of the ASME Section III Nuclear Vessel Code. The Program can accommodate up to 25 transient stress stat es on as many as 20 structural locations.

4.1.4.1.9.2 Program Version and Computer. The present version of FAP-71 was completed by L. Young of GE/NED in 1971 (Reference 4.1-16). The program currently is on the NED Honeywell 6000 computer.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-15 4.1.4.1.9.3 History of Use. Since its completion in 1971, the program has been applied to several design analyses of GE BWR vessels.

4.1.4.1.9.4 Extent of Use. The program is used in conjuncti on with several shell analysis programs in determining the fatigue life of BWR mechanical components subject to thermal transients.

4.1.4.1.10 CREEP/PLAST

4.1.4.1.10.1 Program Description. A finite element progr am is used for the analysis of two-dimensional (plane and axisymmetric) problems under conditions of creep and plasticity. The creep formulation is based on the memory theory of creep in which the constitutive relations are cast in the form of heredi tary integrals. The material creep properties are built into the program and they represent annealed 304 stainle ss steel. Any other cr eep properties can be included if required.

The plasticity treatment is based on kinemetic hardening and von Mises yield criterion. The hardening modulus can be constant or a function of strain.

4.1.4.1.10.2 Progr am Version and Computer. The program can be used for elastic-plastic analysis with or without the presence of creep. It can also be used for creep analysis without the presence of instantaneous plasticity. A detailed description of theory is given in Reference 4.1-17. The program is operative on UNIVAC-1108.

4.1.4.1.10.3 History of Use. This program was developed by Y. R. Rashid (Reference 4.1-17) in 1971. It underwent extensive program te sting before it was put on production status.

4.1.4.1.10.4 Extent of Application. The program is used at GE/NED in the channel cross section mechanical analysis.

4.1.4.2 Fuel Rod Thermal Analysis

Thermal design analyses of the fuel and core we re performed to verify that design criteria are met (see References 4.1-1, 4.1-4 and 4.1-5). 4.1.4.3 Reactor Systems Dynamics The analysis techniques used in reactor systems dynamics are de scribed in Sec tions S.1.3 and S.4 of Reference 4.1-1. A complete stability analysis for the reactor coolant system is provided in Section 4.4.4.2. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-16 4.1.4.4 Nuclear Engineering Analysis

The analysis techniques are described in the fuel design reports (see Reference 4.1-1). 4.1.4.5 Neutron Flue nce Calculations

See Section 4.3.2.8. 4.1.4.6 Thermal Hydraulic Calculations

The digital computer program uses a parallel fl ow path model to perform the steady-state BWR reactor core thermal-hydraulic an alysis. Program input includes the core geometry, operating power, pressure, coolant flow rate , inlet enthalpy, and the power distribution within the core. Output from the program includes core pressure drop, coolant fl ow distribution, critical power ratio, and axial variations of quality, density, and enthalpy for each fuel type.

4.

1.5 REFERENCES

4.1-1 General Electric Sta ndard Application for Reactor Fuel, NEDE-24011-P-A, and Supplement for United States, NED E-24011-P-A-US (most recent approved version referenced in COLR).

4.1-2 Supplemental Reload Licensing Repor t for Columbia (m ost recent version referenced in COLR).

4.1-3 Fuel Bundle Information Report for Columbia (most recent approved version referenced in COLR).

4.1-4 "GNF2 Advantage Generic Compliance with NEDE-24011-P-A (GESTAR II)," NEDC-33270P, (most recent vers ion referenced in COLR).

4.1-5 "GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II)," NEDC-32868P, (most recent vers ion referenced in COLR). 4.1-6 Deleted. 4.1-7 Crowther, R. L., Xenon Considerations in Design of Boiling Water Reactors, APED-5640, June 1968.

4.1-8 Deleted. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.1-17

4.1-9 Beitch, L., Shell Structures Solved Numerically by Using a Network of Partial Panels, AIAA Journal, Volume 5, No. 3, March 1967.

4.1-10 E. L. Wilson, A Dig ital Computer Program For the Finite Element Analysis of Solids With Non-Linear Material Proper ties, Aerojet General Technical, Memo No. 23, Aerojet General, July 1965. 4.1-11 I. Farhoomand and E. L. Wilson, Non-Line ar Heat Transfe r Analysis of Axisymmetric Solids, SESM Report SESM 71-6, University of California at Berkeley, Berkeley, California, 1971.

4.1-12 J. E. McConnelee, Finite-Users Manual, Gene ral Electric TIS Report DF 69SL206, March 1969.

4.1-13 R. W. Clough and C. P. Johnson, A Finite Element Approximation For the Analysis of Thin Shells, International Journal Solid Structures, Vol. 4, 1968.

4.1-14 A Computer Program For the Structural Analysis of Arbitrary Three-Dimensional Thin Shells, Report No. GA-9952, Gulf General Atomic.

4.1-15 Burgess, A. B., User Guide and Engineering Description of HEATER Computer Programs, March 1974.

4.1-16 Young, L. J., FAP-71 (Fatigue Analysis Program) Computer Code, GE/NED Design Analysis Unit R. A. Report No. 49, January 1972.

4.1-17 Rashid, Y. R, Theory Report for Creep-P last Computer Program, GEAP-10546, AEC Research and Development Report, January 1972.

FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.960690.95 Steam Separator 4.1-1Wet Steam ReturningWaterSteam Water MixtureTurning Vanes (Inlet Nozzle) Standpipe Core Discharge Plenum ReturningWaterWater Level Columbia Generating Station Final Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.98Steam Dryer Panel 4.1-2SteamFlowSteamFlowColumbia Generating StationFinal Safety Analysis Report FigureAmendment 61 December 2011 Form No. 960690 LDCN-10-029 Draw. No. Rev.910402.33 4.1-3Columbia Generating Station Final Safety Analysis Report DELETED COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-1 4.2 FUEL SYSTEM DESIGN

See Appendix A, Secti on A.4.2 of Reference 4.2-1. 4.2.1 DESIGN BASES

General Electric BWR fuel as sembly and channel design base s, analytical methods, and evaluation results are de scribed in Reference 4.2-1 (Appendix A, subsection A.4.2.1), Reference 4.2-6 and Reference 4.2-25. 4.2.1.1 Fuel System Damage Limits

4.2.1.1.1 Stress/Strain Limits

See subsection 2.2.1. 1.2 of Reference 4.2-1. 4.2.1.1.2 Fatigue Limits

See subsections 2.2. 1.2.2 of Reference 4.2-1. 4.2.1.1.3 Fretting Wear Limits

Fretting wear is considered in the mechanical design analysis of the assembly. See subsection 2.2.1.3. 2 of Reference 4.2-1. 4.2.1.1.4 Oxidation, Hydriding, and Corrosion Limits

See subsection 2.2.1. 4.2.2 of Reference 4.2-1 for the hydriding limit. Oxidation and corrosion are considered in the mechanical design analysis. See subsec tion 2.2.1.4.1.2 of Reference 4.2-1. 4.2.1.1.5 Dimensiona l Change Limits

See Reference 4.2-6 and subsection 2.2. 1.5.2 of Reference 4.2-1. 4.2.1.1.6 Internal Gas Pressure Limit See subsection 2.2.1. 6.2 of Reference 4.2-1 .

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-2 4.2.1.1.7 Hydraulic Loads Limits

See subsection 2.2.1. 7.2 of Reference 4.2-1. 4.2.1.1.8 Control Rod Reactivity Limits

See Section 3.2 and 3.3 of Reference 4.2-1 and Reference 4.2-7. 4.2.1.2 Fuel Rod Failure Limits

4.2.1.2.1 Hydriding Limits

See subsection 2.2. 2.1 of Reference 4.2-1. 4.2.1.2.2 Cladding Collapse Limits

See subsection 2.2.2. 2.2 of Reference 4.2-1. 4.2.1.2.3 Fretting Wear Limits

See subsection 2.2.1. 3.2 of Reference 4.2-1. 4.2.1.2.4 Overheating of Cladding Limits

See subsections 2.2.2.4 and 4.3.1 of Reference 4.2-1. 4.2.1.2.5 Overheating of Pellet Limits

See subsection 2.2.2. 5.2 of Reference 4.2-1. 4.2.1.2.6 Excessive Fuel Enthalpy Limits

See subsection 2.2. 2.6 of Reference 4.2-1. 4.2.1.2.7 Pellet-Claddi ng Interaction Limits

See subsection 2.2.2. 7.2 of Reference 4.2-1. 4.2.1.2.8 Bursting Limits

See subsections 2.2.2.8 a nd 2.2.3.4 of Reference 4.2-1. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-3 4.2.1.2.9 Mechanical Fracturing Limits

See subsection 2.2.2. 9.2 of Reference 4.2-1. 4.2.1.3 Fuel Coolability Limits

4.2.1.3.1 Cladding Embrittlement Limits

See Reference 4.2-10, subsection 2.2.3.1 of Reference 4.2-1. 4.2.1.3.2 Violent Expul sion of Fuel Limits

See subsection 2.2. 3.2 of Reference 4.2-1. 4.2.1.3.3 Generalized Cladding Melt Limits

Same as Section 4.2.1.3.1 and subsection 2.2. 3.3 of Reference 4.2-1. 4.2.1.3.4 Fuel Rod Ballooning Limits

Same as Section 4.2.1.2.8 . 4.2.1.3.5 Structural Deformation Limits

See subsection 2.2. 3.5 of Reference 4.2-1. 4.2.2 DESCRIPTION AN D DESIGN DRAWINGS

See References 4.2-2 and 4.2-3. 4.2.2.1 Control Rods

The control rods (typical configuration shown in Figures 4.2-1.1 , 4.2-1.2, and 4.2-1.3) perform the dual function of power shaping and reactivity control. Power distribution in the core is controlled during operation of the reactor by manipulating selected patterns of control rods. Control rod withdrawal tends to counterba lance steam void effects at the top of the core and results in significant axial power flattening.

The original control rods consists of a sheathed cruciform array of stainless steel tubes filled with boron-carbide (B 4C) powder. The control rods are 9.88 in. in total span and are separated uniformly throughout the core on a 12-in. pitch maximum. Each control rod is surrounded by four fuel assemblies.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 4.2-4 The main structural member of a control rod is made of type 304 stainles s steel and consists of a top handle, an original bottom casting with a velocity limiter and cont rol rod drive coupling, a vertical cruciform center post, and four U-shaped absorber tube sheaths. The top handle, bottom casting, and center post are welded into a single skeletal structure. The U-shaped sheaths are resistance welded to the center post, handle, and casti ngs to form a rigid housing to contain the boron-carbide-filled absorber rods. Rollers at the t op and bottom of the control rod guide the control rod as it is inserted and withdrawn from th e core. The control rods are cooled by the core bypass flow. The U-shaped sh eaths are perforated to allow the coolant to circulate freely about the absorber tubes. Op erating experience has sh own that control rods constructed as desc ribed above are not susceptible to dimensional distortions.

The boron-carbide (B 4C) powder in the absorber tubes is compacted to about 70% of its theoretical density. The boron-car bide contains a minimum of 76.5% by weight natural boron. The boron-10 (B-10) minimum content of the boron is 18% by weight. Absorber tubes are made of type 304 stainless steel . Each absorber tube is 0. 188-in. O.D. and has a 0.025-in. wall thickness. Absorber tubes are sealed by a plug welded into each end. The boron-carbide is longitudinally separated in to individual compartments by stainless steel balls at approximately 16-in. intervals. The steel balls are held in place by a slight crimp of the tube. Should boron-carbide tend to sint er in service, the steel balls will keep the resulting void spaces distributed over the le ngth of the absorber tube.

Some of the control rods have been replaced with Duralife 215 or Marathon control rods. The main structural member of the Duralife 215 cont rol rod design is made of stainless steel and consists of a top handle, a tie rod, a bottom control rod driv e coupling, and four sheaths containing the neutron absorber. The top handle, tie rod, velocity limiter, and sheaths are welded into a single structure. The neutron absorber in each wing of the sheath consists of 18 high-purity stainless-steel tube s filled with boron-carbide, three hafnium rods at the edge of the wing, and a hafnium plate at the top.

The sheaths of the Duralife 215 bl ades are attach ed to the structure w ith full fusion corner welds to the handle, tie rod, and velocity limiter to form a rigid housing. In conel X750 rollers at the top and bottom of the cont rol rod guide the control rod as it is inserted and withdrawn from the core. These rollers ro tate on PH 13-8 Mo pins. The sheaths are perforated and the hafnium absorber plate has coolan t grooves to allow the coolant to circulate freely about the absorber and flush the joint between the sheath and handle.

The number of boron carbide absorber rods in each wing has been changed from 19 rods with an I.D. of 0.138 in. to 18 rods with an I.D. of 0.148 in. Th e outside diameter remains the same. The length of the absorb er column in these rods has been reduced from 143 in. to 137 in. to accommodate a top 6-in.-high hafnium plate. In addition, three 0.188 in. O.D. hafnium rods have been added to the edge of each wing.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 4.2-5 The Marathon control rod blade consists of a top handle, a segmented tie rod (for weight savings), a bottom control rod coupling/velocity limiter and four wings consisting of an array of square tubes. The square tubes each have four lobes to allow adjacent tubes to be welded to each other. The absorber tubes are welded lengthwise to form the four wings of the control rod. Each wing is comprised of 17 absorber tubes. The four wi ngs are then welded to the tie rod to form the cruciform-shaped member of the control rod. The square tubes are circular inside and are loaded with either B 4C or hafnium. The combination of absorbers and abso rber tubes is based on the needed initial reactivity worth. In addition, empty capsules are used in some absorber tubes to provide a plenum for helium released during B 4C burnup.

A comparison of the original, the Duralife 215 and the Marathon control rod dimensions and materials is given in Table 4.2-1 . 4.2.2.2 Velocity Limiter

The control rod velocity limiter (see Figure 4.2-2 ) is an integral part of the bottom assembly of each control rod. This feature protects against a high reactivity insertion rate by limiting the control rod velocity in the event of a control rod drop accident. It is a one-way device in that the control rod scram velocity is not significantly affected but the control rod dropout velocity is reduced to a permissible limit.

The velocity limiter is in the form of two nearly mated conical elements that act as a large clearance piston inside the control rod guide tube. The lower conical element is separated from the upper conical element by four radial spacers 90 degrees apart.

The hydraulic drag forces on a control rod are approximately proportional to the square of the rod velocity and are negligible at normal rod withdrawal or rod inser tion speeds. However, during the scram stroke the rod reaches high velocity, and the drag forces must be overcome by the drive mechanism.

To limit control rod velocity dur ing dropout but not during scram, the velocity limiter is provided with a streamlined profile in the scram (upward) direction. Thus, when the control rod is scrammed water flows over the smooth su rface of the upper conical element into the annulus between the guide tube and the limiter. In the dropout direction, however, water is trapped by the lower conical el ement and discharged through the annulus between the two conical sections. Because this water is forced in a partially reversed direction into water flowing upward in the annulus, a severe turbulence is created, and this sl ows the descent of the control rod assembly to less than 5 ft/sec.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-6 4.2.3 DESIGN EVALUATION

See Appendix A, subsecti on A.4.2.3 of Reference 4.2-1. 4.2.3.1 Fuel System Damage Evaluation

4.2.3.1.1 Stress/Strain Evaluation

Fuel rod internal pressure has been shown to remain below system pressure for rod peak burnups well beyond anticipated ach ieved burnup. For GNF fuel see section 2.2.1.1.3 of Reference 4.2-1. 4.2.3.1.2 Fati gue Evaluation

See subsection 2.2.1. 2.3 of Reference 4.2-1. 4.2.3.1.3 Fretting Wear Evaluation

See Reference 4.2-12, subsection 2.2.1.3.3 of Reference 4.2-1. 4.2.3.1.4 Oxidation, Hydriding, and Corrosion Evaluation

See subsections 2.2.1.4.1.3 and 2.2.1.4.2.3 of Reference 4.2-1. 4.2.3.1.5 Dimensiona l Change Evaluation

See Reference 4.2-6, subsection 2.2.1.5.3 of Reference 4.2-1. 4.2.3.1.6 Internal Ga s Pressure Evaluation

See subsection 2.2. 6 of Reference 4.2-3 and Section 3.2. 6 of reference 4.2-2. The internal pressure is used in conjuncti on with other loads on the fuel rod cladding when calculating cladding stresses and comparing these stresses to the design criteria. The analysis results show that the calculated cladding stresses are below allowable limits even with internal gas pressure and other loads at end of life normal and transient conditions, respectively.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-7 4.2.3.1.7 Hydraulic Load Evaluation

See subsection 2.2.1. 7.3 of Reference 4.2-1, 4.2-12 and Section 3.9. 4.2.3.1.8 Control Rod Reactivity Evaluation

See Appendix A, subsecti on A.4.3.2 of Reference 4.2-1. Energy Northwest calculates the fluence of each control blade us ing an appropriate c onversion factor for fuel exposures adjacent to the control blade. Control blade shuffling or replacement is based on the calculated blade fluence as compared to vendor allowed values (Reference 4.2-22). The vendor allowed values account for the reduction in cont rol blade worth due to a comb ination of boron-10 depletion and boron loss resulting from crack ing of the absorber tubes.

4.2.3.2 Fuel Rod Failure

4.2.3.2.1 Hydriding Evaluation

See Section 4.2.3.1.4 . 4.2.3.2.2 Cladding Collapse Evaluation

See subsection 2.2. 8 of Reference 4.2-3 and Section 3.2.8 of Reference 4.2-2. 4.2.3.2.3 Fretting Wear Evaluation

See Section 4.2.3.1.3 . 4.2.3.2.4 Overheating of Cladding Evaluation

See section 2.6 of Reference 4.2-3 and Section 3.6 of Reference 4.2-2. 4.2.3.2.5 Overheating of Pellet Limits

See subsection 2.2. 9 of Reference 4.2-3 and Section 3.2.9 of Reference 4.2-2. 4.2.3.2.6 Excessive Fuel Enthalpy Evaluation

See Section 15.4.9 and subsection 2.12 of Reference 4.2-3 and Section 3.12 of Reference 4.2-2. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-8 4.2.3.2.7 Pellet-Cladding Interaction Evaluation

Calculated results do not exceed the 1% plastic strain or minimum critical power ratio (MCPR) fuel cladding integrity safety limits; thus fuel pellet melting does not occur. These are the most applicable genera l design criteria for pell et cladding interaction (PCI) phenomena. While PCI-induced fuel failures rema in a commercially undesirable pr oblem, they are not a safety concern. Boiling water reactors (BWRs) have been designed and licensed with provisions to accommodate operating with fuel cladding perforation, and field experience confirms that plants do indeed operate within radiological release limits.

Operation below the thermal-mechanical limits historically has resulted in very few pellet-cladding interaction (PCI) fuel failures. Furthermore power ma neuvering guidelines have been developed that have further reduced fuel failures due to the PCI mechanism.

4.2.3.2.8 Bursting Evaluation

See subsection 2.11.1 of Reference 4.2-3 and Section 3.11.1 of Reference 4.2-2. 4.2.3.2.9 Mechanical Fracturing Evaluation

See Reference 4.2-12 and subsection 2.2. 2.9.3 of Reference 4.2-1. 4.2.3.3 Fuel Coolability Evaluation

4.2.3.3.1 Cladding Embrittlement Evaluation

See Section 4.2.3.2.8 and subsection 2.2. 3.1 of Reference 4.2-1. 4.2.3.3.2 Violent Expulsi on of Fuel Evaluation

See Section 15.4.9 and subsection 2.12 of Reference 4.2-3 and Section 3.12 of Reference 4.2-2. 4.2.3.3.3 Generalized Cladding Melt Evaluation See Section 4.2.3.2.8 and subsection 2.11.2 of Reference 4.2-3 and Section 3.11.2 of Reference 4.2-2. 4.2.3.3.4 Fuel Rod Ballooning Evaluation

See Section 4.2.3.2.8 and subsection 2.11.1 of Reference 4.2-3 and Section 3.11.1 of Reference 4.2-2. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 4.2-9 4.2.3.3.5 Structural Deformation Evaluation See Section 4.2.3.2.9 . 4.2.4 TESTING, INSPECTION, AND SURVEILLANCE PLANS

4.2.4.1 Fuel Testing, In spection, and Surveillance

See Appendix A, subsecti on A.4.2.4 of Reference 4.2-1. 4.2.4.2 Online Fuel System Monitoring

Columbia Generating Station (CGS ) has two independent radiation detection systems that are directly capable of detecting fiss ion product releases from failed fu el rods in an online manner. The main steam line radiation (MSLR) monitors are described in Section 11.5.2.1.1 . Because the MSLR monitors are located relatively close to the reactor core, they are capable of sensing gross fission product rel eases in a few seconds.

The offgas system radiation (OGSR) monitors are capable of detecting low-level emissions of noble gases in 2 to 3 minutes af ter the gases leave th e fuel. The OGSR monitors are described in more detail in Section 11.5.2.2.1 . 4.2.4.3 Post-Irradiation Surveillance

The following fuel surveillance will be conducted after the refueling outage for the CGS unit on fuel discharged during the refueling outage that has given indication of gross cladding defects or anomalies during plant operation.

Scope The fuel surveillance program, de veloped to provide verification of the reliable performance of the CGS fuel design, will consist of the following insp ections and measurements:

a. Visual inspection of the peripheral rods will be perf ormed on discharged fuel, that has given indication of gross cla dding defects or anomalies during plant operation, after each refu eling outage. The examin ation will be capable of detecting and characterizi ng generic gross cladding defects or anomalies; and

b. If anomalous behavior of the fuel cla dding, components of the fuel assembly, or significant rod bow are detected by visual examination, further investigation, and measurements of such significant anomalies will be conducted after the refueling outages.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-038 4.2-10 Implementation

a. Onsite receiving inspection of all the initial core fuel asse mblies and subsequent reloads will be documented. Any significant anomalies detected will be documented;

b. Fuel performance histor y and related plant operationa l data will be monitored and analyzed during operation;

c. Assemblies discharged during each refueling outage that have given indication of gross cladding defects or anomalies dur ing plant operation will be selected for visual inspection. The vi sual examination of the pe ripheral rods will include observations for cladding de fects, fretting, rod bo wing, missing components, corrosion, crud deposition, and geometric distortions. The defects or anomalies

on the cladding surface area examined will be either vi deotaped or photographed to document and characterize the anomaly;

d. In the event that significant anomalies are observed during the refueling examination, all other discharged assemblies may also be visually inspected.

The results will be analyzed to determine fuel utilization strategy and possible safety implications in accordance with the operating procedures and applicable licensing requirements;

e. If unusual defects are obse rved, the fuel with the de fects and the applicable operational data will be investigated and further appr opriate tests and examination of the defected fuel will be performed; and

f. If defects of an unusual nature are detected, an oral report will be made to the NRC after the completion of the inspecti on activities. Under normal conditions, the report will contain visual examination summaries confirming the reliable performance of the fuel asse mblies. In the ev ent that significant anomalies or unusual defects are observed, the report w ill contain the description and related data of onsite receiving inspection a nd operational conditions

. Evaluation and studies to identify causes for any enc ountered anomalies or defects will be

assessed and the results w ill be reported to the NRC as they become available.

4.2.4.4 Channel Ma nagement Program

Fuel channels are subject to bulge, bow, and elongation when irradi ated in reactors. Excessive deformations (bow and bulge) c ould produce traversing in-core probe asymmetries and control blade frictional resistance.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-11 All new reload fuel will be lo aded with new channels. Energy Northwest has in the past reinserted requalified channels in CGS but has transitioned away from channel reuse (References 4.2-13, 4.2-14, and 4.2-15). The Safety Evaluation Report Re lated to the Operation of WPPSS Nuclear Project No. 2, Supplement 3 (Reference 4.2-16), discusses measurement of selected discharged fuel channels for deflection. The intent of this deflection measurement was to qualify channels for reuse. Because Energy Northwest no longe r reuses channels, the qualific ation of channel reuse has been discontinued.

In addition to the above cha nnel management program, Energy Northwest is taking a number of operational actions to monitor channel distortion in the core. These include Technical Specifications requirements for periodic scram testi ng and rod notch testing, which would provide an indication of pending driveline friction between control rod and bowed channels. Should either of these tests suggest a driveline friction problem, the tests described in NEDE-21354-P, Reference 4.2-6, would then be used to isolate the cause.

4.

2.5 REFERENCES

4.2-1 General Electric Compa ny, General Electric Standard Application for Reactor Fuel (NEDE-24011-P-A), and Supplement for United States (NEDE-24011-P-A-US) (most re cent approved version re ferenced in COLR).

4.2-2 "GNF2 Advantage Generic compliance with NEDE-24011-P-A (GESTAR II)," NEDC-33270P, (most recent vers ion referenced in COLR).

4.2-3 "GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II)," NEDC-32868P, (most recent vers ion referenced in COLR).

4.2-4 Deleted.

4.2-5 Deleted.

4.2-6 General Electric Co mpany, BWR Fuel Channel Mechanical Design and Deflection, NEDE-21354-P, September 1976. 4.2-7 General Electric Co mpany, Control Blade Life time with Potential B 4C Loss, NEDO-24226 and S upplement 1.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-12 4.2-8 Deleted.

4.2-9 Deleted.

4.2-10 General Electric Company, Analytical Model for Loss-of-Coolant Analyses in Accordance with 10 CFR 50 Appendix K, NEDO-20566-A, September 1986.

4.2-11 Deleted.

4.2-12 General Electric Company, GE Duralife 215 Control Rod Safety Evaluation, GENE-778-028-0790, Revision 2, July 1992. 4.2-13 Letter and Attachment from G. C. Sorensen, Ma nager, Regulatory Programs, Supply System to NRC,

Subject:

Nuclear Plant No. 2, Operating License NPF-21, Modification to WNP-2 Cycle Reload Submittal and Response to NRC

Bulletin 90-02: Loss of Thermal Margin Caused by Channel Box Bow, GO2-90-075, April 13, 1990.

4.2-14 Letter from G. C. Sorensen, Mana ger, Regulatory Progra ms, Supply System to NRC,

Subject:

Nuclear Plant No. 2, Operating License NPF-21, Final Response to NRC Bulletin 90-02; Loss of Thermal Margins Caused by Channel Box Bow, GO2-90-162, September 28, 1990.

4.2-15 Letter and Attachments from P. L. Eng., Project Manager, NRC to G. C. Sorensen, Manager, Regulatory Programs, Suppl y System, Evaluation of Response to NRC Bulletin 90-92; Loss of Thermal Margins Caused by Channel Box Bow (TAC No. 76354), April 22, 1991.

4.2-16 Nuclear Regulatory Commission, Sa fety Evaluation Repo rt Related to the Operation of WPPSS Nuclear Project No. 2, NUREG-0892, Supplement 3, Washington, D.C., May 1983.

4.2-17 Deleted.

4.2-18 Deleted. 4.2-19 Deleted.

4.2-20 General Electric Company, GE Marathon Control Rod Assembly (NEDE-31758P-A), October 1991. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.2-13 4.2-21 Deleted.

4.2-22 General Electric Company, GE BWR Control Rod Lifetime, NEDE-30931 (most recent revision specified in CVI 768-00,91).

4.2-23 Deleted.

4.2-24 Deleted. 4.2-25 General Electric Co mpany, Fuel Assembly Eval uation of Combined Safe Shutdown Earthquake (SSE) and Loss-of -Coolant Accident (LOCA) Loadings, NEDE-21175-3-P, July 1982. 4.2-26 Deleted.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-022 4.2-15 Table 4.2-1 Control Rod Parameters Original Equipment Duralife 215 Marathon Control rod weight, lb (kg) 186 (84.4) 204 (92.5) 197 (89.4) Absorber rod - boron-car bide Number per control rod 76 72 52 Length, in. (mm) 143 (3632) 137 (3480) 143.7 (3650) Inside diameter, in. (mm) 0.138 (3.51) 0.148 (3.76) 0.189 (4.80) Density, gr ams/cm3 1.76 (Nomi nal) 1.76 (Nomi nal) 1.76 (70% Theoretical) Absorber tube Cladding ma terial Stainless steel High purity stainless steel 304S O.D., in. (mm) 0.188 (4.78) 0.188 (4.78) 0.246 (6.248) Wall thickness, in. (mm) 0.025 (0.635) 0.020 (0.508) 0.021 (0.533) Absorber rods - hafnium Number per control rod

- 12 16 Length, in. (mm)
- 143 (3632) 143.4 (3642) Diameter, in. (mm)
- 0.188 (4.78) 0.188 (4.78) Density, gr ams/cm3  13.1 13.0 Absorber plate - hafnium Number per control rod Length, in. (mm)
- 6 (152) - Width, in. (mm)
- 3.42 (86.87) - Thickness, i

n. (mm) - 0.188 (4.78) - Density, gr ams/cm3 - 13.1 - Sheath thick ness, in. (mm) 0.030 (0.762) 0.034 (0.864) - Stiffener Yes No - Pin material Haynes Alloy 25 PH 13-8 MO PH 13-8 MO Roller material Stellite 3 Inconel X750 Inconel X750

FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.960690.96Original Equipment (OEM) Control Rod Blade Assembly4.2-1.1Columbia Generating StationFinal Safety Analysis Report LDCN-02-022 ABSORBER ROD 16 in. BETWEEN BALLS (TYPICAL) 1/2 in. (TYPICAL) 6.5"143 in. ACTIVE POISON LENGTH 9.88 in.HANDLESHEATHBLADENEUTRON ABSORBER

RODSUPPER GUIDE ROLLER TYPICAL 4 PLACES COUPLING SOCKETLOWER GUIDE

ROLLER TYPICAL 4 PLACESVELOCITY LIMITER COUPLING RELEASE

HANDLEWELDED END PLUG FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.010126.54DuraLife 215 Control Rod Blade Assembly 4.2-1.2Columbia Generating StationFinal Safety Analysis Report LDCN-02-022 Zone 2Zone 1Solid Hafnium Rods Solid Hafnium Plate Zone 2Zone 1Solid Hafnium Rods Standard B 4C Absorberwith Improved Tubing Material FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.010126.55Marathon Control Rod Blade Assembly 4.2-1.3Columbia Generating StationFinal Safety Analysis Report LDCN-02-022 HANDLEBLADENEUTRON ABSORBER RODSCOUPLING RELEASE HANDLEVELOCITY LIMITER COUPLING SOCKET FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.010126.56Marathon Control Rod Blade Absorber Details 4.2-1.4Columbia Generating StationFinal Safety Analysis Report LDCN-02-022SQUARE TYPEABSORBER TUBE ABSORBER CAPSULE B4C Placement in Capsules and Absorber Tubes GAPLOBEBORON CARBIDE POWDERAbsorber Tubes(Before Welding)Absorber Tubes Welded to Tie Rods FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.010126.57Marathon Control Rod Blade Absorber Placement 4.2-1.5LDCN-02-022CONTROL ROD CROSS PARTIAL SECTIONTOPBOTTOMTYPE 1TYPE 1HAFNIUMB4C ABSORBER CAPSULEEMPTY CAPSULE TYPE 1ABSORBER MATERIAL CONTAINED IN TUBESTYPE 2TYPE 3 TYPE 3TYPE 2TYPE ABSORBER LOADING1 ONE 143.1" LONG HAFNIUM ROD 2 FOUR 35.77" LONG B4C CAPSULES 3 THREE 35.77" LONG B4C CAPSULES ONE 23.85" LONG B4C CAPSULE ONE 11.925" LONG EMPTY CAPSULE Columbia Generating StationFinal Safety Analysis Report FigureAmendment 57 December 2003Form No. 960690.veR.oN .warD 960690.97 Control Rod Velocity Limiter 4.2-2CouplingCore Support Plate OrificeVelocity LimiterGuide Tube Control Rod Drive HousingStub TubeReactor Vessel10.420 In.148-7/16 In. 144 In.StrokeControl RodFuel Support Casting Rollers22-1/16 In. To Active Fuel Zone Columbia Generating Station Final Safety Analysis Report LDCN-02-022 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-1 4.3 NUCLEAR DESIGN

4.3.1 DESIGN BASES

See Appendix A, subsecti on A.4.3.1 of Reference 4.3-4. 4.3.1.1 Reactivity Basis

See Appendix A, subsection A.4.3.1.1 of Reference 4.3-4. 4.3.1.2 Overpower Bases

See Appendix A, subsection A.4.3.1.2 of Reference 4.3-4. 4.3.2 DESCRIPTION

See Appendix A, subsecti on A.4.3.2 of Reference 4.3-4. 4.3.2.1 Nuclear Design Description

See Appendix A, subsection A.4.3.2.1 of Reference 4.3-4. The reference core loading pattern is provided in Reference 4.3-7. See Table 4.3-2 , Table 4.3-3 and Reference 4.3-9. 4.3.2.2 Power Distribution

See Appendix A, subsection A.4.3.2.2 of Reference 4.3-4. 4.3.2.2.1 Power Distri bution Calculations

See References 4.3-7 and 4.3-3. 4.3.2.2.2 Power Distri bution Measurements

See Appendix A, subsection A.4.3.2.2.2 of Reference 4.3-4. 4.3.2.2.3 Power Distribution Accuracy

See Appendix A, subsection A.4.3.2.2.3 of Reference 4.3-4. 4.3.2.2.4 Power Dist ribution Anomalies

See Appendix A, subsection A.4.3.2.2.4 of Reference 4.3-4. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-2 4.3.2.3 Reactivity Coefficients

See Appendix A, subsection A.4.3.2.3 of Reference 4.3-4. 4.3.2.4 Control Requirements

See Appendix A, subsection A.4.3.2.4 of References 4.3-4. 4.3.2.4.1 Shutdown Reactivity

See Appendix A, subsection A.4.3.2.4.1 of Reference 4.3-4. The cold shutdown margin for the referen ce core loading pattern is provided in Reference 4.3-7. As discussed in Section 4.6.3.1.1.5 , the shutdown margin with the highest worth control rod withdrawn shall be analytically de termined to be at least 0.38% k/k or shall be determined by test to be at least 0.28% k/k. To ensure that the safety design basis for shutdown margin is satisfied, additional design margin is adopted during desi gn development so that a shutdown margin of at least 1.00% k/k is calculated with the highest worth control rod fully withdrawn.

4.3.2.4.2 Reactivity Variations

See Appendix A, subsection A.4.3.2.6 of Reference 4.3-4. The excess reactivity de signed into the core is contro lled by the control rod system supplemented by gadolinia-ura nia fuel rods (Reference 4.3-3). Control rods are used during the cycle partly to compensate for burnup and partly to control the power distribution.

Reactivity balances are not used in describing BWR beha vior because of the strong interdependence of the individua l constituents of reactivity. Therefore, th e design process does not produce components of a reactiv ity balance at the conditions of interest. Instead, it gives the keff representing all effects combined. Further, any listing of components of a reactivity balance is quite ambiguous unl ess the sequence of the cha nges is clearly defined.

4.3.2.5 Control Rod Patter ns and Reactivity Worths See References 4.3-1, 4.3-2 and 4.3-3. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-3 4.3.2.6 Criticality of Re actor During Refueling

See Appendix A, subsection A.4.3.2.6 of Reference 4.3-4. Compliance with Technical Specification shutdown margin re quirements is demonstrated through plant procedures and reactivity anal yses performed for reload specific refueling activities.

4.3.2.7 Stability

See Appendix A, subsection A.4.3.2.7 of Reference 4.3-4. 4.3.2.7.1 Xenon Transients

See Appendix A, subsection A.4.3.2.7.1 of Reference 4.3-4. 4.3.2.7.2 Thermal Hydraulic Stability

See Appendix A, subsection A.4.3.2.7.2 of Reference 4.3-4. 4.3.2.8 Vessel Irradiations

The reactor pressure vessel (RPV ) irradiation calculation provides a best-estimate prediction of the fluence rather than a conservative prediction as was the case with earlier methods. The methodology for the neutron flux calculation conforms to Licensing Topical Report (LTR) NEDC-32983-P-A (Reference 4.3-10). In general, the method ology described in the LTR adheres to the guidance in Regulatory Guide 1.190 for neutron flux evaluation and was approved by the U.S. NRC in th e Safety Evaluation Report (SER ) for referencing in licensing actions.

The fluence calculations are perf ormed with the DORTG01V discre te ordinates transport code. The LTR provides a description of the DORT cal culation used to determine the RPV fluence, as well as the calculations used to predict the measured dosimetry and validate the transport model. The calculational model includes a repres entation of the periphera l fuel assemblies and the core-internals, downcomer and vessel geomet ry. Calculations are performed to determine the bundle-average power distribution in the peri pheral fuel bundles for input to the DORT core neutron source. Calculati ons employ a relatively fine (r, , z) spatial mesh and are carried out using an S 12 angular quadrature set. The eighty-group MATXS cross section library is the basic nuclear data set. The cross secti on data used in these calculations is based on the ENDF/B-V nuclear data except for iron, hydrogen and oxygen. Since the cr oss sections for these elements have changed significantly in the more recent ENDF/B-VI data set, ENDF/B-VI cross sections were used for oxygen, hydrogen, and individua l iron isotopes. The cross section library is used in performing the energy and spatial self -shielding and removal COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-029 4.3-4 calculations. The scattering cross se ctions are represented using a P 3 Legendre expansion. The calculations are performed in azimuthal (r, ) and axial (r, z) geometries. A synthesis technique is used to determine the th ree-dimensional fluence distribution.

Figure 4.3-1 shows a quadrant of the core and the vess el internal component s that are relevant to the flux calculation (Reference 4.3-5). The reactor core is divided into three radial zones, based on the geometric layout of the bundles and their relative contribution to the shroud and RPV flux. The (r, ) analysis used the polar coordinates to define the calculation model as a planar sector between pre-selected reactor azimuths (typical ly 0° and 90°). Since the surveillance capsule is centered close to the midplane elevation of the core, core midplane data is assumed for the analysis. The model includes several material regions radially: three in-core regions, the bypass water region, shroud, downcomer water, jet-pump riser, jet-pump inlet mixer, surveillance capsule holder/bracket, and the RPV claddi ng and base metal.

The core model for the axial (r ,z) calculation is a cylinder simulating the cross-sectional area of the core at a pre-selected azimuth. For the capsule flux calcu lation, the (r,z) calculation was performed at the 300° azimuth, where the capsu le is located. For the shroud/RPV flux calculation, the azimuth of 24° was selected becaus e it is near the peak shroud flux and peak RPV flux. The core cylinder contains the afor e-mentioned three radial zones for each of the 25 axial fuel nodes. Each axial fuel node is sub-divi ded into bundle-depende nt radial regions so that each core region is modeled with its respective wate r density, structure material density, and actinide concentra tion. Similar to the (r, ) model, there are bypass water, shroud, downcomer water, a nd RPV regions beyond the core. Table 4.3-1 summarizes the neutron fluence results (Reference 4.3-5). Two sets of fluence data are presented: at th e end of 40 years (33.1 EFPY ), and at the end of 60 years (51.6 EFPY). Note EFPY is defined as 3323 MW t based effective full power years. The calculation of 33.1 EFPY factors in the uprated power (3486 MWt) from Cycle 11 through end of life (Reference 4.3-5). Fluence projections after Cycl e 17 include a 10% adder to bound potential variation in future cycles.

The RPV peak fluence (at 33.1 EFPY) given in Table 4.3-1 is used for development of the P-T limit curves. The peak 1/ 4 T fluence values (n/cm

2) used for P-T curve development are: 1.75E+17 for lower shell #1, 5.11E+17 for lo wer-intermediate sh ell #2, 2.81E+17 for N6 nozzle and 2.13E+17 for girth weld be tween shell #1 and shell #2 (Reference 4.3-6). The 1/4 T fluences were calculated in accordance with RG 1.99, Revision 2.

4.3.3 ANALYTICAL METHODS

See Appendix A, subsecti on A.4.3.3 of Reference 4.3-4. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-5 4.3.4 CHANGES

See Appendix A, subsecti on A.4.3.4 of Reference 4.3-4. 4.

3.5 REFERENCES

4.3-1 "GNF2 Advantage Generic complian ce with NEDE-24011-P-A (GESTAR II)," NEDC-33270P, (most recent vers ion referenced in COLR).

4.3-2 "GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II)," NEDC-32868P, (most recent vers ion referenced in COLR).

4.3-3 Reference Loading Pattern (most recent version referenced in COLR).

4.3-4 General Electric Sta ndard Application for Reactor Fuel, NEDE-24011-P-A, and Supplement for United States, NED E-24011-P-A-US (most recent approved version referenced in COLR).

4.3-5 GE Nuclear Energy, Washington Public Power Supply System WNP-2 RPV Surveillance Materials Testing and Analysis, Document No. GE-NE-B1301809-01, March 1997. GE Nuclear Energy, "Energy Northwest Columbia Generati ng Station Neutron Flux Evaluation," GE-NE-0000-0 023-5057-R0, April 2004.

4.3-6 GE Nuclear Energy, "Pressure-Temperature Curves for Energy Northwest Columbia," NEDC-33144-P (CVI CAL 1012-00,3).

4.3-7 Supplemental Reload Licensing Re port for Columbia (m ost recent version referenced in COLR).

4.3-8 Fuel Bundle Information Report for Co lumbia (most recent version referenced in COLR). 4.3-9 "Global Nuclear Fuels Fuel Bundle Designs," NED E-31152P, Revision 9, May 2007. 4.3-10 GE Nuclear Energy, "Licensing Topical Report, General Electric Methodoloty for Reactor Pressure Vessel Fast Neut ron Flux Evaluati ons," NEDC-32983-P-A, Revision 2, January 2006.

4.3-11 Deleted. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-6 4.3-12 GE Nuclear Energy, Washington Public Power Supply System Nuclear Project 2, "WNP-2 Power Uprate Transient Analysis Task Report,"

GE-NE-208-08-0393, September 1993.

4.3-13 GE Nuclear Energy, "Licensing Topical Report, General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations," NEDC-32983-P-A, December 2001.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 4.3-7 Table 4.3-1

Summary of Neutron Fluence Results Flux (n/cm 2-s) Fluence (n/cm

2) Cycle 10 Representative Future Cycle 40-year (33.1 EFPY)*

60-year (51.6 EFPY)* RPV At Midplane 6.92E+08 5.75E+08 6.77E+17 1.03E+18 At Peak Elevation 7.60E+08 6.27E+08 7.41E+17 1.12E+18 Peak/Midplane 1.10 1.09 1.09 1.09 Elevation for 10 17 fluence (inches above BAF) Bottom -3.3 -7.0 Top 156.2 160.0 Shroud At Midplane 1.81E+12 1.54E+12 1.80E+21 2.75E+21 At Peak Elevation 2.07E+12 1.73E+12 2.02E+21 3.06E+21 Peak/Midplane 1.15 1.12 1.12 1.11 Top Guide 2.08E+13 1.91E+13 2.15E+22 3.31E+22 Core Plate 3.39E+11 3.04E+11 3.46E+20 5.31E+20

• EFPY is defined as 3323 MWt ba sed effective full power years.

The calculation of 33.1 and 51.6 EFPY factors in the uprated power (3486 MWt) from Cycle 11 through End of Life (Reference 4.3-5). COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-8 Table 4.3-2

Reload Fuel Neutronic Design Values GE14 & GNF2 1 Fuel pellet Fuel material Density, g/cm 3 % of T.D. Diameter Enriched fuel Natural fuel Fuel rod Fuel length, full, in. Fuel length, partial, in. Cladding material Clad I.D., in. Clad O.D., in. Fuel assembly Number of fuel rods, full length Number of fuel rods, partial length Number of inert water rods Fuel rod enrichments Reference 4.3-8 Fuel rod pitch, in. Fuel assembly loading, kg uranium Reference 4.3-8 1 GNF2 and GE14 design values are provided in Table 2-1 of Reference 4.3-1. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.3-9 Table 4.3-3

Neutronic Design Values

Parameter Value Core data Number of fuel assemblies 764 Rated power, MWt 3486 Rated core flow, Mlbm/hr 108.5 Core inlet enthalpy, Btu/lbm 528.7 Reactor dome pressure, psia 1035 Fuel assembly pitch, in. 6.00 Control rod data a Absorber material B 4C Total blade span, in. 9.75 Total blade support span, in. 1.58 Blade thickness 0.260 Blade face-to-face internal dimension, in. 0.200 Absorber rods per blade 76 Absorber rods outside diameter, in. 0.188 Absorber rods inside diameter, in. 0.138 Absorber density, % of theoretical 70.0 a Original equipment control rods. Some of the control blades are replaced with Duralife 215 and Marathon control blades.

16304560090Shroud3RPVCapsuleJ/P RiserJ/P Mixer17181920212223242627252830I 151413121110987654321333333333333333333333333333233333333222222222222 222 222 222 222 222 222222 222222 221111111 11111111111 11111111111 11111111111 11111111111111 1111111111 111111111 11111111111 1111111 11111111111111111 111129960690.10 3JColumbia Generating Station Final Safety Analysis Report Core Layout and Vessel Internal ComponentsDraw. No.Rev.FigureAmendment 58 December 2005 4.3-1Form No. 960690FH LDCN-04-005 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-1 4.4 THERMAL-HYDRAULIC DESIGN

4.4.1 DESIGN BASES

4.4.1.1 Safety Design Bases

See Appendix A, subsection A.4.4.1.1 of Reference 4.4-1. 4.4.1.2 Requirements for Steady-State Conditions

See Appendix A, subsection A.4.4.1.2 of Reference 4.4-1. For purposes of maintaining adequate thermal margin during normal steady-state operation, the minimum critical power ratio (MCPR) must not be less than the required MCPR operating limit, and the maximum linear he at generation rate (MLHGR) mu st be maintained below the design linear heat generation rate (LHGR) for the plant. This does not specify the operating power nor does it specify peaking factors. These parameters are determined subject to a number of constraints including th e thermal limits given previously . The core and fuel design basis for steady-state operation (i.e., MCPR and LHGR limits) ha ve been defined to provide margin between the steady-state operating conditions and any fuel damage condition to accommodate uncertainties and to ensure that no fuel damage results even during the worst anticipated transient cond ition at any time in life.

4.4.1.3 Requirements for Anticipated Operational Occurrences (AOOs)

See Appendix A, subsection A.4.4.1.3 of Reference 4.4-1. 4.4.1.4 Summary of Design Bases

See Appendix A, subsection A.4.4.1.4 of Reference 4.4-1, and Reference 4.4-4. 4.4.2 DESCRIPTION OF THERMAL-HYDRAULIC DESIGN OF REACTOR CORE

See Appendix A, subsecti on A.4.4.2 of Reference 4.4-1. 4.4.2.1 Summary Comparison An evaluation of plant performa nce from a thermal and hydraulic standpoint is provided in Section 4.4.3. A tabulation of thermal and hydraulic parameters of the core is given in Table 4.4-1 . COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-2 4.4.2.2 Critical Power Ratio

See Appendix A, subsection A.4.4.2.2 of Reference 4.4-1, Reference 4.2-2 and Reference 4.2-3. 4.4.2.3 Linear Heat Generation Rate

See Appendix A, subsection A.4.4.2.3 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.2.4 Void Fraction Distribution

The void fraction exit values are provided in Table 4.4-2 . 4.4.2.5 Core Coolant Flow Dist ribution and Orificing Pattern

Correct distribution of core coolant flow among the fuel assemblies is accomplished by the orifices fixed at the inlet of each fuel assembly in the fuel support pieces . The orifices control the flow distribution and, hen ce, the coolant conditions within prescribed bounds throughout the design range of core operation. The sizing and design of the orifices ensure stable flow in each fuel assembly during normal operating conditions.

The core is divided into two or ifice flow zones. The outer z one is a narrow, reduced-power region around the core periphery. The inner zone is the core centr al region. No other flow or steam distribution, other than that provided by adjus ting power distribution with control rods, is used or needed.

4.4.2.5.1 Flow Distribution Data Comparison

Design core flow calculations were made using th e design power distributions. The flow distribution to the fuel assemblies was calcul ated based on the assump tion that the pressure drop across all of the fuel assemblies is the same. This a ssumption has been confirmed by measuring the flow distribution in BWRs. Therefore, there is a reasonable assurance that the calculated flow distribution throughout the core is in close agreement with the actual flow distribution (Reference 4.4-1). 4.4.2.5.2 Effect of Cha nnel Flow Uncertainties on the MCPR Uncertainty

The channel flow uncertainty has been inherently considered in its contribution to the MCPR

uncertainty when evaluating the probability of a fuel rod subject to a boiling transition in establishing the safety limit MCPR.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-3 The channel flow uncertainty is not an independent parameter cont ributing to the MCPR

uncertainty. Its effect has b een included in evaluating the pr obability of a boiling transition during a core wide power and flow calculation.

4.4.2.6 Core Pressure Drop and Hydraulic Loads

See Appendix A, subsection A.4.4.2.6 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.2.7 Correlation a nd Physical Data

See Appendix A, subsection A.4.4.2.7 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.2.8 Thermal Effects of Operational Transients

See Appendix A, subsection A.4.4.2.8 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.2.9 Uncertainties in Estimates

See Appendix A, subsecti on A.4.4.2.9 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-03-003 4.4-4 4.4.2.10 Flux Tilt Considerations

See Appendix A, subsection A.4.4.2.10 of Reference 4.4-1. 4.4.3 DESCRIPTION OF THE THERMA L AND HYDRAULIC DESIGN OF THE REACTOR COOLANT SYSTEM

4.4.3.1 Plant Configuration Data 4.4.3.1.1 Reactor Coolan t System Configuration The reactor coolant system is described in Section 5.4 and shown in isometric perspective in Figure 5.4-1 . The piping sizes, fittings , and valves are listed in Table 5.4-2 . 4.4.3.1.2 Reactor Coolant Syst em Thermal Hydraulic Data

The steady-state distribution of temperature, pressure, and flow rate for each flow path in the reactor coolant system is shown in Figure 5.1-1 . 4.4.3.1.3 Reactor Coolant System Geometric Data

Coolant volumes of regions and components within the reactor vessel are shown in

Figure 5.1-2 . Table 4.4-3 provides the flow path le ngth, height, liquid level, minimum elevations, and minimum flow areas for each major flow path volume within the reactor vessel and recirculation loops of the reactor coolant systems.

Table 4.4-4 provides the lengths and sizes of all safety injection lines to the reactor coolant system.

4.4.3.2 Operating Restrictions on Pumps

Expected recirculation pump performance curves are shown in Figures 5.4-2 and 5.4-7. These curves are valid for all conditions with a normal operating range varying from approximately 25% to 105% of rated pump flow.

The pump characteristics, including considerations of net positive suction head (NPSH) requirements, are the same for the conditions of two-pump and one-pump operation as described in Section 5.4.1. Subsection 4.4.3.3 gives the operating limits imposed on the recirculation pumps by cavitation, pump loads, bearing design flow starvation, and pump speed.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 4.4-5 4.4.3.3 Power-Flow Operating Map

4.4.3.3.1 Limits for Normal Operation

The power-flow operating map for the pow er range of operation is shown in Figure 4.4-1 . The boundaries of this map are as follows.

a. Natural circulation line: The operating state of the reactor moves along this line for the normal control rod withdrawal sequence in the absence of recirculation pump operation,

b. Maximum Extended Load Line Limi t Analysis (MELLLA)

Boundary: The line passes through 100% power at 80.7% core flow,

c. Rated power line: Constant 100% power line,

d. ICF line: Constant 106% increased core flow line, and

e. Pump cavitation interlock line: This line is required to protect either the recirculation pumps or the jet pumps from cavitation damage.

4.4.3.3.2 Regions of the Power-Flow Map

a. Region I This region defines the syst em startup operationa l capability with the recirculation pumps and motors being driven by the adjustable speed drives (ASDs). Flow is controlled by the variable speed pump, and power changes during normal startup and shutdown will be in this region;

b. Region II This is the low power area of the operating map where cavitation can be expected in the recirculation pumps and jet pumps.

Operation within this region is precluded by system interlocks that run back the pumps to minimum speed; and

c. Region III This represents the normal operating zone of the map where power changes can be made by either control rod movement or

by core flow changes through us e of the variable speed pumps. 4.4.3.3.3 Design Features for Power-Flow Control

The following limits and design features are employed to mainta in power-flow conditions to the required values shown in Figure 4.4-1

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 4.4-6 a. Minimum power limits at intermediate and high core flows. To prevent cavitation in the recirculation pumps and jet pumps, the recirculating system is provided with an interlock to run back the pump speed to 15 Hz if the difference between steam line temperature and recirculation pump inlet temperature is less than a preset value (10.7°F). This ac tion is initiated el ectronically through a time delay.

b. Minimum power limit at low core flow. During low power, low loop flow operations, the temperature differential interlock provides cav itation protection. Activation of the temperature differential interlock will run back the pump speed to 15 Hz. The ASD output speed/freque ncy is measured by instrumentation provided for monitoring the ASD. The speed change action is electronically initiated.

c. Pump bearing limit. For pumps as la rge as the recirculation pumps, practical limits of pump bearing desi gn require that minimum pu mp flow be limited to 25% of rated. To ensure this minimum flow, the system is designed so that the minimum pump speed will al low this rate of flow.

d. Valve position. To prevent structural or cavitation damage to the recirculation pump due to pump suction flow starvati on, the system is provided with an interlock to prevent starting the pumps or to trip the pumps if the suction or discharge block valves are at less than 90% open position. This circuit is activated by a position limit switch and is active before the pump is started, during individual loop manual control mode, or during ganged loop manual control.

The cavitation limits are establis hed for two-pump opera tion, but will not protect the jet pumps and recirculation pumps on one-pu mp operation. Therefore, a dditional procedural operational limits are established to prevent cavitation damage during th e single loop operation. One-pump operation is restricted to the Extended Load Line Limit Analysis (108% rodline) boundary because extended operation in the MELLLA domain has not been evaluated. The procedural operational limits are shown in Figure 4.4-2 . Flow Control. The principal modes of normal operation with ASD flow control are summarized as follows: The recirculation pumps are started when the suction and discharge block valves are full open; with the pump speed at 15 Hz the reactor heatup and pressurization can commence. When operating pressure has been established, reactor power can be increased. This power-flow increase will follow a line within Region I of the flow control map shown in Figure 4.4-1 . When reactor power is greater than approximately 20% of rated, the steam line to recirculation pump inlet differential temperature low feedwater flow interlock is cleared and the main

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 4.4-7 recirculation pump speed can be manually increased from 15 Hz. The system is then brought to the desired power-flow level within the normal operating area of the map (Region III) by individual loop control or manual ganged control of the ASD sy stem output frequency and by withdrawing control rods.

Recirculation pump speed increa ses resulting from ASD system output frequency increases toward 63 Hz with constant c ontrol rod position will result in power/flow changes along, or nearly parallel to, the 100% rod line.

4.4.3.4 Temperature-Po wer Operating Map Not applicable.

4.4.3.5 Load-Following Characteristics

The automatic load following featur e has been deleted from the system. All load increases or decreases on CGS are manually controlled by the operator.

4.4.3.6 Thermal and Hydraulic Characteristics Summary Table

The thermal-hydraulic charact eristics are provided in Table 4.4-1 for the core and tables of Section 5.4 for other portions of the reactor coolant system.

4.4.4 EVALUATION

See Appendix A, subsections A.4. 4.4 - A.4.4.4.5 of Reference 4.4-1, Reference 4.4-2 and Reference 4.4-3. 4.4.4.1 Bypass Flow

Table 4.4-5 shows the bypass flows for the two cases of the GE14 and GNF2 core.

4.4.4.2 Thermal Hydraulic Stability Analysis

Core thermal-hydraulic analyses are performed in accordance with the Long-Term Stability Solutions Option III methodology descri bed in Reference 4.4-1. The analysis supporting the OPRM System Period Based Detec tion Algorithm (PBDA) setpoints is presented in Reference 4.4-4. A backup stability protection may be used on an interim basis as allowed by Technical Specifications. The analysis supporting the backup stability protection is presented in Reference 4.4-4, and the methods used in the backup stab ility protection analysis are presented in Reference 4.4-1. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-8 4.4.5 TESTING AND VERIFICATION

See Appendix A, subsecti on A.4.4.5 of Reference 4.4-1. 4.4.6 INSTRUMENTATION REQUIREMENTS

See Appendix A, subsecti on A.4.4.6 of Reference 4.4-1. 4.4.6.1 Loose Parts

The instrumentation for online monitoring for loose parts in the reactor vessel has been deactivated.

See Section 7.7.1.12 for further information.

4.

4.7 REFERENCES

4.4-1 General Electric Compa ny, General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A, and Supp lement for United States, NEDE-24011-P-A-US (most recent approved version re ferenced in COLR).

4.4-2 "GNF2 Advantage Generic Compliance with NEDE-24011-P-A (GESTAR II)," NEDC-33270P, (most recent vers ion referenced in COLR).

4.4-3 "GE14 Compliance with Amendment 22 of NEDE-24011-P-A (GESTAR II)," NEDC-32868P, (most recent vers ion referenced in COLR).

4.4-4 Supplemental Reload Licensing Repor t for Columbia (m ost recent version referenced in COLR).

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-029 4.4-9 4.4-9 GEXL97 Correlation Applicable to ATRIUM-10 Fu el, NEDC-33419P, Revision 0, June 2008.

4.4-10 Methodology and Uncertainties for Safety Limit MCPR Evaluations, NEDC-32601P-A, August 1999.

4.4-11 Power Distribution Uncertainties for Safety Limit MCPR Evaluations, NEDC-32694P-A, August 1999. 4.4-12 Fuel Bundle Information Report for Columbia (most recent version referenced in COLR).

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 4.4-11 Table 4.4-1 Thermal and Hydraulic Design Characteristics of the Reactor Core

General Operating C onditions Parameter Reference design thermal output, MWt 3486 Power level for engineered safety features, MWt 3716 Steam flow rate, at 421.2F final feedwater temperature, millions lb/hr 15.01 Core coolant flow rate range, millions lb/hr 87.6-115 Feedwater flow rate, millions lb/hr 14.98 System pressure, nominal in steam dome, psia 1035 Core exit pressure, nominal, psia 1047 Coolant saturation temperatur e at core design pressure, F 550 Average power density, kW/liter 51.56 Average linear heat generation rate, kW/ft 4.05 Core total heat transfer area, ft 2 86,099 Average heat flux, Btu/hr-ft 2 132,790 Design operating minimum critical power ratio (MCPR) (see COLR) a Core inlet enthalpy at 421.2F FFWT, Btu/lb 528.7 Core inlet temperature, at 421.2F FFWT, F 533.9 Power assembly exit void fraction, % (RPF=1.0) 71.2 Assembly flow, klbm/hr 120.4 b Core pressure drop, psid 23.437 b a Core Operating Limits Report. b Based on full core of GE14, (1035 psia dome pressure, 3486 MWt (100%) power and 108.5 Mlbm/hr (100% of rated core flow).

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-12 Table 4.4-2

Mixed Core Thermal Hydraulic Analysis Results a GE14 GNF2 Assembly flow (Klb/hr) 109.69 115.12 Exit quality (active region) 0.259 0.259 Exit void fraction 0.824 0.824 Critical power ratio b 1.575 1.671 a Core ~1/3 GNF2 fuel and 2/3 GE14 fuel 3545 MWt core power and 10 8.5 Mlbm/hr core flow. Values for a high power assembly

1.40 radial peaking factor.

b Estimates obtained using the GEXL critical power correlation (References 4.4-2 and 4.4-3). COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.4-13 Table 4.4-3 Reactor Coolant System Geometric Data

Flow Path Length (in.) Height and Liquid Level (in.) Elevation of Bottom of Each Volume a Minimum Flow Areas (ft2) Lower plenum 216 216 216 -172.5 71.5 Core 164 164 164 44.0 142.0 Upper plenum and

separators 178 178 178 208.0 49.5 Dome (above normal

water level) 312 312 0 386.0 343.5 Downcomer area 321 321 321 -51.0 79.5 Recirculation loops and

jet pumps (one loop) 108.5 ft 403 403 -394.5 132.5 in2 a Reference point is recircu lation nozzle outlet centerline.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.4-14 Table 4.4-4 Lengths and Sizes of Safety Injection Lines

Line O.D. (in.) Line Length (ft) HPCS line Pump discharge to valv ea 16 319 From HPCS-V-4 inside con tainment to RPV 12.75 108 Total 427 LPCI lines Loop A 1. Pump d ischarge to reducer 18 421 2. Reducer to injection valve, a RHR-V-42A 14 6 3. From RHR-V-42A to RPV 14 94 Total 521 Loop B 1. Pump d ischarge to reducer 18 394 2. Reducer to inject ion valve RHR-V-42B 14 6

3. Inside containment to RPV 14 93 Total 493 Loop C 1. Pump d ischarge to reducer 18 71

2. Reducer to inject ion valve RHR-V-42C 14 138

3. Inside containment to RPV 14 99 Total 308 LPCS line Pump discharge to valv ea 16 222 Inside containment to RPV 12.75 117 Total 339 a Injection valve located as near as possible to outside of c ontainment wall.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 4.4-15 Table 4.4-5 a,b Core Pressure Drop and Leakage Flow Results for Core Configurations Case Core Pressure Drop (psid) Core Bypass Flow (%) 1: All GE14 core 24.403 11.7 2: All GNF2 core 23.626 11.1 a Core power: 3545 MWt; core flow: 108.5 Mlb/hr. b Including both leakage flow and water rod flow.

FigureAmendment 63 December 2015 Form No. 960690 LDCN-10-004 Draw. No. Rev.960690.03 4.4-11Columbia Generating Station Final Safety Analysis Report Power-Flow Operating Map Two Loop Operation 0010203040506070809010011012040003500CDEFGHBAI300025002000150010005000102030405060 Core Flow (% of Rated) Core Flow (Mlbm/hr)7080901001101200102030405060708090100110120130Thermal Power (% of Rated) Thermal Power (MWt) Region IJet Pump Cavitation InterlockMinimumPump Speed Increased Core Flow RegionNatural Circulation Flow Line MELLLABoundaryRegion IIIRegion II100% Power = 3486 Mwt100% Core Flow = 108.5 Mlbm/hr A: B: C: D: E: F: G: H: I:49.4% Power/ 23.8% Flow 57.5% Power/ 32.3% Flow100.0% Power/ 80.7% Flow100.0% Power/100.0% Flow 100.0% Power/106.0% Flow65.1% Power/106.0% Flow 60.4% Power/100.0% Flow33.0% Power/ 65.4% Flow 14.6% Power/ 30.4% Flow FigureAmendment 59 December 2007 Form No. 960690 LDCN-07-011 Draw. No. Rev.060108.05 4.4-2Columbia Generating Station Final Safety Analysis Report Power-Flow Operating Map Single Loop Operation 01020 30 40 506070 8090010203040506070Percent Thermal Power(Rated Thermal Power = 3486 MWth)Percent Core Flow (Rated Core Flow = 108.5 Mlb/hr)NaturalCirculationFlow LineMinimum Pump S peedPump Cavitati on Interlock LineExtended Load Line Limit(108% Rod Line)Procedural Operati on Limit(Jet Pump Nozzle Cavitati on Line) COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-086 4.5-1 4.5 REACTOR MATERIALS

4.5.1 CONTROL ROD SYSTEM STRUCTURAL MATERIALS

4.5.1.1 Material Specifications

The following material listing applies to the c ontrol rod drive (CRD) mechanism supplied for this application. The position indicator and minor nonstructural items are omitted.

a. Cylinder, tube, and flange assembly Flange ASME SA 182 grade F304

Housing cap screws ASME SA 540 g rade B23, CL4 or SA 193 grade B7

Plugs ASME SA 182 grade F304

Cylinder ASTM A269 grade TP 304

Outer tube ASTM A269 grade TP 304

Tube ASTM A269 grade TP 304

Spacer ASTM A269 grade TP 304 or ASTM A511 grade MT 304

b. Piston tube assembly Piston tube ASTM A269 grade TP 304 or ASTM A479 grade XM-19

Stud ASTM A276 type 304

Head/base ASME SA 182 grade F304

Indicator tube ASME SA 312 type 316

Cap ASME SA 182 grade F304 or TP 316

c. Drive assembly Coupling spud Inconel X-750

Index tube ASTM A269 grade TP 304 or ASTM A479 grade XM-19 COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-086 4.5-2 Piston head Armco 17-4 PH

Coupling ASME SA 312 grade TP 304 or ASTM A511 grade MT 304

Magnet housing ASME SA 312 grade TP 304 or ASTM A511 grade MT 304

d. Collet assembly Collet piston ASTM A269 grade TP 304 or ASME SA 312 grade TP 304

Finger Inconel X-750

Retainer ASTM A269 grade TP 304 or ASTM A511 grade MT 304

Guide cap ASTM A269 grade TP 304

e. Miscellaneous parts Stop piston ASTM A276 type 304

Connector ASTM A276 type 304

O-ring spacer ASME SA 240 type 304

Piston tube nut ASME SA 194 grade B8 or B8A or SA 479 grade XM-19

Barrel ASTM A269 grade TP 304 or ASME SA 312 grade TP 304 or ASME SA 240 type 304

Collet spring Inconel X-750

Ring flange ASME SA 182 grade F304

Ring flange cap ASME SA 193 grade B6 screws The materials listed under ASTM specification numbers are all in the annealed condition (with

the exception of the outer tube in the cylinder, tube, and flange assemb ly), and their properties COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-086 4.5-3 are readily available. The outer tube is appr oximately 1/8 hard and ha s a tensile strength of 90,000/125,000 psi, yield strength of 50,000/85, 000 psi, and minimu m elongation of 25%.

The coupling spud, collet fingers, and collet spri ng are fabricated from Inconel X-750 in the annealed or equalized condition and heat treat ed to produce a tensile strength of 165,000 psi minimum, yield of 105,000 psi minimum, and elongation of 20% minimum. The piston head is Armco 17-4 PH in condition H-1100, with a tensile strength of 140, 000 psi minimum, yield of 115,000 psi minimum, and elongation of 15% minimum.

These are widely used materials, whose prope rties are well known. The parts are readily accessible for inspection and replacement if necessary.

4.5.1.2 Special Materials

No cold-worked austenitic stainless steels with a yield strength greater than 90,000 psi are employed in the CRD system. Armco 17-4 PH (p recipitation hardened stainless steel) is used for the piston head. This material is aged to the H-1100 condition to produce resistance to stress corrosion cracking in the BWR environments. Armco 17-4 PH (H-1100) has been

successfully used in the past in BWR drive mechanisms. Th e only hardenable martensitic stainless steel used is the ring flange cap screws. The material is TP 410 in the H-1100 condition.

4.5.1.3 Processes, Inspections, and Tests

All austenitic stainless steel used in the CRD sy stem is solution annealed material with one exception, the outer tube in the cylinder, tube, and flange assembly (see Section 4.5.1.1). Proper solution annealing is verified by testing per ASTM A262, "Recommended Practices for

Detecting Susceptibility to Intergranul ar Attack in Stainless Steels."

Two special processes are employed which subject selected components to temperatures in the

sensitization range. These processes are perf ormed on austenitic stainless steel, including XM-19.

a. The cylinder (cylinder, tube, and fla nge assembly) and the retainer (collet assembly) are hard surfaced with Colmonoy 6.

b. The following components are nitrided to provide a wear resistant surface:

1. Tube (cylinder, tube

, and flange assembly) 2. Piston tube (piston tube assembly)

3. Index tube (drive line assembly)

4. Collet piston and guide cap (collet assembly)

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 4.5-4 Colmonoy hard-surfaced component s have performed successfully in the past in drive mechanisms. Nitrided compone nts have accumulated many years of BWR service. It is normal practice to remove some CRDs periodica lly during refueling outages. At this time, both the Colmonoy hard-surfaced parts and n itrided surfaces are accessible for visual examination. In addition, dye penetrant ex aminations have been performed on nitrided surfaces of the longest service drives. This inspection program is adequate to detect any incipient defects before they could become serious enough to cause operating problems. All austenitic stainless steel is required to be in the solution heat treated condition. Welding is performed in accordance with Section IX of the ASME Boiler and Pressure Vessel (B&PV) Code. Heat input for stainless-steel welds is restricted to a maximum of 50,000 joules/in. and interpass temperature to 350°F. Heating above 800°F (except for welding) is prohibited unless the welds are subsequently solution annealed. These controls are employed to avoid

severe sensitization and comply with the intent of Regulatory Guide 1.44.

4.5.1.4 Control of De lta Ferrite Content

All type 308 weld metal is required to comply with a specification which requires a minimum of 5% delta ferrite. This amount of ferrite is adequate to prevent any micro-fissuring (hot

cracking) in austenitic stainless steel welds. (See Section 4.5.2.4.) 4.5.1.5 Protection of Materials During Fabrication, Shipping, and Storage

All the CRD parts listed in Section 4.5.1.1 are fabricated under a process specification which limits contaminants in cutting, gr inding, and tapping cool ants and lubricants. It also restricts all other processing materials (marking inks, tape, etc.) to those which are completely removable by the applied cleaning process. All contaminants are then required to be removed by the appropriate cleaning process prior to any of the following:

a. Any processing which increases part temperature above 200°F, b. Assembly which results in decr ease of accessibility for cleaning, and c. Release of parts for shipment.

The specification for packaging and shi pping the CRD provides for the following:

The drive is rinsed in hot deionized water and dried in preparation for shipment. The ends of

the drive are then covered with a vapor tight ba rrier with desiccant. Packaging is designed to protect the drive and prevent damage to th e vapor barrier. The planned storage period considered in the design of the container and packaging is 2 years. This packaging has been in use for a number of years. Periodic audits have indicated satisfactory protection. The degree of surface cleanliness required by th ese procedures meets the requirements of Regulatory Guide 1.37. COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-11-040 4.5-5 Site or warehouse storage specifications require in side heated storage comp arable to level B of ANSI 45.2.2. After the second year, a yearly inspection of 10% of the humidity indicators (packaged with the drives) is required to verify that the units are dry.

4.5.2 REACTOR INTERNAL MATERIALS

4.5.2.1 Material Specifications

Materials used for the core support structure:

a. Shroud support - Nickel chrome iron alloy, ASME SB166 or SB168,

b. Shroud, core plate (and aligners),

top guide (and aligne rs), and internal structures welded to these compone nts, ASME SA240, SA182, SA479, SA312, SA249, or SA213 (all type 304, except the shroud which is 304L),

c. Peripheral fuel s upports - SA312 type 304,

d. Core plate studs and nuts. SA193 grade B8, SA194 grade 8 (all type 304),

e. Control rod drive housing. AS ME SA312 type 304, SA182 type 304,

f. Control rod drive guide tube. AS ME SA351 type CF8, SA358. SA312, SA249 (type 304), and

g. Orificed fuel support. ASME SA351 type CF8.

Materials used in the steam separators and steam dryers:

a. All materials are type 304 stainless steel,

b. Plate, sheet, and strip ASTM A240, type 304,

c. Forgings ASTM A182, grade F304,

d. Bars ASTM A479, type 304,

e. Pipe ASTM A312, grade TP 304,

f. Tube ASTM A269, grade TP 304,

g. Bolting material ASTM A193, grade B8,

h. Nuts ASTM A194, grade 8, and

i. Castings ASTM A351, grade CF8.

Materials used in the jet pump assemblies:

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-06-000 4.5-6 The components in the jet pump assemblies are a ri ser, restrainer brackets, inlet-mixers, slip joint clamps, diffusers, and a riser brace. Materials used for these components are to the

following specifications:

a. Castings ASTM A351 grade CF 8 and ASME SA351 grade CF3,

b. Bars ASTM A276 type 304 and ASTM A370 grade E38 and E55,

c. Bolts ASTM A193 grade B8 or B8M,

d. Sheet and plate ASTM A240 t ype 304, ASTM A276 type 304, ASTM A358, and ASME SA240 type 304L,

e. Tubing ASTM A269 grade TP 304,

f. Pipe ASTM A358 type 304 and ASME SA312 grade TP 304,

g. Welded fittings ASTM A403 grade WP304, and

h. Forgings ASME SA182 grade F304, ASTM B166, and ASTM A637 grade 688.

Materials in the jet pump assemblies which are not type 304 stainless steel are listed below:

a. The inlet mixer adapter casting, the wedge casting, bracket casting adjusting screw casting, and the diffuser collar cas ting are type 304 hard-surfaced with Stellite 6 for slip fit joints;

b. The diffuser is a bimetallic component made by welding a type 304 forged ring to a forged Inconel 600 ring, ma de to Specification ASTM B166;

c. The inlet-mixer contains a pin, inse rts and beam made of Inconel X-750 to Specification ASTM B637 grade UNS N07750 (Beam), and ASTM A370 grade

E38 and E55 (pin and insert);

d. The jet pump beam bolt is type 316L stainless steel;

e. The jet pump slip joint clamp body is fabricated from solution heat-treated ASTM A-182/ASME SA-182 Grade F XM-19 stainless steel with a maximum of 0.04% carbon;

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-06-000 4.5-7 f. The jet pump slip joint clamp adjustable bolt, bolt retainer, pins, and ratchet lock spring are fabricated from ASTM B-637/ASME SB-637 UNS N07750

Type 3 (Alloy X-750); and

g. All components of jet pump restrainer bracket auxiliary wedge assemblies are fabricated from ASTM B-637 UNS N07750 Type 3 (Alloy X-750), except for

the frame.

All core support structures are fabricated from ASME specified materi als and designed using ASME Code Section III, Appendix I allowable st resses, and ASME Code Section III, Class I, reactor vessel design rules as guides. The othe r reactor internals are fabricated from ASTM specification materials. Material requirements in the ASTM specificati ons are identical to requirements in corresponding ASME material specifications. The allowable stress levels

specified in ASME Code Section III, Appendix I, are used as a guide in the design of all internal structures in the reactor.

4.5.2.2 Controls on Welding

For core support structures and other internals, weld procedures and welders are qualified in accordance with the ASME B&PV Code, Section IX.

4.5.2.3 Nondestructive Examination of Wrought Seamless Tubular Products

Wrought seamless tubular products are used in the fabrication of the CRD housing. This

ASME Code Section III component is designed to the rules of S ubsection NB, and the material specified is ASME SA-312 supplemented by GE specifications which invoke Subsection NB requirements. This material meets the requi rements of NB-2550 and meets the intent of Regulatory Guide 1.66. The CRD housings are built to the 1971 Edition, Summer 1971 Addenda of the code.

Other internal non-code safety and non-safety components are optionally fabricated from wrought seamless tubular products. This material is supplied in accordance with the applicable ASTM material specifications and is nondestructively examined to th e extent specified therein. In addition, the specification for tubular produc ts employed for CRD housings external to the

reactor pressure vessel (RPV) meet requirement s of paragraph NB-2550 which meets the intent of Regulatory Guide 1.66.

Other internals are non-coded, and wrought seamless tubular products were supplied in accordance with the applicable AS TM material specifications. These specifications require a hydrostatic test on each length of tubing.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 4.5-8 4.5.2.4 Fabrication and Pro cessing of Austenitic Stainless Steel - Regulatory Guide Conformance Regulatory Guide 1.31, Control of Stainless Steel Welding All austenitic stainless steel weld filler materi als were supplied with a minimum of 5% delta ferrite. This amount of ferrite is considered adequate to prevent micro-fissuring in austenitic stainless steel welds. An extensive test program performed by Gene ral Electric Company, with the concurrence of the Regulatory Staff, has demonstrated that controlling weld filler metal ferrite at 5% minimum produces produc tion welds which meet the requirements of Regulatory Guide 1.31. A total of approxima tely 400 production welds in five BWR plants were measured and all welds met the require ments of the Interim Regulatory Position to Regulatory Guide 1.31.

Regulatory Guide 1.34, Control of Electroslag Weld Properties.

Electroslag welding is not empl oyed for any reactor internals.

Regulatory Guide 1.36, Nonmetallic Thermal Insulation for Austenitic Stainless Steel.

Nonmetallic thermal insulation is not employed fo r any components in the reactor vessel. For external applications, all nonmetallic insu lation meets the requirements of Regulatory Guide 1.36.

Regulatory Guide 1.44, Control of th e Use of Sensitized Stainless Steel.

All wrought austenitic stainless steel was solu tion heat treated. Heating above 800°F was prohibited (except for welding) unless the stainl ess steel was subsequently solution annealed. Purchase specifications restricted the maximum weld heat input to 110,000 joules per in., and the weld interpass temperature to 350°F maximum. Welding was performed in accordance

with Section IX of the ASME B&PV Code S ection IX. These controls were employed to avoid severe sensitization a nd comply with the intent of Regulatory Guide 1.44.

Regulatory Guide 1.71, Welder Qualifi cation for Areas of Limited Accessibility

Welder qualification for areas of limited accessibility is discussed in Sections 1.8.2 and 1.8.3. 4.5.2.5 Contamination, Pr otection, and Cleaning of Austenitic Stainless Steel

Exposure to contaminant was avoided by caref ully controlling all cleaning and processing materials which contact stainless steel during manufacture and constructi on. Any inadvertent surface contamination was removed to avoid potential detrimental effects.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 4.5-9 Special care was exercised to ensure removal of surface contaminants prior to any heating operation. Water quality for ri nsing, flushing, a nd testing was contro lled and monitored. The degree of cleanliness required by these procedures meets the requirements of Regulatory

Guide 1.37.

4.5.3 CONTROL ROD DRIVE HOUSING SUPPORTS

The American Institute of Steel Construc tion (AISC) Manual of Steel Construction, "Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings," was

used in designing the CRD housing support system . However, to provide a structure that absorbs as much energy as practical without yielding, the allowa ble tension and bending stresses used were 90% of yield and the shear stress used was 60% of yield. These design stresses are 1.5 times the AISC allowable stre sses (60% and 40% of yield, respectively).

For purposes of mechanical design, the postulated failure resulting in the highest forces is an instantaneous circumferential se paration of the CRD housing from the reactor vessel, with the reactor at an operating pressure of 1086 psig (a t the bottom of the vessel) acting on the area of the separated housing. The weight of the se parated housing, CRD, and blade, plus the pressure of 1086 psig acting on the area of the separated housing, gives a force of approximately 32,000 lb. This force is used to calculate the impact force, conservatively assuming that the housing travels through a 1-in . gap before it contacts the supports. The impact force (109,000 lb) is then treated as a static load in design. The CRD housing supports are designed as Seismic Category I e quipment in accordance with Section 3.2. All CRD housing support subassemblies are fabricated of ASTM A36 structural steel, except

for the following items:

a. Grid ASTM A441,

b. Disc springs Schne rr, type BS-125-71-8, c. Hex bolts and nuts ASTM A307, and d. 6 x 4 x 3/8 tubes ASTM A500 grade B.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-1 4.6 FUNCTIONAL DESIGN OF REACTIVITY CONTROL SYSTEMS Functional design of the contro l rod drive (CRD) system is discussed below. Functional designs of the recirculation flow control syst em and the standby liqui d control (SLC) system are described in Sections 5.4.1 and 9.3.5, respectively.

4.6.1 INFORMATION FOR THE CONTROL ROD DRIVE SYSTEM

4.6.1.1 Control Rod Drive System Design

4.6.1.1.1 Design Bases

4.6.1.1.1.1 Safety Design Bases . The CRD mechanical system meets the following safety design bases:

a. The design provides for a sufficiently rapid control rod insertion that no fuel damage results from any a bnormal operating transient.

b. The design includes positioning devices, each of which individually supports and positions a control rod.

c. Each positioning device

1. Prevents its control ro d from initiating withdrawal as a result of a single malfunction,

2. Is individually operated so that a failure in one positioning device does not affect the operation of any other positioning device, and

3. Is individually energized when ra pid control rod insertion (scram) is signaled so that failure of power sources external to the positioning device does not prevent other positi oning devices' control rods from being inserted.

4.6.1.1.1.2 Power Ge neration Design Basis. The CRD system design provides for positioning the control rods to control power generation in the core.

4.6.1.1.2 Description

The CRD system controls gross changes in co re reactivity by incrementally positioning neutron absorbing control rods within the reactor core in response to manua l control signals. It is also required to quickly shut down the reactor (scram) in emergency situations by rapidly inserting withdrawn control rods into the core in response to a manual or automatic signal. The CRD COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-2 system consists of locking piston CRD mechanisms, and the CRD hydraulic system (including power supply and regulation, hydraulic cont rol units (HCUs), interconnecting piping, instrumentation and electrical controls).

4.6.1.1.2.1 Control Rod Drive Mechanisms . The CRD mechanis m (drive) used for positioning the control rod in the reactor core is a double-acting, mechanically latched, hydraulic cylinder using w ater as its operating f luid (see Figures 4.6-1 through 4.6-4). The individual drives are mounted on the bottom head of the reactor pressure vessel (RPV). The drives do not interfere with refueling and are operative even when the head is removed from the RPV.

The drives are also readily accessible for inspection and servic ing. The bottom location makes maximum utilization of the water in the reactor as a neutron shie ld and gives the least possible neutron exposure to the drive components. Using water from the condensate treatment system and/or condensate storage tanks as the operating fluid eliminates the need for special hydraulic fluid. Drives are able to utilize simple pi ston seals whose leakage does not contaminate the reactor water but provides cooling for the drive mechanisms and their seals.

The drives are capable of inserting or withdrawing a control rod at a slow, controlled rate, as well as providing rapid inserti on when required. A mechanism on the drive locks the control rod at 6-in. increments of str oke over the length of the core.

A coupling spud at the t op end of the drive index tube (piston rod) engages and locks into a mating socket at the base of th e control rod. The weight of the control rod is sufficient to engage and lock this coupling. Once locked, the drive and rod form an inte gral unit that must be manually unlocked by specific procedures before the components can be separated.

The drive holds its control rod in distinct latch positions until the hydr aulic system actuates movement to a new position. Withdrawal of each rod is limited by a seating of the rod in its guide tube. Withdrawal beyond this position to the over-travel limit can be accomplished only if the rod and drive are uncoupled. Withdrawal to the over-travel lim it is annunciated by an alarm.

The individual rod indicators, grouped in one control panel display, correspond to relative rod locations in the core. A separate, smaller display is located ju st below the large display on the vertical part of the benchboard. This display presents the positi ons of the control rod selected for movement and the other rods in the affected rod group.

For display purposes the control r ods are considered in groups of four adjacent rods centered

around a common core volume. Each group is monitored by four local power range monitor (LPRM) strings (see Section 7.6.1.4). Rod groups at the periphery of the core may have less than four rods. The small rod display shows th e positions, in digital form , of the rods in the COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-3 group to which the selected rod belongs. A white light indicates which of the four rods is the one selected for movement.

4.6.1.1.2.2 Drive Components . Figure 4.6-2 illustrates the op erating principle of a drive. Figures 4.6-3 and 4.6-4 illustrate the drive in more detail. The main components of the drive and their functions ar e described below.

4.6.1.1.2.2.1 Drive Piston . The drive piston is mounted at the lower end of the index tube. This tube functions as a pist on. The drive piston and index tube make up the main moving assembly in the drive. The drive piston ope rates between positive end stops, with a hydraulic cushion provided at the upper e nd only. The piston has both insi de and outside seal rings and operates in an annular space between an inne r cylinder (fixed piston tube) and an outer cylinder (drive cylinder). Because the type of inner seal used is effective in only one direction, the lower sets of seal rings are m ounted with one set sea ling in each direction.

A pair of nonmetallic bushings prevents metal-to-metal contact between the piston assembly and the inner cylinder surface. The outer pist on rings are segmented step-cut seals with expander springs holding the segm ents against the cylinder wall. A pair of split bushings on the outside of the piston preven ts piston contact with the cyli nder wall. The effective piston area for down-travel or withdrawal is approximately 1.2 in. 2 versus 4.1 in. 2 for up-travel or insertion. This difference in driving area tends to balance the control rod weight and ensures a higher force for insertion than for withdrawal.

4.6.1.1.2.2.2 Index Tube. The index tube is a long hollow shaft made of nitrided stainless steel. Circumferentia l locking grooves, spaced every 6 in. along the outer surface, transmit the weight of the control rod to the collet assembly.

4.6.1.1.2.2.3 Collet Assembly. The collet assembly serves as the index tube locking mechanism. It is located in the upper part of the drive unit. This assembly prevents the index tube from accidentally moving downward. The assembly consists of the collet fingers, a return spring, a guide cap, a collet housing (par t of the cylinder, tube, and flange), and the collet piston.

Locking is accomplished by fingers mounted on the collet piston at the top of the drive cylinder. In the locked or latched position the fingers engage a locki ng groove in the index tube.

The collet piston is normally held in the latc hed position by a force of approximately 150 lb supplied by a spring. Metal pist on rings are used to seal the collet piston from reactor vessel pressure. The collet assembly will not unlatch until the collet fingers are unloa ded by a short, automatically sequenced, drive-in signal. A pressure, approxim ately 180 psi force, slide the collet up against the conical surfac e in the guide cap, and spread the fingers out so they do not engage a locking groove. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-4 A guide cap is fixed in the upper end of the drive assembly. This member provides the unlocking cam surface for the collet fingers and serves as the upper bushi ng for the index tube.

If reactor water is used durin g a scram to supplement accumu lator pressure, it is drawn through a filter on the guide cap.

4.6.1.1.2.2.4 Piston Tube. The piston tube is an inner cylinder, or column, extending upward inside the drive piston and index tube. Th e piston tube is fixed to the bottom flange of the drive and remains stationary. Water is brought to the upper side of the drive piston through this tube. A buffer shaft, at the uppe r end of the piston tube , supports the stop piston and buffer components.

4.6.1.1.2.2.5 Stop Piston . A stationary piston, called the stop piston, is mounted on the upper end of the piston tube. This piston provides the seal between reactor vessel pressure and the space above the drive piston. It also functi ons as a positive end stop at the upper limit of control rod travel. Piston ri ngs and bushings, simila r to those used on the drive piston, are mounted on the upper portion of the stop piston. The lower end of the stop piston is threaded on to the top of the piston tube forming a spac e for a set of spring washers which serve to protect both the drive piston and the stop piston from damage as the dr ive piston reaches its end of travel. The upper end of the piston tube has a series of orific es which hydraulically dampen the drive piston motion as the inner seals (or buffer seals) slide past them, effectively cutting off the exhaust path for the over-piston water. The high pressu res generated in the buffer are confined to the cyli nder portion of the stop piston, a nd are not applied to the stop piston and drive piston seals.

The center tube of the drive mechanism forms a well to contain the position indicator probe. The probe is an aluminum extrusion attached to a cast aluminum housing. Mounted on the extrusion are hermetically sealed, magnetically operated, positi on indicator switches. The entire probe assembly is protected by a thin-walled stainless steel tube. The switches are actuated by a ring magnet located at the bottom of the drive piston.

The drive piston, piston tube, and indicator t ube are all of nonmagnetic stainless steel, allowing the individual switches to be operated by the magnet as the piston passes. Two switches are located at each position corresponding to an index tube groove, thus allowing redundant indication at each la tching point. Two additional switches are located at each midpoint between latching points to indicate the intermediate positions during drive motion. Thus, indication is provi ded for each 3 in. of travel. Duplicate switches are provided for the full-in and full-out positions. Redundant over-travel switches are located at a position below the normal full-out position. Because the limit of down-travel is normally provided by the control rod itself as it reaches the backseat pos ition, the drive can pass this position and actuate the over-travel switches only if it is uncoupled from its contro l rod. A convenient means is COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-5 thus provided to verify that the drive and control rod are coupled after installation of a drive or at any time during plant operation.

4.6.1.1.2.2.6 Flange and Cylinder Assembly . A flange and cylinder a ssembly is made up of a heavy flange welded to the drive cylinder. A sealing surface on the upper face of this flange forms the seal to the drive housing flange. Th e seals contain reactor pressure and the two hydraulic control pressures. Tefl on coated, stainless steel rings ar e used for these seals. The drive flange contains the integral ball, or two-way, check (ball-shuttle ) valve. This valve directs either the reactor vessel pressure or the driving pressure , whichever is higher, to the underside of the drive piston. Reactor vessel pressure is admitted to this valve from the annular space between the drive and drive housing throug h passages in the flange.

Water used to operate the collet piston passes between the outer tube and the cylinder tube. The inside of the cylinder tube is honed to provide the surface required for the drive piston seals.

Both the cylinder tube and outer tube are welded to the drive flange. The upper ends of these tubes have a sliding fit to allow for different ial expansion.

4.6.1.1.2.2.7 Lock Plug . The upper end of the index tube is threaded to receive a coupling spud. The coupling (see Figure 4.6-1 ) accommod ates a small amount of angular misalignment between the drive and the control rod. Six spring fingers allow the coupling spud to enter the mating socket on the control rod. A plug th en enters the spud a nd prevents uncoupling.

Two means of uncoupling are provided. With th e reactor vessel head removed, the lock plug can be raised against the spring force of appr oximately 50 lb by a rod extending up through the center of the control rod to an unlocking handle located above the control rod velocity limiter. The control rod, with the lock plug raised, can then be lifted from the drive.

The lock plug can also be pushed up from below, if it is desired to uncouple a drive without removing the RPV head for access. In this case, the central por tion of the drive mechanism is pushed up against the uncoupling rod assembly, which raises th e lock plug and allows the coupling spud to disengage the socket as the drive piston and index tube are driven down.

The control rod is heavy enough to force the spud fingers to enter the so cket and push the lock plug up, allowing the spud to enter the socket completely and the plug to snap back into place. Therefore, the drive can be coupled to the control rod using only the weight of the control rod. However, with the lock plug in place, a force in excess of 50, 000 lb is required to pull the coupling apart.

4.6.1.1.2.3 Materi als of Construction. Factors that determine the choice of construction materials are discussed in the following subsections.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-6 4.6.1.1.2.3.1 Index Tube. The index tube must withstand the locking and unlocking action of the collet fingers. A compatible bearing combination must be provided that is able to withstand moderate misalignment forces. The reactor environment limits the choice of materials suitable for corrosion resi stance. The column and tensile loads can be satisfied by an annealed, single phase, nitrogen stre ngthened, austenitic stainless steel. The wear and bearing requirements are provided by malc omizing the complete tube. To obtain suitable corrosion resistance, a carefully controlled proces s of surface preparation is employed.

4.6.1.1.2.3.2 Coupling Spud. The coupling spud is made of Inconel 750 that is aged for maximum physical strength and the required corrosion resistance. Because misalignment tends to cause chafing in the semispherical contact area, the part is protected by a thin chromium plating (electrolized). This pl ating also prevents galling of th e threads attaching the coupling spud to the index tube.

4.6.1.1.2.3.3 Collet Fingers. Inconel 750 is used for the colle t fingers, which must function as leaf springs when cammed open to the unlocked position. Colmonoy 6 hard facing provides a long-wearing surface, adequate for design life, to the area contacting the index tube and unlocking cam surface of the guide cap.

Experience at some operating boili ng water reactors (BWR) indicates that failures can occur in the collet fingers of the CRD mechanism. To resolve this problem, some BWR facilities installed a revised collet retainer design. However, CGS does not ha ve the revised collet retainer design. General Elec tric (GE) has demons trated by testing a nd operating experience that the existing CRDs meet all safety and licensing requirements and are expected to give full life performances. However, as a result of examining operating driv es, GE has discovered evidence of intergranular stre ss corrosion cracking (IGSCC) in some CRD drive components and has made design impr ovements to preclude IGSCC in the future. The spare parts for CRD components purchased by Energy Northwest incorpor ate this revised design. Along with the other parts of the drive, the collet retainer t ube, piston tube, and index tube will be routinely checked and changed out, if necessary, with the parts incorporating the revised design.

4.6.1.1.2.3.4 Seals and Bushings. Carbon Graphite material is selected for seals and bushings on the drive piston and stop piston. The material is inert, has a low friction coefficient when water-lubricated and is resist ant to degradation at high temperatures. The Carbon Graphite material is relatively soft, wh ich is advantageous when an occasional particle of foreign matter reaches a seal. The resulting scratches in the seal redu ce sealing effici ency until worn smooth, but the drive design can tolerate considerable water leakage past the seals into the reactor vessel.

4.6.1.1.2.3.5 Summary. All drive components exposed to reac tor vessel water are made of austenitic stainless steel except the following:

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-7 a. Seals and bushings on the drive piston and stop piston are Carbon Graphite

material,

b. All springs and members requiring spri ng action (collet fingers, coupling spud, and spring washers) are made of Inconel-750,

c. The ball check valve is a Ha ynes Stellite cobalt-base alloy,

d. Elastomeric O-ring s eals are ethylene propylene,

e. Metal piston rings are Haynes 25 alloy,

f. Certain wear surfaces are hard faced with Colmonoy 6,

g. Nitriding by a proprietary new malcomizing process and chromium plating are used in certain areas where resistance to abrasion is necessary, and

h. The drive piston head is made of Armco 17-4 PH.

Pressure containing porti ons of the drives are designed and fabricated in accordance with requirements of the American Society of Mech anical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section III.

4.6.1.1.2.4 Control Rod Drive Hydraulic System. The CRD hydr aulic system (Figure 4.6-5) supplies and controls the pressure and flow to and from the drives through hydraulic control

units (HCU). The water discharged from the drives during a scram flows through the HCU to the scram discharge volume (SDV). The water discharged from a drive during a normal control rod positioni ng operation flows through the HCU, th e exhaust header, and is returned to the reactor vessel vi a the HCUs of nonmoving drives. E ach CRD has an associated HCU.

4.6.1.1.2.4.1 Hydrau lic Requirements. Th e CRD hydraulic system design is shown in Figures 4.6-5 and 4.6-6. The hydraulic requirements, identified by the function they perform, are as follows:

a. An accumulator hydraulic charging pressure of approximately 1400 to 1500 psig is required. Flow to the accumulators is required only during scram reset or system startup;

b. Drive water header pressure of a pproximately 260 psi a bove reactor vessel pressure is required. A fl ow rate of approximately 4 gpm to insert a control rod and 2 gpm to withdraw a control rod is required;

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-8 c. Cooling water to the drives is required at a flow rate of approximately 0.34 gpm per drive unit. (Cooling water to a drive can be interrupted for short periods without damaging the drive);

d. The SDV is sized to receive and contain all the water discharged by the drives during a scram; a minimum volume of 3.

34 gal per drive is required (excluding the instrument volume);

e. Purge water flow to the RPV level inst rumentation reference leg backfill system at a flow rate from 0.

6 gal/hr to 2.4 gal/hr.

4.6.1.1.2.4.2 System Desc ription. The CRD hydraulic systems provide the required functions with the pumps, filter, valves, instrumentation, and piping shown in Figure 4.6-5 and described in the following.

Duplicate components are included, where necessary, to ensure c ontinuous system operation if an inservice component requires maintenance.

4.6.1.1.2.4.2.1 Supply Pump. One supply pump pressurizes th e system with water from a condensate supply header, which ta kes suction from the condensa te treatment system and/or condensate storage tanks depending on plant operation. One installed spare pump is provided for standby. A discharge check valve prevents backflow through the nonoperating pump. A portion of the pump discharge fl ow is diverted through a minimum flow bypass line to the condensate storage tank. This flow is controlled by an orifi ce and is sufficient to prevent immediate pump damage if the pump di scharge is inadvertently closed.

Condensate water is processed by two filters in the system. The normal CRD pump suction flow path includes a 25- filter with a 250- Y-strainer upstream of th e filter. Th e filtration capacity of these two in-series elements is limited by and therefore characterized by, the 25- filter (see Figure 4.6-5).

The filters used on the CRD system are of a r ugged design and failure of the filters are not considered likely. Alarms are provided to give an early warning to the operator that maintenance is required.

The only known mode of failure of the filter element is for it to collapse due to high differential pressure. The CR D pump suction filter can with stand a maximum differential pressure of 20 psi and an alarm indicates in the control room high su ction filter differential pressure at 8 psi. The filter element is additionally protected and strengthened by a stainless steel, perforated center tube. The CRD pump discharge filter can withstand a maximum

differential pressure of 300 psi and an alarm indicates in the control room high differential pressure at 20 psi. The filter element is constructed entirely of stainless steel. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-9 If the CRD systems pump suction and discharg e filters were bypassed completely, possible presence of corrosion particles would not affect the reliability of the scram function of the CRD system. The presence of corrosion particles may accelerate wear of the drive components over a period of time. However, such wear is not a safety concern since this degradation in drive performance already occurs during normal r od operations and is detectable.

4.6.1.1.2.4.2.2 Accumulator Charging Pressure . Accumulator charging pressure is established by the discharge pre ssure of the system supply pu mp. During scram the scram inlet (and outlet) valves open and permit the stored energy in the accumu lators to discharge into the drives. The resulting pressure decrease in the charging water header allows the CRD supply pump to "run out" (i.e., flow rate to increase substan tially) into the CRDs via the charging water header. The flow sensing system upstream of the accumu lator charging header detects high flow and closes the flow control valve. This action maintains increased flow through the charging water header.

Pressure in the charging header is monitored in the control room with a pressure indicator and low pressure alarm. Charging water header pre ssure is not essential to successfully scram the plant. Each of the accumulato rs are prevented from leaking b ack to the charging water header by a check valve. Therefore, the pressure required to scram each rod is maintained. The integrity and leaktightness of thes e check valves are routinely test ed as part of the surveillance test program. In addition, when the reactor is at rated pressure, no accumulator pressure is necessary to scram the plant.

During normal operation the flow control valve maintains a constant system flow rate. This flow is used for drive flow, driv e cooling, and system stability.

4.6.1.1.2.4.2.3 Drive Water Pressure . Drive water pressure requi red in the drive header is maintained by the drive/cooling wa ter pressure control valve, which is manually adjusted from the control room. A flow rate of approximately 6 gpm (the sum of the flow rate required to insert and withdraw a control rod) normally pa sses from the drive water pressure stage through two solenoid-operated stabilizing va lves (arranged in parallel) a nd then goes into the cooling water header. The flow through one stabilizing valve equals the drive insert flow; that of the

other stabilizing valve equals the drive withdraw al flow. When operating a drive, the required flow is diverted to that drive by closing the appropriate stabilizing valve while at the same time opening the drive directional control and exhaust solenoid valv es. Thus, flow through the drive/cooling water pressure cont rol valve is always constant.

Flow indicators in the drive water header and in the line downstream from the stabilizing valves allow the flow rate through the stabili zing valves to be adjusted when necessary. Differential pressure between the reactor vessel and the drive pressure stage is indicated in the control room.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 LDCN-14-026 4.6-10 4.6.1.1.2.4.2.4 Coolin g Water Header. The cooling water header is located downstream from the drive/cooling water pres sure valve. The drive/cooling water pressure control valve is manually adjusted from the control room to produce the required drive/cooling water pressure

balance.

The flow through the flow control valve is virt ually constant. Therefore, once adjusted, the drive/cooling water pressure cont rol valve will maintain the corr ect drive pressure and cooling water pressure, independent of reactor vessel pressure. Changes in setting of the pressure control valve are required only to adjust for cha nges in the cooling requir ements of the drives, as drive seal characteristics change with time. A flow indicator in th e control room monitors cooling water flow. A different ial pressure indicator in th e control room indicates the difference between reactor vesse l pressure and drive/cooling water pressure. Although the drives can function without cooling water, temperatures a bove 350°F can result in fluid flashing and measurable delays in scram times. The temperature of each drive is monitored by a temperature recorder.

4.6.1.1.2.4.2.5 Scram Discharge Volume. The CGS SDV header system is designed as a continually expanding path from the 185 individual 0.75-in. scram discharge (withdrawal) lines to one of two integrated scram discharge volume/instrument volume (SDV/IV) systems (one system per approximately half the drives). Each integrated SDV/IV system consists of a continuously downsloping piping run expanding from the SDV (consisting of seven 6-in. Return headers from the indivi dual HCU banks to an 8-in. comb ined return h eader) to the 12-in. vertically oriented IV. The only location where blockage need be assumed (piping less than 2-in. diameter) is in the 0.75 in. discharge line from the individual HCU. Blockage here would only cause failure of one control rod to insert. This is an acceptable consequence for a single failure and has been evalua ted as part of the plant design basis. The header piping is sized to receive and contain all the water discharged by the driv es during a full scram (3.34 gal per drive) independent of the IV.

During normal plant operation each SDV is empty and vented to the atmosphere through its open vent and drain valve. When a scram occurs on a signal from the safety circu it, these vent and drain valves are closed to conserve reactor water. Redundant vent and drain valves are incorporated in the design of the SDV to ensure that no single failure can result in uncontrolled loss of reactor coolant. Lights in the cont rol room indicate the pos ition of these valves. During a scram, the SDV partly fills with wa ter discharged from a bove the drive pistons. After scram is completed, the CRD seal leakage from the reactor continues to flow into the SDV until the discharge volume pressure equals the reactor vessel pressure. A check valve in each HCU prevents reverse flow from the scram discharge header volume to the drive. When the initial scram signal is cleared from the reactor protection system (RPS), the SDV signal is overridden with a key lock override switch, and the SDV is drained and returned to atmospheric pressure.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 LDCN-14-026 4.6-11 Remote manual switches in the pilot valve solenoid circuits allow the discharge volume vent and drain valves to be tested without disturbing the RPS. Closing the SDV valves allows the outlet scram valve seats to be leak tested by timing the accumulation of leakage inside the SDV.

Six liquid-level switches and two level transmi tters directly connected to each instrument volume monitor the volume for abnormal water level. They provide redundant and diverse input to the RPS scram functi on and control room annunciation and contro l rod withdrawal block function. They are set at three different levels. At the lowest level, a level switch actuates to indicate that the volume is not comp letely empty during post-scram draining or to indicate that the volume starts to fill through leakage accu mulation at other times during reactor operation. At the sec ond level, one level sw itch produces a rod withdrawal block to prevent further withdrawal of any control rod, when leakage accumulate s to half the capacity of the instrument volume. The remaining four switches are interconnected with trip channels of the RPS and will initiate a reactor scram on high water level while sufficient volume for a full scram still exists within the SDV. Two of these switches ar e actuated by level transmitters to provide diversity of signals to the RPS.

In the event of a slow or partial loss of air pressure, the hi gh-level scram se tpoint and the SDV/IV system capacity ensure that scram capability is main tained even in the event of maximum inleakage into the SDV prior to a scram. Analysis, assuming the maximum inleakage of 5 gpm and using th e actual calculation piston-over area to determine the scram volume requirements, shows that adequate scram discharge volume will remain in the SDV system at the time that a scram is initiated.

A partial loss of air pressure does not result in the uncontrolled release of reactor coolant to the reactor building should all or most of the scram discharge valves lift. When the water buildup reaches scram initiation leve l in the IV, a scram signal is produced. This will cause the air supply to the vent and dr ain valves to vent, thereby en suring that the vent and drain valves close and isolate. For leakage rates that do not result in buildup in the IV, the leak will drain to the reactor building equipment drain system.

4.6.1.1.2.4.3 Hydraulic Control Units. Each HCU furnishe s pressurized water, on signal, to a drive unit. The drive then pos itions its control rod as required. Operation of the electrical system that supplies scram and normal control rod positioning signa ls to the HCU is described in Section 7.7.1.2. The basic components in each HCU are manual, pneumatic, and electrical valves; an accumulator, related piping, elec trical connections, filters, and instrumentation (see Figures 4.6-5, 4.6-6, and 4.6-7). The components and their functions are described in the following. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-12 4.6.1.1.2.4.3.1 Insert Drive Valve . The insert drive valve 123 is solenoid operated and opens on an insert signal. The valve supplies drive water to the bottom side of the main drive piston. 4.6.1.1.2.4.3.2 In sert Exhaust Valve . The insert exhaust solenoi d valve 121 also opens on an insert signal. The valve disc harges water from above the dr ive piston to the exhaust water header.

4.6.1.1.2.4.3.3 Withdraw Drive Valve. The withdraw drive va lve 122 is solenoid operated and opens on a withdraw signal. The valve supp lies drive water to the top of the drive piston.

4.6.1.1.2.4.3.4 Withdraw Exhaust Valve . The solenoid operated withdraw exhaust valve 120 opens on a withdraw signal and discharges water from below the main drive piston to the exhaust header. It also serves as the settle valve, which opens following any normal drive movement (insert or withdraw) to allow the control rod and its drive to settle back into the nearest latch position.

4.6.1.1.2.4.3.5 Sp eed Control Units. The insert drive valve and withdraw exhaust valve have a speed control unit. Th e speed control unit regulates the control rod insertion and withdrawal rates during normal operation. Th e manually adjustable flow cont rol unit is used to regulate the water flow to and from the volume beneath the main drive piston. A correctly adjusted unit does not require readjustment except to comp ensate for changes in drive seal leakage.

4.6.1.1.2.4.3.6 Scram Pilot Valves. The scram pilot valves are operated from the RPS. Two scram pilot valves control both the scram inlet valve and the sc ram exhaust valve. The scram pilot valves are identical, three-way, solenoid-operated, normally energized valv es. On loss of electrical signal to the pilot valves, such as the loss of external ac power, the inlet ports close and the exhaust ports op en on both valves. The pilot valves (Figure 4.6-5 ) are arranged so

that the trip system signal mu st be removed from both valves before air pr essure can be discharged from the scram valve operators.

This prevents the inadvertent scram of a single drive in the even t of a failure of one of the pilot valve solenoids.

4.6.1.1.2.4.3.7 Scram Inlet Valve. The scram inlet valve opens to supply pressurized water to the bottom of the drive piston. This quick opening globe valve is operated by an internal spring and system pressure. It is closed by air pressure applied to th e toe of its diaphragm operator. A position indicator switch on this valve energizes a light in the control room as

soon as the valve starts to open.

4.6.1.1.2.4.3.8 Sc ram Exhaust Valve . The scram exhaust valve opens slightly before the scram inlet valve, exhausting water from above the drive piston. The exhaust valve opens faster than the inlet valve because of the higher air pressure spring setting in the valve COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-13 operator. A position indicator switch on this valve energizes a light in the control room as soon as the valve starts to open.

4.6.1.1.2.4.3.9 Scram Accumulator. The scram accumulator stores sufficient energy to fully insert a control rod at lower vessel pressures. At higher vessel pressures the accumulator pressure is assisted or supplan ted by reactor vessel pressure. The accumulator is a hydraulic cylinder with a free-floating piston. The pist on separates the water on top from the nitrogen below. A check valve in the accumulator charging water line prevents loss of water pressure in the event supply pressure is lost.

During normal plant operation the accumulator piston is seated at the bottom of its cylinder. Loss of nitrogen decreases the nitrogen pressure, which actuat es a pressure switch and sounds an alarm in the control room.

To ensure that the accumulator is always able to produce a scram, it is continuously monitored for water leakage. A float type level switch actuates an alarm if water leaks past the piston barrier and collects in the accumu lator instrumentation block.

4.6.1.1.2.5 Control Rod Drive System Operation. The CRD system performs rod insertion, rod withdrawal, and scram. These opera tional functions are described below.

4.6.1.1.2.5.1 Rod Insertion . Rod insertion is initiated by a signal from the operator to the insert valve solenoids. This si gnal causes both insert valves to open. The insert drive valve applies reactor pressure plus approximately 90 psi to the bottom of the drive piston. The insert exhaust valve allows water from above the drive piston to discharge to the exhaust header.

As is illust rated in Figure 4.6-3 , the locking mechanism is a ratchet -type device and does not interfere with rod insertion. The speed at wh ich the drive moves is determined by the flow through the insert speed control valve, which is set for approximately 4 gpm for a shim speed (nonscram operation) of 3 in./sec. During normal insertion, the pressure on the downstream side of the speed control valve is 90 psi to 100 psi above reactor vessel pressure. However, if the drive slows for any reason, the flow through, and pressure drop across, the insert speed control valve will decrease; the full differential pressure (260 ps i) will then be available to cause continued insertion. W ith 260 psi differential pressure acting on the drive piston, the piston exerts an upward force of 1040 lb. 4.6.1.1.2.5.2 Rod Withdrawal . Rod withdrawal is by design more involved than insertion. The collet finger (latch) must be raised to reach the unlocked position (see Figure 4.6-3 ). The notches in the index tube and the collet fingers are shaped so that the downward force on the index tube holds the collet finge rs in place. The index tube mu st be lifted before the collet fingers can be released. This is done by opening the drive insert valves (in the manner described in the preceding paragraph) for approximately 1 sec. The withdraw valves are then opened, applying driving pressure above the driv e piston and opening the area below the piston COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-035 4.6-14 to the exhaust header. Pressure is simultaneously applied to the collet piston. As the piston raises, the collet fingers are cammed outward, away from the index tube, by the guide cap.

The pressure required to release the latch is set and maintained at a level high enough to overcome the force of the latch return spring plus the force of reactor pressure opposing

movement of the collet piston. When this occurs, the index tube is unlatched and free to move in the withdraw direction. Water displaced by the drive piston flows out through the withdraw

speed control valve, which is se t to give the control rod a shim speed of 3 in./sec. The entire valving sequence is automatically controlled an d is initiated by a single operation of the rod withdraw switch.

4.6.1.1.2.5.3 Scram . During a scram the scram pilot valves and scram valves are operated as previously described. With the scram valves open, accumulator pressure is admitted under the drive piston, and the area over the dr ive piston is vented to the SDV.

The large differential pr essure (initially approximately 1500 psi and al ways several hundred psi, depending on reactor vessel pressure) produces a large upward force on the index tube and control rod. This force gives the rod a high in itial acceleration and provid es a large margin of force to overcome friction. Afte r the initial accelerati on is achieved, the dr ive continues at a nearly constant velocity. This characteristic provides a high in itial rod insertion rate. As the drive piston nears the top of its stroke the piston seals close off the large passage (buffer orifices) in the stop piston tube, providing a hydraulic cushion at the end of travel.

Prior to a scram signal the accu mulator in the HCU has approxi mately 1450-1510 psig on the water side and 1050-1100 psig on the nitrogen side. As the in let scram valve opens, the full water-side pressure is available at the CRD acting on a 4.1 in. 2 area. As CRD motion begins, this pressure drops to the gas-side pressure less line losses between the accumulator and the CRD system; at low vessel pressures the accumu lator completely discharges with a resulting gas-side pressure of approxima tely 575 psi. The CRD accumula tors are required to scram the control rods when the reactor pressure is low, and the accumulators retain sufficient stored energy to ensure the complete insertion of the control rods in the required time.

The ball check valve in the driv e flange allows reactor pressure to supply the scram force whenever reactor pressure exce eds the supply pressure at the drive. This occurs due to accumulator pressure decay and inlet line losses during all scrams at higher vessel pressures. When the reactor is close to or at fully operating pressure, reac tor pressure alone will insert the control rod in the required time, although th e accumulator does prov ide additional margin at the beginning of the stroke.

The CRD system provides the following performance at full power operation and with accumulators. The scram insertion time is measured from the instant the scram pilot valve solenoids are deenergized.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-035 4.6-15 Position inserted from 45 39 25 5

fully withdrawn

Tech Spec scram insertion 0.528 0.866 1.917 3.437 time (sec)

4.6.1.1.2.6 Instrumentation. The instrumentation for both the control rods and CRDs is defined by that given for the manual control system. The objective of the reactor manual control system is to provide the operator with the means to make change s in nuclear reactivity so that reactor power level and power distribution can be contro lled. The syst em allows the operator to manipul ate control rods.

The design bases and further discussion are contained in Chapter 7 . 4.6.1.2 Control Rod Drive Housing Supports

4.6.1.2.1 Safety Objective

The CRD housing supports prevent any significant nuclear transient if a drive housing breaks or separates from the bottom of the reactor vessel.

4.6.1.2.2 Safety Design Bases

The CRD housing supports shall meet the following safety design bases:

a. Following a postulated CRD housing failure, control rod downward motion shall be limited so that a ny resulting nuclear transient could not be sufficient to cause fuel damage, and

b. The clearance be tween the CRD housings and the s upports shall be sufficient to prevent vertical contact stresses caused by thermal expansion during plant operation.

4.6.1.2.3 Description

The CRD housing supports are shown in Figure 4.6-8. Horizontal beams are installed immediately below the bottom head of the reactor vessel, between the rows of CRD housings. The beams are supported by brackets welded to the steel form liner of the drive room in the reactor support pedestal.

Hanger rods, approximately 10 ft long and 1.75 in. in diameter, are supported from the beams on stacks of disc springs. These springs comp ress approximately 2 in. under the design load.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-16 The support bars are bolted between the bottom ends of the hanger rods. The spring pivots at the top and the beveled, loos e fitting ends on the support ba rs prevent substantial bending moment in the hanger rods if the support bars are overloaded. Individual grids rest on the support bars between adjacent beams. Because a single piece grid would be difficult to handle in the limited work space and because it is necessary that CRDs, position indicators, and in-core instrumentation components be accessible for inspection and maintenance, each grid is designed for in-place assembly or disassembly. Each grid assembly is made from two grid plates, a clamp, and a bolt. The top part of the clamp guides the grid to its correct position directly below the respec tive CRD housing that it would support in the postulated accident.

When the support bars and grid s are installed, a gap of approximately 1 in. at room temperature (approximately 70°F) is provided between the grid and the bottom contact surface of the CRD flange. During system heatup, th is gap is reduced by a net downward expansion of the housings with respect to the supports . In the hot operating condition, the gap is approximately 0.25 in.

In the postulated CRD housing failure, the CRD housing supports are loaded when the lower contact surface of the CRD flange contacts the grid. The resulting load is then carried by two grid plates, two support bars, four hanger rods, their disc sp rings, and two adjacent beams.

For purposes of mechanical design, the postulate d failure resulting in the highest forces is an instantaneous circumferential separation of the CRD housing from the reactor vessel, with an internal pressure of 1250 psig (reactor vesse l design pressure) acting on the area of the separated housing. The we ight of the separated hous ing, CRD, and blade, plus the pressure of 1250 psig acting on the area of the separated housi ng, gives a force of approximately 35,000 lb. This force is multip lied by a factor of three for impact, conservatively assuming that the housing travels through a 1-in. gap before it contacts the supports. The total force (105,000 lb) is then treated as a static load in design.

All CRD housing support subassemblies are fabricated of commonly available structural steel, except for the disc springs, whic h are Schnorr, Type BS-125-71-8.

4.6.2 EVALUATION OF THE CONTROL ROD DRIVES Safety evaluation of the contro l rods, CRDs, and CRD housing supports is described below. Further description of control rods is contained in Section 4.2. The evaluation of the effects of pipe breaks on the CRDs may be found in Section 3.6. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-17 4.6.2.1 Control Rods 4.6.2.1.1 Materials Adequacy Throughout Design Lifetime

The adequacy of the materials throughout the design life was evaluated in the mechanical design of the control rods. The primary materials, B 4C powder, hafnium, and type 304 austenitic stainless steel, have been found suitable in me eting the demands of the BWR environment.

4.6.2.1.2 Dimensional a nd Tolerance Analysis Layout studies are done to ensure that, given th e worst combination of extreme detail part tolerance ranges at assembly, no interference exis ts which will restrict the passage of control rods.

The italicized information is historical and was provided to support the application for an operating license.

In addition, during initial preoperational testing, an observer who is in direct communication with the control room will observe the operation of each individual control rod and verify that there is no binding or restric tion to rod motion and will liste n for any scr aping or binding noises which may signify rod misalignment. In addition, the function of each CRD line will be measured as indicated by the differential pr essure developed across the CRD piston during notch withdrawal. These differential pressure traces will be co mpared to reference traces to proper operation and the absen ce of abnormal friction.

4.6.2.1.3 Thermal Analysis of the Tendency to Warp

The various parts of the contro l rod assembly remain at approximately the same temperature during reactor operation, negating the problem of distortion or warpage. What little differential thermal growth could exist is allowed for in the mechanical design. A minimum axial gap is maintained between absorber rod tubes and the cont rol rod frame assembly for the purpose. In addition, dissimilar metals are avoided to further this end.

4.6.2.1.4 Forces for Expulsion An analysis has been performed that evaluates the maximum pr essure forces which could tend to eject a control rod from the core. The results of this analysis are given in Section 4.6.2.2.2.2. In summary, if the collet were to rema in open, which is un likely, calculations indicate that the steady-state control rod w ithdrawal velocity w ould be 2 ft/sec for a pressure-under line break, the lim iting case for rod withdrawal.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-18 4.6.2.1.5 Functional Failure of Critical Components The consequences of a functional failure of critical components have been evaluated and the results are discussed in Section 4.6.2.2.2 . 4.6.2.1.6 Precluding Excessive Rates of Reactivity Addition

To preclude excessive rates of reactivity add ition, analysis has been performed both on the velocity limiter device and the effect of probable contro l rod failures (see Section 4.6.2.2.2 ). 4.6.2.1.7 Effect of Fuel Rod Failure on Control Rod Channel Clearances

The CRD mechanical design ensures a sufficiently rapid insertion of control rods to preclude the occurrence of fuel rod fa ilures that could hinder reactor shutdown by causing significant distortions in channel clearances.

4.6.2.1.8 Mechanical Damage

Analysis has been performed for all areas of the control system showing that system mechanical damage does not affect the capability to continuous ly provide reactivity control.

In addition to the analysis performed on the CRD (see Sections 4.6.2.2.2 and 4.6.2.2.3 ) and the control rod blade, the following discussion summarizes the analys is performed on the control rod guide tube.

The guide tube can be subjected to any or all of the following loads:

a. Inward load due to pressure differential, b. Lateral loads due to flow across the guide tube,

c. Dead weight,

d. Seismic (vertical and horizontal), and

e. Vibration.

In all cases analysis was perf ormed considering both a recircul ation line break and a steam line break. These events result in the largest hydraulic loadings on a control rod guide tube.

Two primary modes of failure were considered in the guide tube analysis: exceeding allowable stress and excessive elastic deformation. It was found that the allowable stress limit will not be exceeded and that the elastic deforma tions of the guide tube never are great enough to cause the free movement of the control rod to be jeopardized.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-19 4.6.2.1.9 Evaluation of Cont rol Rod Velocity Limiter The control rod velocity limiter limits the free fa ll velocity of the contro l rod to a value that cannot result in nuclear system process barrier damage. This ve locity is evaluated by the rod drop accident analysis in Chapter 15 .

4.6.2.2 Control Rod Drives

4.6.2.2.1 Evaluati on of Scram Time The rod scram function of the CRD system provi des the negative reactivity insertion required by safety design basis Section 4.6.1.1.1.1 . The scram time shown in the description is adequate as shown by the transient analyses in Chapter 15 . 4.6.2.2.2 Analysis of Malfunction Relating to Rod Withdrawal

There are no known single malfunctions that cause the unplanned withdrawal of even a single

control rod. However, if multip le malfunctions are postulated, st udies show that an unplanned rod withdrawal can occur at withdrawal speeds th at vary with the combination of malfunctions postulated. In all cases the subsequent withdrawal speeds are less than that assumed in the rod drop accident analysis as discussed in Chapter 15 . Therefore, the physical and radiological consequences of such rod withdrawals are less than those anal yzed in the rod drop accident.

4.6.2.2.2.1 Drive Housing Fails at Attachment Weld . The bottom head of the reactor vessel has a penetration for each CRD location. A dr ive housing is raised in to position inside each penetration and fastened by welding. The drive is raised into the drive housing and bolted to a flange at the bottom of the housi ng. The housing material is seam less, type 304 stainless-steel pipe with a minimum tensile stre ngth of 75,000 psi. The basic failure considered here is a complete circumferentia l crack through the housing wall at an elevation just below the J-weld.

Static loads on the housing wall include the weight of the drive and the control rod, the weight of the housing below the J-weld, and the reactor pressure acting on the 6-in.-diameter cross-sectional area of the housing and the drive. Dynamic loading results from the reaction force during drive operation.

If the housing were to fail as described, the following sequence of even ts is foreseen. The housing would separate from the vessel. Th e CRD and housing would be blown downward against the support structure by reactor pressure acting on the cross-sectional area of the housing and the drive. The downward motion of the drive and associated parts would be determined by the gap between the bottom of the drive and the suppor t structure and by the deflection of the support structure under load. In the current design, maximum deflection is approximately 3 in. If the collet were to remain latched, no further control rod ejection would occur (Reference 4.6-1); the housing would not drop fa r enough to clear the vessel COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-20 penetration. Reactor water would leak at a rate of approximately 220 gpm through the 0.03-in.-diametral clearan ce between the housing and the vessel penetration. If the basic housing failure were to occur while the control rod is being withdrawn (this is a small fraction of the total drive operating time) and if the collet were to stay unlatched, the following sequence of events is foreseen. The housing would sepa rate from the vessel. The drive and housing would be blown downward agai nst the CRD housing supp ort. Calculations indicate that the steady-state rod withdrawal velocity would be 0.3 ft/sec. During withdrawal, pressure under the collet piston would be approx imately 250 psi greater than the pressure over it. Therefore, the collet would be held in the unlatched pos ition until driving pressure was removed from the pressure-over port.

4.6.2.2.2.2 Rupture of Hydraulic Line(s) to Drive Housing Flange. There are three types of possible rupture of hydraulic lines to the driv e housing flange: (1) pressure-under line break; (2) pressure-over line break; and (3) coin cident breakage of both of these lines.

4.6.2.2.2.2.1 Pre ssure-Under Line Break . For the case of a pr essure-under line break, a partial or complete circumferential opening is postulated at or near the point where the line enters the housing flange. Failure is more likely to occur after another basic failure wherein the drive housing or housing flange separates from the reactor vessel. Failure of the housing, however, does not necessarily lead dir ectly to failure of the hydraulic lines.

If the pressure-under line were to fail and if the collet were latched, no control rod withdrawal would occur. There would be no pressure differential across the collet piston and, therefore, no tendency to unlatch the collet. Consequently, the associated control rod could not be withdrawn, but if reactor pressure is greater than 600 psig, it will in sert on a scram signal.

The ball check valve is designe d to seal off a broken pressure-under line by using reactor pressure to shift the check ball to its upper seat. If the ball ch eck valve were prevented from seating, reactor water w ould leak to the atmosphere. Becaus e of the broken line, cooling water could not be supplied to the drive involved. Loss of cooling water would cause no immediate damage to the drive. However, prolonged exposure of the drive to temperatures at or near reactor temperature could lead to deterioration of material in the seals. Temperature is monitored by a temperature reco rder. A second indication woul d be high cooling water flow. If the basic line failure were to occur while the control rod is being withdrawn, the hydraulic force would not be sufficient to hold the colle t open, and spring force normally would cause the collet to latch and stop rod withdrawal. However, if the collet were to remain open, calculations indicate that the steady-state contro l rod withdrawal veloci ty would be 2 ft/sec. 4.6.2.2.2.2.2 Pre ssure-Over Line Break . The case of the pressure-over line breakage considers the complete breakage of the line at or near the poi nt where it enters the housing flange. If the line were to br eak, pressure over the drive pi ston would drop from reactor COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-21 pressure to atmospheric pressure . Any significant reactor pressure (approximately 600 psig or greater) would act on the bottom of the drive piston and fully insert the drive. Insertion would occur regardless of the operational mode at the time of the failure. After full insertion, reactor water would leak past the stop piston seals. This leakage would exha ust to the atmosphere through the broken pressure-over line. The leakage rate at 1000 psi reactor pressure is estimated to be 4 gpm nominal but not mo re than 10 gpm, ba sed on experimental measurements. If the reactor were hot, driv e temperature would increase. This situation would be indicated to the reactor operator by the drift alarm, by the fully inserted drive, by a high drive temperature, and by operation of the drywell sump pump. 4.6.2.2.2.2.3 Simulta neous Breakage of the Pressure -Over and Pressure-Under Lines . For the simultaneous breakage of th e pressure-over and pressure-under lines, pressures above and below the drive piston would drop to zero, a nd the ball check valve would close the broken

pressure-under line. Reactor water would flow from the annulus outside the drive, through the vessel ports, and to the space belo w the drive piston. As in the case of pressure-over line breakage, the drive would then insert (approximately 600 psig or greater) at a speed dependent on reactor pressure. Full insertion would occur regardless of the operational mode at the time of failure. Reactor water would leak past the drive seals and out the broken pressure-over line to the atmosphere, as described above. Drive temperature would increase. Indication in the control room would include the drift alarm, th e fully inserted drive, and operation of the drywell sump pump.

4.6.2.2.2.3 All Drive Fla nge Bolts Fail in Tension. Each CRD is bolted to a flange at the bottom of a drive housing. The flange is welded to the drive housing. Bolts are made of AISI-4140 steel, with a minimum te nsile strength of 125, 000 psi. Each bolt has an allowable load capacity of 15,200 lb. Capa city of the eight bolts is 121, 600 lb. As a result of the reactor design pressure of 1250 psig, the major load on all eight bolts is 30,400 lb.

If a progressive or simultaneous failure of all bo lts were to occur, th e drive would separate from the housing. The cont rol rod and the drive would be blown downward against the support structure. Impact velocity and support structure loading would be slightly less than that for drive housing failure because reactor pr essure would act on the drive cross-sectional area only and the housing would remain attached to the reactor vessel. The drive would be isolated from the cooling water supply. Reactor water would flow downw ard past the velocity limiter piston, through the large drive filter, and into the annular sp ace between the thermal sleeve and the drive. For worst-case leakage calculations, the large filt er is assumed to be deformed or swept out of the way so it would o ffer no significant flow restriction. At a point near the top of the annulus, where pressure w ould have dropped to 35 0 psi, the water would flash to steam and cause choke-flow conditions. Steam would flow down the annulus and out the space between the housing and the drive flanges to the drywell. Steam formation would limit the leakage rate to approximately 840 gpm.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-22 If the collet were latched, control rod ejection would be limited to the distance the drive can drop before coming to rest on th e support structure. There woul d be no tendency for the collet to unlatch, because pressure below the collet piston would drop to zero. Pressure forces, in fact, exert 1435 lb to hold the collet in the latched position. If the bolts failed during control rod withdrawal, pressure below the collet piston would drop to zero. The collet, with 1650-lb return force, would latch and stop rod withdrawal.

4.6.2.2.2.4 Weld Jo ining Flange to Housing Fails in Tension . The failure considered is a crack in or near the weld that joins the flange to the housing. This crack extends through the wall and completely aro und the housing. The flange material is forged, type 304 stainless steel, with a minimum tensile st rength of 75,000 psi. The hous ing material is seamless, type 304 stainless steel pipe, with a minimum tensile strength of 75,000 psi. The conventional, full penetration weld of type 308 stainless steel has a minimum tensile strength approximately the same as that for the parent metal. The design pressure and temperature are 1250 psig and 575°F. Reactor pressure acting on the cross-sec tional area of the drive; the weight of the control rod, drive, and flange

and the dynamic reaction force during drive operation result in a maximum tensile stress at the weld of approximately 6000 psi.

If the basic flange-to-housing joint failure occurred, the flange a nd the attached drive would be blown downward against the support structure. The support structure loading would be slightly less than that for drive housing failure because reactor pressure would act only on the drive cross-sectional area. Lack of differential pressure across the collet piston would cause the collet to remain latched a nd limit control rod motion to a pproximately 3 in. Downward drive movement would be small; therefore, most of the drive would remain inside the housing. The pressure-under and pressu re-over lines are flexible enough to withstand the small displacement and remain attached to the flange. Reactor water would follow the same leakage path described above for the fl ange-bolt failure, except that exit to the drywell would be through the gap between the lower end of the housing and the top of the flange. Water would flash to steam in the annulus surrounding the driv

e. The leakage rate would be approximately 840 gpm.

If the basic failure were to occur during control rod withdraw al (a small fraction of the total operating time) and if the collet were held unlatched, the flange would separate from the housing. The drive and flange would be blown downward against the su pport structure. The calculated steady-state rod withdrawal velocity would be 0.13 ft /sec. Because pressure-under and pressure-over lines re main intact, driving water pressure would continue to the drive, and the normal exhaust line restriction would exist. The pressure be low the velocity limiter piston would drop below normal as a result of leak age from the gap between the housing and the flange. This differential pre ssure across the velocity limiter piston would result in a net downward force of approximately 70 lb. Leakage out of the housing would greatly reduce the pressure in the annulus surrounding the drive. Thus, the net downward force on the drive piston would be less than normal. The overall effect of these events would be to reduce rod COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-23 withdrawal to approximately one-half of norma l speed. With a 560 psi differential across the collet piston, the collet woul d remain unlatched; however, it should relatch as soon as the drive signal is removed.

4.6.2.2.2.5 Housing Wall Ruptures . This failure is a vertical split in the drive housing wall just below the bottom head of the reactor vessel. The flow area of the hole is considered equivalent to the annular area between the driv e and the thermal sleeve. Thus, flow through this annular area, rather than flow through the hole in the housing, would govern leakage flow. The housing is made of type 304 stainless-steel seamless pipe, with a minimum tensile strength of 75,000 psi. The maximum hoop stress of 11,900 psi results primarily from the reactor design pressure (1250 psig) acting on the inside of the housing.

If such a rupture were to occur, reactor water would flash to steam and leak through the hole in the housing to the drywell at approximately 1030 gp

m. Choke-flow conditions would exist, as described previously for the flange-bolt failure. However, leakage flow would be greater because flow resistance would be less; that is, the leaking water and steam would not have to flow down the length of the housing to reach the drywell. A critical pressure of 350 psi causes the water to flash to steam.

No pressure differential across the collet piston would tend to unlatch the collet, but the drive would insert as a result of loss of pressure in the drive housing causing a pressure drop in the space above the drive piston.

If this failure occurred during control rod withdrawal, drive w ithdrawal would stop, but the collet would remain unlatched . The drive would be stoppe d by a reduction of the net downward force action on the drive line. The net force reduction would occur when the leakage flow of 1030 gpm reduces the pressu re in the annulus outside the drive to approximately 540 psig, thereby reducing the pressure acting on to p of the drive piston to the same value. A pressure differential of approxima tely 710 psi would ex ist across the collet piston and hold the collet unlatched as long as the operator held the withdraw signal.

4.6.2.2.2.6 Flange Plug Blows Out . To connect the vessel ports with the bottom of the ball check valve, a hole of 0.75-in. diameter is drille d in the drive flange. The outer end of this hole is sealed with a plug of 0.812-in. diamet er and 0.25-in. thickness . A full-penetration, type 308 stainless steel weld hol ds the plug in place. The postulated failure is a full circumferential crack in this weld and subsequent blowout of the plug.

If the weld were to fail, the plug were to blow out, and the collet remained latched, there would be no control rod motion. There would be no pressure differential acr oss the collet piston acting to unlatch the collet. Reactor water would leak past the velocity limiter piston, down the annulus between the drive and the thermal sleeve, through the vessel ports and drilled passage, and out the open plug hole to the drywell at approximately 320 gpm. Leakage calculations assume only liquid flows from the fl ange. Actually, hot re actor water would flash COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-24 to steam, and choke-flow conditions would exist. Thus, the expected leakage rate would be lower than the calculated value.

If this failure were to occur during control rod withdrawal and if the collet were to stay unlatched, calculations indicate that control rod withdrawal speed would be approximately 0.24 ft/sec. Leakage from the ope n plug hole in the flange would cause reactor water to flow downward past the velocity limit er piston. A small differential pressure across the piston would result in an insignificant driving force of approximately 10 lb, tending to increase withdraw velocity. A pressure differential of 295 psi across the collet piston w ould hold the collet unlatched as long as the driving signal was maintained.

Flow resistance of the exhaust path from the drive would be normal because the ball check valve would be seated at the lower end of its travel by pressure under the drive piston.

4.6.2.2.2.7 Ball Check Valve Plug Blows Out. As a means of access for machining the ball check valve cavity, a 1.25-in.-diameter hole has been drilled in the flange forging. This hole is sealed with a plug of 1.31-in. diameter a nd 0.38-in. thickness. A full-penetration weld, using type 308 stainless steel filler, holds the plug in place. The failure postulated is a circumferential crack in this weld leading to a blowout of the plug.

If the plug were to blow out while the drive was latched, there would be no control rod motion. No pressure differential would exist across the collet piston to unlatch the collet. As in the previous failure, reactor water would flow past the velocity limiter, down the annulus between the drive and thermal sleeve, through the vessel ports and drilled passage, through the ball check valve cage and out the open plug hole to the drywell. The leakage calculations indicate the flow rate would be 350 gpm. This calculation assu mes liquid flow, but flashing of the hot reactor water to steam would reduce this rate to a lower valu

e. Drive temperature would rapidly increase.

If the plug failure were to occur during control rod withdrawal (it would not be possible to unlatch the drive after such a fa ilure), the collet would relatch at the first locking groove. If the collet were to stick, calculations indicat e the control rod withdrawal speed would be 11.8 ft/sec. There would be a large retarding force exerted by the velocity limiter due to a 35 psi pressure differential across the velocity limiter piston.

4.6.2.2.2.8 Drive/Cooling Wate r Pressure Control Valve Failure . The pressure to move a drive is generated by the pressure drop of practically the full system flow through the drive/cooling water pressure control valve. This valve is eith er a motor-operated valve or a standby manual valve; either one is adjusted to a fixed opening. The normal pressure drop across this valve develops a pressure 260 psi in excess of reactor pressure.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-25 If the flow through the drive/coo ling water pressure control valv e were to be stopped, as by a valve closure or flow blockage, the drive pressure would increase to the shut off pressure of the supply pump. The occurrence of this condition during withdrawal of a drive at zero vessel pressure will result in a drive pressure increase from 260 psig to no more than 1750 psig. Calculations indicate that the drive would accelerate from 3 in./sec to approximately 6.5 in./sec. A pressure different ial of 1670 psi across the colle t piston would hold the collet unlatched. Flow would be upward past the velo city limiter piston, but retarding force would be negligible. Rod movement would stop as soon as the driving signal was removed. Conversely, if the PCV were to fail to a full open position, the cooling water pr essure would increase and the drive water pressure would decrease. The resulting cooling water pressure increase could cause control rods to drift inward. The existe nce of rod drifts would be alarmed to the control room operator for appropriate action. The resu lting drop in drive water pressure would make normal c ontrol rod notch movements impossi ble but would not affect the ability of the scram function.

In both of the cases described above, the manually operated bypass PC V in conjunction with

the isolation gate valves located upstream and downstream of the PCV would enable the operators to take corrective action.

In conclusion, although th e failure to the full open or full cl osed position of the drive/cooling water PCV will cause perturbation in the CRD sy stem operation, it does not present a safety problem to affect the scram capability of the CRD system.

4.6.2.2.2.9 Ball Check Valve Fails to Close Passage to Vessel Ports . Should the ball check valve sealing the passage to the vessel ports be dislodged and prev ented from reseating following the insert portion of a drive withdr awal sequence, water below the drive piston would return to the reactor th rough the vessel ports and the a nnulus between the drive and the housing rather than through the speed control valve. Because the fl ow resistance of this return path would be lower than normal, the calculated withdrawal speed would be 2 ft/sec. During withdrawal, differential pressure across the co llet piston would be a pproximately 40 psi. Therefore, the collet would te nd to latch and would have to stick open befo re continuous withdrawal at 2 ft/sec, could occur. Water would flow upward past the velocity limiter piston, generating a small retarding fo rce of approximately 120 lb. 4.6.2.2.2.10 Hydraulic C ontrol Unit Valve Failures . Various failures of the valves in the HCU can be postulated, but none could produ ce differential pressure s approaching those described in the preceding paragraphs and none alone coul d produce a high velocity withdrawal. Leakage through eith er one or both of the scram va lves produces a pressure that tends to insert the control rod rather than to withdraw it. If the pressure in the SDV should exceed reactor pressure following a scram, a check valve in the line to the scram discharge header prevents this pressure from operating the drive mechanisms.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-26 4.6.2.2.2.11 Collet Fingers Fail to Latch. The failure is presumed to occur when the drive withdraw signal is removed. If the collet fails to latch, the dr ive continues to withdraw at a fraction of the normal speed. Th is assumption is made because there is no known means for the collet fingers to become unlocked without so me initiating signal. B ecause the collet fingers will not cam open under a load, accidental application of a down signal does not unlock them. (The drive must be given a short insert signal to unload the fingers and cam them open before the collet can be driven to the unlock position.) If the drive withdrawal valve fails to close following a rod withdrawal, the co llet would remain open and the drive continue to move at a reduced speed. 4.6.2.2.2.12 Withdrawal Speed Control Valve Failure. Normal withdrawal speed is determined by differential pressures in the drive and is set for a nominal value of 3 in./sec. Withdrawal speed is maintained by the pressure regulating valve and is independent of reactor vessel pressure. Tests have s hown that accidental opening of the speed control valve to the full-open position produces a velocity of approximately 6 in./sec.

The CRD system prevents unplanned rod withdr awal and it has been shown above that only multiple failures in a drive unit and its control unit could cause an unpl anned rod withdrawal.

4.6.2.2.2.13 Slow or Partial Loss of Air to the Scram Discharge Valves. The CGS IV is adequately hydraulically coupled to the SDV, i.e., the IV is connected directly to the SDV with piping of a diameter equal to or greater than the diameter of th e SDV headers. This allows for direct detection of liquid buildup so that the ab ility to scram is ensured.

The basis of the instrument volume high level scram setpoint and the SDV/IV physical arrangement provides for scram action before significant SDV reduction occurs which could affect scram capability.

The high-level scram setpoint and the SDV/IV sy stem capacity ensure th at scram capability is maintained even in the event of maximum inl eakage into the SDV prior to a scram. Analysis, assuming the maximum inleakage of 5 gpm and using the actual calculated piston-over area to determine the scram volume require ments, shows that adequate SDV will remain in the SDV system at the time that a scram is initiated.

The partial loss of air pressure does not result in the uncontrolled release of reactor coolant to the reactor building. The vent and drain valves tends are spring to close-held open by air. Flow through the valve tends to close it. As air pressure decreases the valves will begin to close to limit coolant inventory loss. When the water buildup reaches scram initiation level in the IV, a scram signal is produced.

This will cause the air supply to the vent and dr ain valves to vent, thereby ensuring that the vent and drain valves close and isolate. For leakage rates whic h do not result in buildup in the IV, the leak will drain to the reactor building equipment drain system. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-026 4.6-27 4.6.2.2.3 Scram Reliability

High scram reliability is the result of a number of features of the CRD system. For example

a. Two reliable sources of scram energy are used to insert each control rod: individual accumulators at low reactor pr essure, and the reactor vessel pressure itself at power;

b. Each drive mechanism ha s its own scram and pilot va lves so only one drive can be affected if a scram valve fails to open. Two pilot valves are provided for each drive. Both pilot valves must be deenergized to initiate a scram;

c. The RPS and the HCUs are designed so that the scram si gnal and mode of operation override all others;

d. The collet assembly and index tube ar e designed so they will not restrain or prevent control rod inse rtion during scram; and

e. The SDV is monitored for accumulated water and the reactor will scram before the volume is reduced to a point that could interfere with a scram.

4.6.2.2.4 Control Rod Support and Operation

Each control rod is independen tly supported and cont rolled as required by the safety design bases.

4.6.2.3 Control Rod Drive Housing Supports

Downward travel of the CRD housing and its control rod following the postulated housing failure equals the sum of these distances: (1) the compression of the disc springs under dynamic loading, and (2) the initi al gap between the grid and the bottom contact surface of the CRD flange. If the reactor were cold and pressurized, the downward motion of the control rod would be limited to the spring compre ssion (approximately 2 in.) plus a gap of approximately 1 in. If the reactor were hot and pressurized, the gap would be approximately 0.25 in. and the spring compression would be slightly less than in the cold condition. In either case, the control rod movement following a housing failure is s ubstantially limited below one drive "notch" movement (6 in.). Sudden withdraw al of any control rod through a distance of one drive notch at any position in the core does not produce a transient sufficient to damage any radioactive material barrier. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-28 The CRD housing supports are in place during pow er operation and when the reactor coolant system is pressurized. If a control rod is ejected during shutdown, the reactor remains subcritical because it is desi gned to remain subcritical w ith any one control rod fully withdrawn at any time.

At plant operating temperature, a gap of approximately 0.25 in. exists between the CRD housing and the supports. At lower temperatures the gap is greater. B ecause the supports do not contact any of the CRD housing except duri ng the postulated acciden t condition, vertical contact stresses are prevented. 4.6.3 TESTING AND VERIFICATION OF THE CONTROL ROD DRIVES

4.6.3.1 Control Rod Drives

4.6.3.1.1 Testing and Inspection

4.6.3.1.1.1 Development Tests . The development drive (prototype) testing included more than 5000 scrams and approximately 100,000 latching cycles. One prototype was exposed to simulated operating cond itions for 5000 hr. These test s demonstrated the following:

a. The drive easily withsta nds the forces, pressures, and temperatures imposed;

b. Wear, abrasion, and corros ion of the nitrided stainl ess parts are negligible.

Mechanical performance of th e nitrided surface is superior to that of materials used in earlier operating reactors;

c. The basic scram speed of the drive has a satisfact ory margin above minimum plant requirements at any reactor vessel pressure; and

d. Usable seal lifetimes in excess of 1000 scram cy cles can be expected.

4.6.3.1.1.2 Factory Quality Control Tests. Quality control of welding, heat treatment, dimensional tolerances, ma terial verification, a nd similar factors is maintained throughout the manufacturing process to ensure reliable performance of the mechanic al reactivity control components. Some of the quality control tests performed on the control rods, CRD mechanisms, and HCU are listed below:

a. Control rod drive mechanism tests

1. Pressure welds on the drives are hydrostatically tested in accordance with ASME codes;

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6-29 2. Electrical components ar e checked for elect rical continuity and resistance to ground;

3. Drive parts that cannot be visually inspected for dirt are flushed with filtered water at high velocity. No significant foreign material is permitted in effluent water;

4. Seals are tested for leakage to demonstrate correct seal operation;

5. Each drive is tested for shim motion, latching, and control rod position indication; and

6. Each drive is subjected to cold scram tests at various reactor pressures to verify correct scram performance.

b. Hydraulic control unit tests

1. Hydraulic systems are hydrostatica lly tested in accordance with the applicable code;

2. Electrical components and systems are tested for electric al continuity and resistance to ground;

3. Correct operation of the accumulator pressure and level switches is verified;

4. The unit's ability to perform its part of a scram is demonstrated; and

5. Correct operation and adjustment of the insert and withdrawal valves is demonstrated.

4.6.3.1.1.3 Operational Tests. After installation, all rods and drive mechanisms can be tested through their full stroke for operability.

During normal operation each time a control rod is withdrawn a notch, the operator can observe the in-core monitor indications to verify that the control rod is following the drive mechanism. All control rods th at are partially withdrawn from the core can be tested for rod-following by inserting or withdrawing the ro d one notch and returning it to its original position, while the operator observes the in-core monitor indications.

To make a positive test of control rod to CRD coupling integrity , the operator can withdraw a control rod to the end of its travel and then attempt to withdraw the drive to the over-travel position. Failure of the drive to over-travel demonstrates rod-to-drive coupling integrity. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-09-034 4.6-30 Hydraulic supply subsystem pres sures can be observed from in strumentation in the control room. Scram accumulator pressures can be observed on the nitrogen pressure gages.

4.6.3.1.1.4 Acceptance Tests . Criteria for acceptance of th e individual CRD mechanisms and the associated control and protection systems were incorporated in specifications and test procedures covering three distinct phases: (1) pre-installation, (2) after installation prior to

startup, and (3) during startup testing.

The pre-installation spec ification defined criteria and acceptable ranges of such characteristics as seal leakage, friction, and scram performance under fixed test conditions whic h must be met before the component was shipped.

The after installation, prestartup tests (Section 14.2) included normal and scram motion and were primarily intended to verify that piping, valves, electrical components and instrumentation were properly installed. The test specifications included criteria and acceptable ranges for drive speed , time settings, scram valve response times, and control pressures. These tests were intended more to document system condition than as tests of performance.

As fuel was placed in the reactor, the startup test procedure ( Chapter 14 ) was followed. The tests in this procedure were intended to demonstrate that the initial operational characteristics meet the limits of the specifications over the range of primary cool ant temperatures and pressures from ambient to operating.

4.6.3.1.1.5 Surveillance Tests. The surveillance requirement s for the CRD system are as follows:

a. Prior to each in-vessel fuel movement during fuel loading sequence, the shutdown margin with the highest worth control rod withdrawn shall be analytically determined to be at least 0.38% k/k or shall be determined by test to be at least 0.28% k/k; b. Once within 4 hr after criticality foll owing fuel movement within the RPV or control rod replacement, the shutdown margin with the highest worth control

rod withdrawn shall be an alytically determined to be at least 0.38% k/k or shall be determined by test to be at least 0.28% k/k; c. Each withdrawn control r od shall be exercised one notch (i.e., inserted at least one notch and then may be returned to its original position) at least once every 31 days.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-020 4.6-31 The control rod exercise tests serve as a periodic check against deterioration of the control rod system and also verifies the ability of the CRD to scram. If a rod can be moved with drive pressure, it may be expected to scram since higher pressure is app lied during scram;

d. The coupling integrity shall be verified for each withdrawn control rod as follows:

1. When the rod is first withdrawn, observe discernible response of the nuclear instrumentation, and

2. When the rod is fully withdrawn each time, observe that the drive will not go to the over-travel position.

Observation of a response from the nuclear instrumentation during an attempt to withdraw a control rod indicates indirec tly that the rod and drive are coupled. The over-travel position feature provides a positive check on the coupling integrity, for only an uncoupled driv e can reach the over-travel position;

e. During operation, accumu lator pressure and level at the normal operating value shall be verified.

Experience with CRD systems of the same type indicates that weekly verification of accumulator pressure and level is sufficient to ensure operability of the accumulator portion of the CRD system;

f. At the time of each major refueling out age, each operable control rod shall be subjected to scram time tests from the fully withdrawn position.

Experience indicates that the scram times of the control rods do not significantly change over the time interval between re fueling outages. A test of the scram times at each refueling outage is sufficient to identify any significant lengthening of the scram times; and

g. A channel functional test of the accumulator leak detectors and a channel calibration of the accumulator pressure detectors, which verifies an alarm setpoint 940 psig on decreasing pressure, is performed at least once per 30 months.

4.6.3.1.1.6 Functional Tests . The functional tes ting program of the CRDs consists of the 5-year maintenance life and th e 1.5X design life test programs as described in Section 3.9.4.4. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 4.6-32 There are a number of failures th at can be postulated on the CRD but it would be very difficult to test all possible failures. A partial test program with pos tulated accident conditions and imposed single failures is available.

The following tests with imposed single failur es have been performed to evaluate the performance of the CRDs under these conditions:

a. Simulated ruptured scram line test,

b. Stuck ball check valve in CRD flange, c. HCU drive down inlet flow control valve (V122) failure, d. HCU drive down outlet flow control valve (V120) failure, e. CRD scram performan ce with V120 malfunction, f. HCU drive up outlet cont rol valve (V121) failure, g. HCU drive up inlet cont rol valve (V123) failure, h. Cooling water check valve (V138) leakage,

i. CRD flange check valve leakage,

j. CRD stabilization circuit failure,

k. HCU filter restriction,

l. Air trapped in CRD hydraulic system,

m. CRD collet drop test, and

n. CR qualification velo city limiter drop test.

Additional postulated CRD failure s are discussed in Sections 4.6.2.2.2.1 through 4.6.2.2.2.12 . 4.6.3.2 Control Rod Drive Housing Supports

CRD housing supports are removed for inspection and maintenance of the CRDs. The supports for one control rod can be removed during reactor shutdown, even when the reactor is pressurized, because all contro l rods are then inserted. When the support structure is reinstalled, it is inspected fo r correct assembly with particular attention to maintaining the correct gap between the CRD flange lower contact surf ace and the grid.

4.6.4 INFORMATION FOR COMBINED PERFORMANCE OF REACTIVITY CONTROL SYSTEMS

4.6.4.1 Vulnerability to Common Mode Failures The two reactivity control systems, the CRD and SLC systems, do not share any instrumentation or components. Thus, a common mode failure of the reactivity systems would be limited to an accident event which could damage essential equipment in the two independent systems.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 4.6-33 A seismic event or the postulated a ccident environments (see Section 3.11) are not considered potential common mode failures since the essen tial (scram) portions of the CRD system are designed to Seismic Category I standards and to operate as required und er postulated accident environmental conditions. The SLC system is also designed to Seismic Category I standards. No common mode power failure is considered credible. The scram function of the CRD system is "fail-safe" on a loss of power and is designed to ove rride any other CRD function. The SLC system has two independent power su pplies to its essential redundant pumps and valves. The power supplies to the SLC system are considered vital and as such are switched to the onsite standby diesels on a loss of normal power sources.

Essential components (including cabling and piping) for the SLC system are separated from essential CRD components in the secondary containment by phys ical barriers and/or by at least 40 ft of physical separa tion. The various safety studies performed by the architect-engineer verified that this separation is sufficient to prevent simultaneous failure of the reactivity systems due to pipe break and whip, credible fires, and all poten tial missiles. The location of the primary components of th ese systems is shown in Figures 1.2-7 through 1.2-12. The CRD insert and withdrawal lines penetrate at the bottom of the RPV whereas the SLC lines connect to the HPCS line which penetrates the RPV. Protection of the reactivity control systems from postulated events, such as pipe breaks, is discussed in Section 3.6. A fault tree analysis was completed for both of these systems, and the calculated unreliability is less than 10 -7/reactor year. This unreliability is an estimate of the failure to fully insert the control rods into the core, combin ed with a failure to inject bor on into the vessel by the SLC. Failure to insert control rods is defined to be noninsertion of the CRDs in the following manner: 50% in a "checkerboard pattern," 31 % in a random pattern, or 4% in a cluster.

4.6.4.2 Accidents Taking Credit for Multiple Reactivity Systems

There are no postulated accidents evaluated in Chapter 15 that take credit for two or more reactivity control systems preventing or mitigating each accident.

4.6.5 EVALUATION OF COMBINED PERFORMANCE

As indicated in Section 4.6.4.2, credit is not taken for multiple reactivity control systems for any postulated accidents in Chapter 15 . 4.6.6 ALTERNATE ROD INSERTION SYSTEM

4.6.6.1 System Description

The alternate rod insertion (ARI) system provides an alternate me ans to scram the control rods which is diverse and in dependent from the RPS. The ARI system may be actuated either COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 4.6-34 manually or automatically. The automatic signal to initiate ARI comes from high reactor vessel pressure or low reactor water level. The setpoints for ARI automatic initiation have been chosen such that a normal scram should already have been initiated by the above parameters prior to ARI initiation. The ARI system causes a scram by relieving the scram air header through four sets of solenoid valves. This, in turn, causes th e scram inlet and outlet valves to open. The CRD units then insert the control blades to shutdown the reactor. The ARI system has been designe d to ensure that rod motion be gins within sufficient time to ensure the ARI design objectives of Reference 4.6-2 are satisfied. These rod movement times are based on plant unique conditi ons and compliance with ARI desi gn objectives to ensure that plant safety considerations will be met.

4.6.6.2 Alternate Rod Insertion Redundancy

The ARI system constitutes a redundant back-up to the normal scra m system and is, therefore, not redundant in itself. That is , the ARI system is only one syst em with two divisions. Both divisions must function properly for the design basis rod in sertion times to be met.

The ARI system is, however, redunda nt in the aspect of preven ting spurious scrams. Each vent point for ARI in the scram air header consists of two valves in series (see Figure 4.6-5 ). The valves must be energized to vent the air header. This design is intended to prevent spurious scrams and unnecessary cycling of the power plant.

4.

6.7 REFERENCES

4.6-1 Benecki, J. E., "Impact Testing on Collet Assembly for Control Rod Drive Mechanism 7RD B144A," General El ectric Company, Atomic Power Equipment Department, APED-5555, November 1967.

4.6-2 NEDE-31096-P, "Licen sing Topical Report, Anticip ated Transient Without Scram," Response to NRC ATWS Ru le 10 CRF 50.62, February 1987. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.99Control Rod to Control Rod Drive Coupling 4.6-1Control Rod Assembly Unlocking Handle (Shown Raised

Against Spring

Force)Coupled View SpudUnlocking Lock plugTubeIndex Tube - DriveActuating

ShaftLock Plug Return Springs SocketVelocity Limiter Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Control Rod Drive Unit 960222.99 4.6-2Piston Tube Coupling Spud Guide Cap Fixed Piston (Stop Piston) Latch (Collet Fingers)Index Tube Moving Piston (Main Drive Piston) Drive Withdraw Line Bottom ofReactor Vessel DriveHousingCollet Piston Return Spring Collet Piston Drive Cylinder Drive Insert Line PRBall CheckValveArrows show water flow

when the drive is in the

withdrawal mode of

operation. Pressures shown are maximum.PR = Reactor Pressure Columbia Generating StationFinal Safety Analysis Report Tube Head FigureAmendment 53 November 1998Form No. 960690.veR.oN .warD Control Rod Drive Unit (Schematic)3-6.469.222069 ReactorPressureVesselReactorPressureVesselPressureOverPortHousingFlangeCircumferential ScreenOuter Tube Inner Tube PistonCoolingOrificeDriveMainFlangeRod Piston Information Detector ProbeBuffer Hole GuideCapControl RodGuide Tube StopPistonColl. Pist. Index Tube SpudPressureUnderPortOuter Tube Inner Tube Thermal Sleeve Piston Tube Inst Tube Index Tube Piston Tube Thermal Sleeve Coll. Pist. Outer Filter Outer Filter Index Tube Index Tube HousingFlangeDrive PistonDrive PistonDrive HousingDrive Housing Inner FilterGuideCapColumbia Generating Station Final Safety Analysis Report Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 4.6-5.179M528-1Control Rod Drive Hydraulic SystemRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 4.6-5.29M528-2Control Rod Drive Hydraulic SystemRev.FigureDraw. No.

Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 4.6-6.3302C12-04,26,2Control Rod Drive System (Process Diagram)Rev.FigureDraw. No. Control Rod Drive Hydraulic Control Unit 900547.25 4.6-7FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Charging Water RiserIsolation Valve Withdrawal RiserIsolation ValveDrive Water Riser Junction BoxWiring Trough Assembly Unit Interconnecting CableDirectional ControlValve (Withdraw)Shutoff Valve Water Accumulation DrainScram Accumulation N2 Cylinder Accumulator N 2Cartridge Valve

Accumulator N 2 Charging Accumulator

Instrumentation

AssemblyIsolation ValveScram Valve Pilot AirIsolation ValveExhaust Water RiserIsolation Valve Insert RiserIsolation Valve Scram Discharge RiserOutlet Scram ValveInlet Scram Valve Directional ControlValve (Insert) ManifoldDirectional Control Valve (Withdraw and Settle)Scram Water Accumulator FrameDirectional Control Valve (Insert)Isolation ValveCooling Water RiserScram Pilot Valve

AssemblyPressure Indicator Columbia Generating StationFinal Safety Analysis Report Control Rod Drive Housing Support 900547.26 4.6-8FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.BracketSteel Form LinerCRDHousingHangerRodReactor Vessel

Support PedestalCRD Flange Support Bar Grid Clamp Grid Bolt Grid Plates Disc SpringsBeamsWasherJam NutNutColumbia Generating StationFinal Safety Analysis Report COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS Section Page 5-i 5.1 SUMMARY DESCRIPTION............................................................5.1-1 5.1.1 SCHEMATIC FLOW DIAGRAM...................................................5. 1-3 5.1.2 PIPING AND INSTRUMENTATION DIAGRAM............................... 5.1-3 5.1.3 ELEVATION DRAWING.............................................................5.1-3 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY...........5.2-1 5.2.1 COMPLIANCE WITH CO DES AND CODE CASES...........................5.2-1 5.2.1.1 Compliance with 10 CFR Part 50, Section 50.55a..............................5.2-1 5.2.1.2 Applicable Code Cases...............................................................5.2-1 5.2.2 OVERPRESSURIZATION PROTECTION........................................5.2-2 5.2.2.1 Design Bases...........................................................................5.2-2 5.2.2.1.1 Safety Design Basis.................................................................5.2-2 5.2.2.1.2 Power Genera tion Design Bases.................................................5.2-2 5.2.2.1.3 Di scussion............................................................................5.2-3 5.2.2.1.4 Safety Valve Capacity..............................................................5.2-3 5.2.2.2 Design Evaluation.....................................................................5.2-4 5.2.2.2.1 Method of Analysis.................................................................5.2-4 5.2.2.2.2 System Design.......................................................................5.2-4 5.2.2.2.3 Evaluati on of Results...............................................................5.2-5 5.2.2.2.3.1 Safety Valve Capacity...........................................................5.2-5 5.2.2.2.3.2 Pressure Dr op in Inlet and Discharge.........................................5.2-6 5.2.2.2.3.3 Reload Speci fic Confirmatory Analysis......................................5.2-6 5.2.2.3 Piping and Instrument Diagrams....................................................5.2-6 5.2.2.4 Equipment and Component Description...........................................5.2-6 5.2.2.4.1 Desc ription...........................................................................5.2-6 5.2.2.4.2 Design Parameters..................................................................5.2-9 5.2.2.4.2.1 Safety/Relief Valve..............................................................5.2-9 5.2.2.5 Mounting of Pressure Relief Devices..............................................5.2-10 5.2.2.6 Applicable Codes and Classification...............................................5.2-10 5.2.2.7 Material Specification................................................................5.2-10 5.2.2.8 Process Instrumentation..............................................................5.2-10 5.2.2.9 System Reliability.....................................................................5. 2-10 5.2.2.10 Inspection and Testing..............................................................5.2-11 5.2.3 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS............5.2-16 5.2.3.1 Material Specifications...............................................................5.2-16 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-02-046 5-ii 5.2.3.2 Compatibility with Reactor Coolant................................................5.2-16 5.2.3.2.1 Pressurized Water Reactor Chemistry of Reactor Coolant..................5.2-16 5.2.3.2.2 Boiling Water Reactor Ch emistry of Reacto r Coolant.......................5.2-16 5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant.............5.2-19 5.2.3.2.4 Compatibility of Constructi on Materials with External Insulation and Reactor Coolant................................................................ 5.2-20 5.2.3.3 Fabrication and Processing of Ferritic Materials and Austenitic Stainless Steels.........................................................................5.2-20 5.2.4 INSERVICE INSPECTION AND TESTING OF THE REACTOR COOLANT PRESSURE BOUNDARY.............................................5.2-21 5.2.4.1 System Boundary Subject to Inspection...........................................5.2-21 5.2.4.2 Arrangement of Systems and Components to Provide Accessibility.........5.2-22 5.2.4.2.1 Reactor Pr essure Vessel...........................................................5. 2-23 5.2.4.2.2 Piping, Pu mps, and Valves.......................................................5.2-24 5.2.4.3 Examination Techniques and Procedures.........................................5.2-24 5.2.4.3.1 Equipment for Inservice Inspection..............................................5.2-24 5.2.4.3.2 Coordination of Inspection Equipment With Access Provisions............5.2-25 5.2.4.3.3 Manual Examination...............................................................5.2-25 5.2.4.4 Inspection Intervals...................................................................5. 2-25 5.2.4.5 Examination Categories and Requirements.......................................5.2-25 5.2.4.6 Evaluation of Examination Results.................................................5.2-25 5.2.4.7 System Leakage and Hydrostatic Pressure Tests................................5.2-26 5.2.4.8 Inservice Inspection Commitment..................................................5.2-26 5.2.4.9 Augmented Inservice Inspecti on to Protect Against Postulated Piping Failures..................................................................................5.2-26 5.2.4.10 Augmented Inservice Inspection of Reactor Pressure Vessel Feedwater Nozzles.................................................................................5.2-27 5.2.4.10.1 Pr eservice Examination.......................................................... 5.2-27 5.2.4.10.2 Inservi ce Examination............................................................5.2-27 5.2.4.11 Augmented Inservice Inspec tion for Intergrannular Stress Corrosion Cracking................................................................................5.2-27 5.2.4.12 ASME Section XI Repairs/Replacements........................................5.2-27 5.2.5 DETECTION OF LEAKAGE THROUGH REACTOR COOLANT PRESSURE BOUNDARY............................................................. 5.2-28 5.2.5.1 Leakage Detection Methods.........................................................5.2-28 5.2.5.1.1 Detection of Abnormal Leakage Within the Primary Containment........5.2-28 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-02-046, 04-033 5-iii 5.2.5.1.2 Detection of Abnormal Leakage Outside the Primary Containment.......5.2-29 5.2.5.2 Leak Detection Devices..............................................................5.2-30 5.2.5.3 Indication in the Control Room.....................................................5.2-31 5.2.5.4 Limits for Reactor Coolant Leakage...............................................5.2-32 5.2.5.4.1 Total Leakage Rate.................................................................5.2-32 5.2.5.4.2 Normally Exp ected Leakage Rate................................................5.2-32 5.2.5.5 Unidentified Leakage Inside the Drywell.........................................5.2-33 5.2.5.5.1 Unidentified Leakage Rate........................................................5.2-33 5.2.5.5.2 Length of Through-Wall Flaw....................................................5.2-33 5.2.5.5.3 Criteria to Evaluate the Adequacy and Margin of the Leak Detection System....................................................................5.2-34 5.2.5.6 Safety Interfaces.......................................................................5. 2-34 5.2.5.7 Testing and Calibration...............................................................5.2-34 5.

2.6 REFERENCES

........................................................................... 5.2-34 5.3 REACTOR VESSEL......................................................................5.3-1 5.3.1 REACTOR VESS EL MATERIALS..................................................5.3-1 5.3.1.1 Materials Specifications..............................................................5.3-1 5.3.1.2 Special Processes Used for Manufacturing and Fabrication...................5.3-1 5.3.1.3 Special Methods for Nondestructive Examination...............................5.3-2 5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels...................5.3-2 5.3.1.5 Fracture Toughness...................................................................5.3-2 5.3.1.5.1 Compliance with Code Requirements...........................................5.3-2 5.3.1.5.2 Compliance with 10 CFR 50 Appendix G......................................5.3-2 5.3.1.5.2.1 Intent of Proposed Approach...................................................5.3-3 5.3.1.5.2.2 Operating Limits Based on Fracture Toughness............................5.3-3 5.3.1.5.2.3 Temperature Limits for Boltup.................................................5.3-5 5.3.1.5.2.4 Inservice Inspection Hydrostatic or Leak Pressure Tests..................5.3-5 5.3.1.5.2.5 Operating Limits During Heatup, Cool down, and Core Operation.....5.3-6 5.3.1.5.2.6 Reactor Vessel Annealing.......................................................5.3-6 5.3.1.6 Material Surveillance.................................................................5.3-6 5.3.1.6.1 Positioning of Surveillance Capsules and Method of Attachment for Plant-Specific Surveillance Program............................................5.3-7 5.3.1.6.2 Time and Number of Dosimetry Measurements...............................5.3-7 5.3.1.6.3 Neutron Flux and Fluence Calculations......................................... 5.3-8 5.3.1.7 Reactor Vessel Fasteners.............................................................5.3-8 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-04-033 5-iv 5.3.2 PRESSURE-TEMP ERATURE LIMITS.............................................5.3-9 5.3.2.1 Limit Curves...........................................................................5.3-9 5.3.2.2 Operating Procedures.................................................................5.3-9 5.3.3 REACTOR VESSEL INTEGRITY...................................................5.3-9 5.3.3.1 Design...................................................................................5.3-10 5.3.3.1.1 Desc ription...........................................................................5.3-10 5.3.3.1.1.1 Reactor Vessel....................................................................5. 3-10 5.3.3.1.1.2 Shroud Support...................................................................5. 3-10 5.3.3.1.1.3 Protec tion of Closure Studs.....................................................5.3-10 5.3.3.1.2 Safety Design Bases................................................................5.3-11 5.3.3.1.3 Power Genera tion Design Basis..................................................5.3-11 5.3.3.1.4 Reactor Ve ssel Design Data...................................................... 5.3-11 5.3.3.1.4.1 Vessel Support....................................................................5. 3-12 5.3.3.1.4.2 Control Rod Drive Housings...................................................5.3-12 5.3.3.1.4.2.1 Contro l Rod Drive Return Line.............................................5.3-12 5.3.3.1.4.3 In-Core Ne utron Flux Monitor Housings....................................5.3-12 5.3.3.1.4.4 Reactor Vessel Insulation.......................................................5.3-12 5.3.3.1.4.5 Reactor Vessel Nozzles.........................................................5.3-12 5.3.3.1.4.6 Materials and Inspection........................................................5.3-14 5.3.3.1.4.7 Reactor Vessel Schematic (BWR).............................................5.3-14 5.3.3.2 Material s of Construction............................................................5.3-14 5.3.3.3 Fabr ication Methods..................................................................5.3-15 5.3.3.4 Inspection Requirements.............................................................5.3-15 5.3.3.5 Shipment and Installation............................................................5.3-15 5.3.3.6 Operating Conditions.................................................................5.3-16 5.3.3.7 Inservice Surveillance................................................................5.3-16 5.

3.4 REFERENCES

........................................................................... 5.3-17 5.4 COMPONENT AND SUBSYSTEM DESIGN.......................................5.4-1 5.4.1 REACTOR RECIRC ULATION PUMPS...........................................5.4-1 5.4.1.1 Safe ty Design Bases...................................................................5.4-1 5.4.1.2 Power Ge neration Design Bases....................................................5.4-1 5.4.1.3 Description.............................................................................5.4-1 5.4.1.3.1 Recirculation System Cavitation Consideration...............................5.4-5 5.4.1.4 Safety Evaluation......................................................................5.4-5 5.4.1.5 Inspection and Testing................................................................5.4-6 COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-00-056, 01-009, 01-025 5-v 5.4.2 STEAM GENERA TORS (PWR).....................................................5.4-6 5.4.3 REACTOR COOLANT PIPING......................................................5. 4-7 5.4.4 MAIN STEAM LINE FLOW RESTRICTORS....................................5.4-7 5.4.4.1 Safe ty Design Bases...................................................................5.4-7 5.4.4.2 Description.............................................................................5.4-7 5.4.4.3 Safety Evaluation......................................................................5.4-8 5.4.4.4 Inspection and Testing................................................................5.4-8 5.4.5 MAIN STEAM LINE ISOLATION SYSTEM.....................................5.4-9 5.4.5.1 Safe ty Design Bases...................................................................5.4-9 5.4.5.2 Description.............................................................................5.4-10 5.4.5.3 Safety Evaluation......................................................................5. 4-12 5.4.5.4 Inspection and Testing................................................................5.4-13 5.4.6 REACTOR CORE ISOL ATION COOLING SYSTEM..........................5.4-14 5.4.6.1 Design Bases...........................................................................5.4-14 5.4.6.2 System Design.........................................................................5.4-16 5.4.6.2.1 General............................................................................... 5.4-16 5.4.6.2.1.1 Description........................................................................5. 4-16 5.4.6.2.1.2 Diagrams...........................................................................5.4-17 5.4.6.2.1.3 Interlocks..........................................................................5.4-18 5.4.6.2.2 Equipment and Co mponent Description........................................ 5.4-19 5.4.6.2.2.1 Design Conditions................................................................5.4-19 5.4.6.2.2.2 Design Parameters...............................................................5.4-20 5.4.6.2.2.3 Overpressure Protection.........................................................5.4-25 5.4.6.2.3 Applicable Codes and Classifications........................................... 5.4-27 5.4.6.2.4 System Reliab ility Considerations............................................... 5.4-27 5.4.6.2.5 System Operation...................................................................5. 4-28 5.4.6.2.5.1 Au tomatic Operation.............................................................5.4-28 5.4.6.2.5.2 Test Loop Operation.............................................................5.4-29 5.4.6.2.5.3 Steam Conden sing (Hot Standby) Operation................................5.4-29 5.4.6.2.5.4 Manual Actions...................................................................5. 4-30 5.4.6.2.5.5 Reactor Core Isolation Cooling Discharge Line Fill System.............5.4-30 5.4.6.3 Performance Evaluation..............................................................5.4-30 5.4.6.4 Preope rational Testing................................................................5.4-30 5.4.6.5 Safety Interfaces.......................................................................5. 4-30 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-04-027 5-vi 5.4.7 RESIDUAL HEAT REMOVAL SYSTEM.........................................5.4-30 5.4.7.1 Design Bases...........................................................................5.4-30 5.4.7.1.1 Functiona l Design Basis...........................................................5.4-31 5.4.7.1.2 Design Basis fo r Isolation of Residual Heat Removal System from Reactor Coolant System........................................................... 5.4-33 5.4.7.1.3 Design Basis for Pr essure Relief Capacity.....................................5.4-33 5.4.7.1.4 Design Basis With Respect to General Design Criterion 5..................5.4-36 5.4.7.1.5 Design Basis for Reliability and Operability................................... 5.4-36 5.4.7.1.6 Design Basis for Protect ion from Physical Damage..........................5.4-37 5.4.7.2 Systems Design........................................................................5. 4-37 5.4.7.2.1 System Diagrams...................................................................5. 4-37 5.4.7.2.2 Equipment and Co mponent Description........................................ 5.4-38 5.4.7.2.3 Controls a nd Instrumentation..................................................... 5.4-40 5.4.7.2.4 Applicable Codes and Classifications........................................... 5.4-40 5.4.7.2.5 Reliability Considerations......................................................... 5.4-41 5.4.7.2.6 Manual Action.......................................................................5. 4-41 5.4.7.3 Performance Evaluation..............................................................5.4-41 5.4.7.3.1 Shutdown Cooling With All Components Available..........................5.4-42 5.4.7.3.2 Shutdown Cooling With Most Limiti ng Failure...............................5.4-42 5.4.7.4 Preope rational Testing................................................................5.4-42 5.4.8 REACTOR WATER CLEANUP SYSTEM........................................5.4-43 5.4.8.1 Design Bases...........................................................................5.4-43 5.4.8.1.1 Safety Design Bases................................................................5.4-43 5.4.8.1.2 Power Genera tion Design Bases.................................................5.4-43 5.4.8.2 System Description....................................................................5. 4-44 5.4.8.3 System Evaluation.....................................................................5. 4-45 5.4.8.4 Demi neralizer Resins.................................................................5.4-46 5.4.8.5 Reactor Water Cleanup Water Chemistry.........................................5.4-46 5.4.8.5.1 Analy tical Methods.................................................................5. 4-46 5.4.8.5.2 Relationship of Filter-Demineralizer Condition to Water Chemistry......5.4-46 5.4.9 MAIN STEAM LINES AND FEEDWATER PIPING........................... 5.4-47 5.4.9.1 Safe ty Design Bases...................................................................5. 4-47 5.4.9.2 Power Ge neration Design Bases....................................................5.4-47 5.4.9.3 Description.............................................................................5.4-47 5.4.9.4 Safety Evaluation......................................................................5. 4-48 5.4.9.5 Inspection and Testing................................................................5.4-48 COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-01-009, 01-025 5-vii 5.4.10 PRESSURIZER......................................................................... 5.4-48 5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM.............................. 5.4-48 5.4.12 VALVES.................................................................................5.4-48 5.4.12.1 Safety Design Bases.................................................................5.4-48 5.4.12.2 Description............................................................................5.4-48 5.4.12.3 Safety Evaluation....................................................................5. 4-49 5.4.12.4 Inspection and Testing..............................................................5.4-49 5.4.13 SAFETY AND RELIEF VALVES.................................................5.4-50 5.4.13.1 Safety Design Bases.................................................................5.4-50 5.4.13.2 Description............................................................................5.4-50 5.4.13.3 Safety Evaluation....................................................................5. 4-50 5.4.13.4 Inspection and Testing..............................................................5.4-50 5.4.14 COMPONENT AND PIPING SUPPORTS.......................................5.4-50 5.4.14.1 Safety Design Bases.................................................................5.4-51 5.4.14.2 Description............................................................................5.4-51 5.4.14.3 Inspection and Testing..............................................................5.4-51 5.4.15 HIGH-PRESSURE CO RE SPRAY SYSTEM....................................5.4-52 5.4.16 LOW-PRESSURE CORE SPRAY SYSTEM.....................................5.4-52 5.4.17 STANDBY LIQUID CONTROL SYSTEM.......................................5.4-52 5.4.18 REFERENCES......................................................................... 5.4-52

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF TABLES

Number Title Page LDCN-02-000 5-viii 5.2-1 Exceptions to Conform ance to 10 CFR 50.55a

Reactor Coolant Pressure Boundary Components 5.2-37 5.2-2 Reactor Coolant Pressure Boundary Component Code Case Interpr etations 5.2-38

5.2-3 Nuclear Sy stem Safety/Relief Setpoints 5.2-39

5.2-4 Systems Which May Ini tiate During Safety Valve

Capacity Overpressure Event 5.2-40 5.2-5 Sequence of Events for Figure 5.2-2 5.2-41 5.2-6 Design Temperature, Pressure and Maximum T est Pressure for RCPB Components 5.2-42

5.2-7 Reactor Coolant Press ure Boundary M aterials 5.2-45

5.2-8 Water Sample Locations 5.2-48 5.2-9 IHSI Summary Prior to First Refueling GL 88-01 Category B Welds 5.2-49 5.2-10 IHSI Summary During First Refueling GL 88-01 Category B Welds 5.2-50 5.2-11 Main Steam Isolation Valv es Material Information 5.2-51 5.2-12 Summary of Isolation/Alarm of System Monitored and the Leak Detection Methods Used 5.2-52 5.3-1 10 CFR 50 Appendix G Matrix 5.3-19 5.3-2 Plate Material Cross Reference 5.3-23 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF TABLES (Continued)

Number Title Page LDCN-04-033 5-ix 5.3-3 Weld Material Cr oss Reference..............................................5.3-24 5.3-4 Plate Material.................................................................... 5.3-25 5.3-5 Weld Material...................................................................5.3-26

5.3-6 Vessel Beltli ne Plate............................................................5.3-29

5.3-7 Vessel Beltline Weld Material Chemistry..................................5.3-30 5.3-8 10 CFR 50 Appendi x H Matrix..............................................5.3-31

5.3-9 Reactor Vessel Beltline Minimum Wall Thickness and Diameter......5.3-33

5.4-1 Reactor Coolant Pressu re Boundary Pump and Valve Description.......................................................................5. 4-53 5.4-2 Reactor Recirculation System Design Characteristics....................5.4-58

5.4-3 Operating Experience of I ngersoll-Rand Emergency Core Cooling Systems Pumps........................................................5.4-60

5.4-4 Operating Experience of Sim ilar Ingersoll-Rand Pumps for BWR Projects Under Review..................................................5.4-61

5.4-5 Reactor Water Cleanup System...............................................5.4-62

5.4-6 Safety and Relief Valve for Piping Systems Connected to the Reactor Coolant Pressure Boundary................................. 5.4-63 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES

Number Title LDCN-15-011 5-x 5.1-1 Rated Operating Conditions of the Boiling Water Reactor 5.1-2 Coolant Volumes of the Boiling Water Reactor 5.2-1 Simulated Safety Relief Valve Spring Mode Characteristic Used for Capacity Sizing Analysis

5.2-2 MSIV Closure with Flux Scram - Nominal Safety Setpoint +3% 6 SRV Out-of-Service

5.2-3 Peak Vessel Pressure Versus Safety Valve Capacity

5.2-4 Time Response of Pressure Vessel For Pressurization Events

5.2-5 Nuclear Boiler System (P&ID)

5.2-6 Safety/Relief Valve Schematic Elevation

5.2-7 Safety/Relief Valve and Steam Line Schematic

5.2-8 Schematic of Safety Valve With Auxiliary Actuating Device

5.2-9 Safety Valve Lift Versus Time Characteristics

5.2-10 Conductance Versus pH as a Function of Chloride Concentration of Aqueous Solution at 25°C

5.2-11 Deleted

5.3-1 Pressure Temperature Limits - Cu rves A through C (Sheets 1 through 3)

5.3-2 Vessel Beltline Plate and Weld Seam Identification

5.3-3 Nominal Reactor Vessel Water Level Trip and Alarm Elevation Settings

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES (Continued)

Number Title 5-xi 5.3-4 Bracket for Holdin g Surveillance Capsule 5.3-5 Reactor Vessel

5.3-6 Feedwater Nozzle

5.3-7 Feedwater Sparger

5.4-1 Recirculation System Evaluation and Isometric

5.4-2 RRC Pump Dynamic Head - Flow Curve

5.4-3 RRC Pump Speed - Torque Curve

5.4-4 Recirculation Pump Head, NPSH, Flow and Efficiency Curves

5.4-5 Operating Principle of Jet Pump

5.4-6 Core Flooding Capability of Recirculation System

5.4-7 Reactor Recirculation System - P&ID (Sheets 1 and 2)

5.4-8 Main Steam Line Flow Restrictor Location

5.4-9 Main Steam Line Isolation Valve

5.4-10 Reactor Core Isolation Cooling Pump Performance Curve (Constant Flow) 5.4-11 Reactor Core Isolation Cooling System - P&ID

5.4-12 Reactor Core Isolation Cooling System Process Diagram

5.4-13 Reactor Core Isolation Cooling Pump Performance Curve

5.4-14 Typical Strainer

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES (Continued)

Number Title LDCN-12-036 5-xii 5.4-15 Residual Heat Removal Syst em - P&ID (Sheets 1 through 4) 5.4-16 Residual Heat Removal System Process Diagram

5.4-17 Residual Heat Removal System Process Data (Sheets 1 and 2)

5.4-18 Residual Heat Rem oval (LPCI) Pump Characteristics (S/N 0473113) P-2A

5.4-19 Residual Heat Rem oval (LPCI) Pump Characteris tics (S/N 0801MP004399-1) P-2B 5.4-20 Residual Heat Rem oval (LPCI) Pump Characteristics (S/N 0473112) P-2C

5.4-21 Vessel Coolant Temper ature Versus Time (Two Heat Exchangers Available)

5.4-22 Reactor Water Cleanup System - P&ID (Sheets 1 through 3)

5.4-23 Reactor Water Cleanup System Process Diagram (Sheets 1 and 2)

5.4-24 Filter/Deminera lization System P&ID

5.4-25 Vessel Coolant Temp erature Versus Time (One Heat Exchanger Available)

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.1-1 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

5.1 SUMMARY DESCRIPTION

The reactor coolant system includes those systems and components which contain or transport fluids coming from, or going to the reactor core. These systems form a major portion of the reactor coolant pressure boundary (RCPB). This chapter provides information regarding the reactor coolant system and pressure-containi ng appendages out to a nd including isolation valving. This grouping of components is defined as follows:

The RCPB includes all pressure -containing components such as pressure vessels, piping, pumps, and valves, which are

a. Part of the reactor coolant system, or

b. Connected to the reactor coolant system

, up to and including any and all of the following:

1. The outermost containment isolat ion valve in system piping that penetrates primary reactor containment,

2. The second of the two valves normally closed during normal reactor operation in system piping that doe s not penetrate primary reactor containment, and

3. The reactor coolant system safety/relief valves.

Section 5.4 discusses the various s ubsystems to the RCPB.

The nuclear system pressure relief system protects the reactor coolant pressure boundary from damage due to overpressure. To protect against overpressure, pr essure-operated relief valves are provided that can discharge steam from the nuclear system to the suppression pool. The pressure relief system also acts to automatically depre ssurize the nuclear system in the event of a loss-of-coolant accident (LOCA ) in which the high-pressure core spray (HPCS) system fails to maintain reactor vessel water level. Depressurization of the nuclear system allows the low-pressure core cooling systems to supply enough cooli ng water to adequately cool the fuel. Section 5.2.5 establishes the limits on nuclear system leakage inside th e drywell so that appropriate action can be taken before the integrity of the nuclear system process barrier is impaired.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.1-2 The reactor vessel and appurtenan ces are described in Section 5.3. The major safety consideration for the reactor vessel is concerned with the ability of the vessel to function as a radioactive material barrier. Various combinations of loadi ng are considered in the vessel design. The vessel meets the requirements of various applicable codes and criteria. The possibility of brittle fracture is considered, and suitable design, material selection, material surveillance activities, and operational limits are establishe d that avoid conditions where brittle fracture is possible.

The reactor recirculation system provides coolan t flow through the core. Adjustment of the core coolant flow rate changes reactor power output, thus providing a means of following plant load demand without adjusting control rods. The recirculation system is designed to provide a slow coast down of flow so that fuel thermal limits cannot be exceeded as a result of recirculation system malfunctions. The arrangement of the recircul ation system routing is such that a piping failure cannot compromise the integrity of th e floodable inner volume of the reactor vessel.

Main steam line flow restrictors of the venturi-type are installed in each main steam line inside the primary containment. The restrictors ar e designed to limit the loss-of-coolant resulting from a main steam line break outsi de the primary containment. The coolant loss is limited so that reactor vessel water level remains above the top of the core during the time required for the main steam isolation valves (MSIVs) to close. This action protects the fuel barrier.

The MSIVs automatically isolate the reactor coolant pressure boundary in the event a pipe break occurs downstream of the isolation valves . This action limits th e loss-of-coolant and the release of radioactive materials from the nuclear system. Two isolation valves are installed on each main steam line; one is located inside, and the other is located outside the primary containment. In the event that a main steam li ne break occurs inside the containment, closure of the other isolation valve outside the primary containment acts to seal the containment itself.

The reactor core isolation cooling (RCIC) system provides makeup water to the core during a reactor shutdown in which feedwater flow is not available. The system is started automatically upon receipt of a low reactor water level signal or manually by the operator. Water is pumped to the core by a turbine pum p driven by reactor steam.

The residual heat removal (RHR) system includes a number of pumps and heat exchangers that can be used to cool the nuclear system under a variety of situations. During normal shutdown and reactor servicing, the RHR system removes residual and decay heat. The RHR system allows decay heat to be removed whenever the main heat sink (main conde nser) is not available (e.g., hot standby). One mode of RHR operation allows the rem oval of heat from the primary containment following a LOCA. Another op erational mode of the RHR system is COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009 5.1-3 low-pressure coolant injection (LPCI). The LPCI operation is an engineered safety feature for use during a postulated LOCA. This operation is descri bed in Section 6.3. The low-pressure core spray (LPCS) system also provide s protection to the nuclear system.

The reactor water cleanup system recirculates a portion of reactor coolant through a filter-demineralizer subsystem to remove particulate and disso lved impurities fr om the reactor coolant. It also removes ex cess coolant from the reactor sy stem under controlled conditions.

5.1.1 SCHEMATIC FLOW DIAGRAM Schematic flow diagrams of the reactor coolant system denoting all major components, principal pressures, temperatur es, flow rates, and coolant volumes for normal steady-state operating conditions at rated power are presented in Figures 5.1-1 and 5.1-2. 5.1.2 PIPING AND INST RUMENTATION DIAGRAM

Piping and instrumentation diagrams covering the systems included within the reactor coolant system and connected systems are presented in the following:

a. The nuclear boiler, main steam, and feedwater systems shown in Figure 10.3-2

, b. Recirculation system shown in Figure 5.4-7 , c. RCIC system shown in Figure 5.4-11 , d. RHR system shown in Figures 5.4-16 and 5.4-17, e. Reactor water cleanup system shown in Figure 5.4-22 , f. HPCS system shown in Figure 6.3-4 , g. LPCS system shown in Figure 6.3-4 , and h. Standby liquid control system shown in Figure 9.3-14 . 5.1.3 ELEVATION DRAWING

An elevation drawing showing the principal dime nsions of the reactor and coolant system in relation to the containment is shown in Figures 1.2-11 and 1.2-12. 108.5 x 10

61. Core Inlet

2. Core Outlet

3. Separator Outlet (Steam Dome)

4. Steam Line (2nd Isolation Valve)

5. Feedwater Inlet (Includes RWCU Return Flow)

6. Recirculating Pump Suction

7. Recirculating Pump Discharge 1069 1047 1035 1000 1063 1037 1327534 550 549 545 421 534 535528.7 639.91191.0 1191.0398.5 528.4 529.8PRESSURE(psia)FLOW(lb/hr)TEMP.(F)ENTHALPY(Btu/lb)108.5 x 10 6*FCVFCVJet PumpCoreRecirculation PumpDriving Flow Main Feed FlowMain Steam Flow Turbine Steam Dryers Steam Separators 7165432Note 1Note 1* Channel Bypass - Nominally 10% Note 1: The FCVs are kept in mechanically blocked full open position.

Note 1Rated Operating Conditions of theBoiling Water Reactor 900547.44 5.1-1FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.15.0 x 10 615.0 x 10 615.2 x 10 632 x 10632 x 106Columbia Generating StationFinal Safety Analysis Report A. Lower Plenum B. Core C. Upper Plenum and Separators D. Dome (Above Normal Water Level)

E. Downcomer Region F. Recirculating Loops and Jet Pumps 4010 1990 2290 7160 5210 1010Volume of Fluid (ft

3) Note1: The FCVs are kept in mechanically blocked full open position.Coolant Volumes of the Boiling Water Reactor 960690.04 5.1-2FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report FCVFCVJet PumpCoreRecirculation PumpDriving Flow Main Feed FlowMain Steam Flow Turbine Steam Dryers Steam Separators Note 1Note 1Note 1BADFEC COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 5.2-1 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY

This section discusses measures employed to provide and maintain the integrity of the reactor coolant pressure boundary (RCPB) for the plant design lifetime.

5.2.1 COMPLIANCE WITH CODES AND CODE CASES

5.2.1.1 Compliance with 10 CFR Part 50, Section 50.55a Table 3.2-1 shows compliance with the rules of 10 CFR Part 50.55a "Code s and Standards." The American Society of Mechanical Engineers (ASME) Code edition, applicable addenda, and component dates are in accordance with 10 CFR 50.55a except for those RCPB components listed in Table 5.2-1 . The design, fabrication, and testing of the RCPB components listed in Table 5.2-1 were in accordance with the recognized codes and standards in effect at the time th e components were ordered as shown in the table. The code edition and applicable addenda that would be required by strict interpreta tion of the rules set forth in 10 CFR 50.55a are identified in Table 5.2-1 . Application for Columbia Generating Stati on (CGS) was filed with the Commission in August 1971. At that time a construction perm it was expected before the end of the 1972, but requests for additional seismic data in August 1972 caused the issuance of the construction permit to go beyond the end of the year to Ma rch 19, 1973. As is common practice in the utility industry, Energy Northwest proceeded with the engineering, design, and material and components procurement in anticipation of th e award of a construction permit to meet construction schedules. Had the construction permit been is sued as initially expected, the requirements of 10 CFR 50.55a would have been met to the letter of the law.

However, in each instance of exception the ASME Code version a pplied was one addenda earlier (6 months) than the code version requi red by the rules of 10 CFR 50.55a. The changes embodied in the later ASME Code addenda were reviewed. It was concluded that the addenda required by the rules of 10 CFR 50.55a affected documentation format but imposed no new technical requirements or change s in quality control procedures from the code version applied in the procurement of the components. Th e level of safety and quality provided by conformance to the earlier code edition and addenda applied in procurement is equivalent to that which would be required by strict application of the rules of 10 CFR 50.55a. The effort and expense of recertification of these com ponents, which had all been shipped to the construction site, would not have provided a comp ensating increase in th e level of safety and quality.

5.2.1.2 Applicable Code Cases

The reactor pressure vessel (R PV) and appurtenances and the RC PB piping, pumps and valves, were designed, fabricated, and tested in accordance with the applicable edition of the ASME COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-2 Code, Section III, including the addenda that were mandatory at the order date for the applicable components. This is in compliance with the intent of Regulat ory Guides 1.84 and 1.85. Section 50.55a of 10 CFR Part 50 requires code case approval only for Class 1 components. These code cases contain requirements or special rules which may be used for the construction of pressure-retaining components of Quality Group Classification A. The various ASME Code case interpretations that were applied to components in the RCPB are listed in Table 5.2-2. Code cases listed in Table 5.2-2 are those used in the original construction of CGS. Other c ode cases that are a dopted for use, as a pproved by Regulatory Guides 1.147, 1.84, 1.85, or specifically approved by the Regulatory Authority for use at CGS, are specified in the component's design specification as required by ASME Section III. 5.2.2 OVERPRESSURIZATION PROTECTION

5.2.2.1 Design Bases

Overpressurization protection is provided in conformance with 10 CFR 50, Appendix A,

General Design Criterion 15.

5.2.2.1.1 Safety Design Basis

The nuclear pressure-relie f system is designed to

a. Prevent overpressurization of the nuclear system that could lead to the failure of the RCPB,

b. Provide automatic depr essurization for small breaks in the nuclear system occurring with maloperation of the high-pressure core spray (HPCS) system so that the low-pressure coolant injection (LPCI) and the low-pressure core spray (LPCS) systems can operate to protect the fuel barrier (see Section 6.3.2.2.2

),

c. Permit verification of its operability, and

d. Withstand adverse combinations of load ings and forces resulting from operation during abnormal, accident, or special event conditions.

5.2.2.1.2 Power Gene ration Design Bases The nuclear pressure relief system safety/relief valves (SRV) ha ve been designed to meet the following power ge neration bases:

a. Discharge to the containment suppression pool, and

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-98-113 5.2-3 b. Correctly reclose following operation so that maximum operational continuity can be obtained.

5.2.2.1.3 Discussion

The ASME Boiler and Pressure Vessel Code (B&PV Code) requires that each component designed to meet Section III be protected from overpressure under upset conditions. The code allows a peak allowable pressu re of 110% of design pressure under upset c onditions. The code specifications for safety valves require that (a) the lowest safety valve setpoint will be set at or below design pressure, and (b) the highest safety valve setpoint will be set so that total accumulated pressure does not exceed 110% of the design pressure for upset conditions. The SRVs are designed to open by means of either of two modes of operation as discussed in Chapter 15. The safety (spring) setpoints are listed in Table 5.2-3 and satisfy the first of the above-mentioned ASME Code specifi cations for safety valves becau se all valves open at less than the nuclear system de sign pressure of 1250 psig.

The automatic depressurization capability of the nucl ear system pressure relief system is evaluated in Sections 6.3 and 7.3. The following detailed criteria are used in selection of SRVs:

a. Must meet requirements of ASME Code, Section III,

b. Valves must qualify for 100% of na meplate capacity cred it for overpressure protection function, and

c. Must meet other performance require ments such as response time, etc., as necessary to provide relief functions.

The SRV discharge piping is constructed in accordance with the ASME Code, Section III, 1971 Edition through the Winter 1973 Addenda.

5.2.2.1.4 Safety Valve Capacity

The safety valve capacity of this plant is ad equate to limit the primary system pressure, including transients, to the re quirements of the ASME B&PV Code, Section III, 1971 Edition through the Summer 1971 Addenda.

Table 5.2-4 lists the systems which c ould initiate during the safety valve capacity overpressure event.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 5.2-4 5.2.2.2 Design Evaluation

5.2.2.2.1 Method of Analysis

To design the pressure protection for the nuclear boiler system, extensive analytical models representing all essential dynamic characteristic s of the system are simulated on a large computing facility. These models include the hydrodynamics of the flow loop, the reactor

kinetics, the thermal characteristics of the fuel and its transfer of heat to the coolant, and all the principal controller features, such as feedwater flow, recircula tion flow, reactor water level, pressure, and load demand. These are presented with all their principal nonlinear features in models that have evolved through extensive expe rience and favorable co mparison of analysis with actual boiling water reactor (BWR) test data.

A detailed description of the models is documented in licensi ng topical reports, References 5.2-1 and 5.2-7. Safety/relief valves are simulated in the nonlinear repr esentation, and the models thereby allow full investigation of the various valve response times, valve capacities, and actuation setpoints that are available in applicable hardware systems.

The typical capacity characteristic as modeled is represented in Figure 5.2-1 for the spring mode of operation. The associated turbine bypass, turbine control valve (TCV), and main steam isolation valve (MSIV) characteristics are also simulated in the models.

The associated bypass, TCV, main steam isolation character istics, and anticip ated transients without scram (ATWS) pump trip are al so represented fully in the models.

5.2.2.2.2 System Design

The overpressure protection system must ac commodate the most se vere pressurization transient. There are two major transients, the closure of a ll MSIVs and a turbine generator trip with a coincident failure of the turbine steam bypass system valves, that represent the most severe abnormal operational transients resulting in a nuclear system pressure rise. The evaluation of transient behavior with final pl ant configuration has s hown that the isolation valve closure is slightly more severe when credit is taken onl y for indirect derived scrams; therefore, it is used as the overpressure protection basis event and shown in Figure 5.2-2 . Table 5.2-5 lists the sequence of events of the vari ous systems assumed to operate during the main steam line isolation closure with flux scram event.

Compliance to ASME Code overpressure protec tion requirements for in troduction of GNF2 fuel has been conservatively demonstrated fo r the limiting overpressu re event. The GE thermal-hydraulic and nuclear coupled transient code TR ACG (References 5.2-7 and 5.2-8) was used to obtain system res ponse and peak vessel pressure. The setpoints ar e listed in Table 5.2-3. The evaluation, based on r eactor operation at 100% of upr ated power, end-of-cycle nuclear dynamic parameters, an initial dome pr essure of 1035 psia (nominal uprated dome

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 5.2-5 pressure), six SRVs with lowest safety setpoints out of servi ce, and SRV opening pressures at 3% above nominal setpoint values resulted in a maximum reactor pr essure of 1311 psig.

The scram reactivity curve is shown in Figure 5.2-2 . 5.2.2.2.3 Evaluation of Results

5.2.2.2.3.1 Safety Valve Capa city. The required SRV capacity is determined by analyzing the pressure rise from an MSIV closure with fl ux scram transient. The plant is assumed to be operating at the turbine-generato r design conditions at a nominal vessel dome pressure of 1035 psia. The analysis hypothetically assumes the failure of the direct MSIV position scram. The reactor is shut down by the backup, high ne utron flux scram. For the analysis, the spring-action safety valve setpoi nts used are in the range of 1236 to 1256 psia. The TRACG analysis indicates that the design valve capacity is capable of mainta ining adequate margin below the peak ASME Code allowable pre ssure in the nuclear system (1375 psig). Figure 5.2-2 shows the result of the TRACG anal ysis. The sequen ce of events in Table 5.2-5 , assumed in these analyses, were investigated to meet code requirements and to evaluate the pressure relief system exclusively.

Under Section III of the ASME B&PV Code, credit can be allowed for a scram from the reactor protection system. In addition, credit is also taken for the protection circuits which are

indirectly derived when determ ining the required SRV capacity.

The backup reactor high neutron flux scram is conservatively applied as a design basis in determining the required capacity of the pressure relieving dual purpose SRVs. Application of the direct position scrams in the design basis c ould be used since they qualify as acceptable pressure protection devices when determining the required SRV capacity of nuclear vessels under the provisions of the ASME Code. The SRVs are operated in a relief mode (pneumatically) at setpoints lower than those specified under the sa fety function. This ensures sufficient margin between anticipated relief mode closing pr essures and valve spring forces for proper seating of the valves.

The typical parametric relationship between peak vessel (bottom) pressure and SRV capacity for the MSIV transient with high flux scram is described in Figure 5.2-3 . Also shown in Figure 5.2-3 is the peak vessel (bottom) pressure for position scram with 18-valve capacity. Pressures shown for flux scram will result only with multiple fa ilure in the redundant direct scram system.

The typical time response of the vessel pressu re to the MSIV transi ent with flux scram is illustrated in Figure 5.2-4 . This shows that the pressure at the vessel bottom exceeds 1250 psig for less than 7 sec and do es not reach the limit of 1375 psig. COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-029 5.2-6 5.2.2.2.3.2 Pressure Drop in Inlet and Discharge. Pressure drop in the piping from the reactor vessel to the valves is taken into account in calculati ng the maximum vessel pressures.

Pressure drop in the discharge piping to the suppression pool is limited by proper discharge line sizing to prevent back-p ressure on each SRV from exceed ing 40% of the valve inlet pressure, thus ensuring choked flow in the valve orifice and no reduction of valve capacity due to the discharge piping. Each SRV has its own separate discharge line. 5.2.2.2.3.3 Reload Specific Confirmatory Analysis. The calculated vessel pressure for MSIV inadvertent closure may be dependent upon the fuel design and core loading pattern. Compliance with the ASME upset limit is demons trated by cycle-dependent analysis just prior to the operation of that cycle. The results are reported in Supplem ental Reload Licensing Report (Reference 5.2-11). 5.2.2.3 Piping and Instrumentation Diagrams

See Figure 5.2-5 which shows the schematic location and number of pressure-relieving devices. The schematic arrangement of the SRVs is shown in Figures 5.2-6 and 5.2-7. 5.2.2.4 Equipment and Component Description

5.2.2.4.1 Description

The nuclear pressure relief system consists of SRVs located on the main steam lines between the reactor vessel and the first isol ation valve within the drywell.

Chapter 15 discusses the events which are expected to activate the primary system SRVs. The chapter also summarizes the number of valves e xpected to operate during the initial blowdown of the valves and the expected duration of this first blowdown. For several of the events it is expected that the lowest set SRV will reopen and reclose as gene rated heat drops into the decay heat characteristics. The pressure increase and relief cycl e will continue with lower frequency and shorter relief discharges as the decay heat drops off and until such time as the residual heat removal (RHR) system can dissipat e this heat. The duration of each relief discharge should, in most cases, be less th an 30 sec. Remote manual actuation of the valves from the control room is recommended to minimize the total number of these discharges, with the intent of achieving extended valve seat li fe and reducing cha llenges to the SRV.

A schematic of the main SRV is shown in Figure 5.2-8 . It is opened by e ither of two modes of operation:

a. The spring mode of operation which c onsists of direct action of the steam pressure against a spring-loaded disk that will pop open when the valve inlet

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-7 pressure force exceeds the spring force. Figure 5.2-9 depicts typical valve lift versus opening time characteristics; and

b. The power-actuated mode of operation which consists of using an auxiliary actuating device consisting of a pneumatic piston/cylinder and mechanical

linkage assembly which opens the valve by overcoming the spring force, even with valve inlet pressure equal to zero psig.

The pneumatic operator is so arra nged that if it malfunctions it will not prevent the valve disk from lifting if steam inlet pressure reaches the spring lift set pressure.

For overpressure SRV operation (self-actuated or spring lift mode), the spring load establishes the safety valve opening setpoint pressure and is set to ope n at setpoints designated in Table 5.2-3. In accordance with the ASME Code, full lift in this mode of operation is attained at a pressure not greater than 3% above the setpoint.

To prevent backpressure from af fecting the spring lift setpoint, each valve is provided with a bellows and balancing piston to c ounteract the effects of any stat ic backpressure which may be present in the discharge line be fore the valve is opened to discharge steam. The bellows isolates steam in the valve disc harge chamber from the valve's internals. If the bellows fails, the balancing piston serves as a functional backup by presenting an effective pi ston area to the back pressure equal to the valve seat area, thus balancing it so there is essentially no net back pressure effect on the setpoint ( Figure 5.2-8 ). The safety function of the SRV is a backup to the relief function described below. The spring-loaded valves are desi gned and constructed in accordan ce with ASME III, 1971 Edition, Paragraph NB-7640, as safety valves with auxiliary actuating devices.

Each SRV is provided with its own pneumatic accumulator and inlet check valve to provide high assurance the valve will actuate in the power-actuated (relief) mode when its pneumatic solenoid valve is energized. The pneumatic accumulator has su fficient capacity to provide one SRV actuation at approximate ly 1000 psig valve inlet pressure. Although no credit is taken under ASME Code Section III for overpressure protec tion by the SRVs in their power-actuated mode, power actuation of the SRV will limit peak reactor pressure in the majority of overpressure transients. Safety/relief valve actuation in the relief mode is initiated by pr essure switches (one per valve) which sense reactor steam space pressure at lower values than the spring mode inlet steam opening pressure. The pressure switches initia te the opening of the SRVs by energizing the pneumatic solenoids (one per valve) at the relief setpoints designated in Table 5.2-3 . When the solenoid is actuated, the delay time, maximum elapsed time between receiving the overpressure signal at the valve actuator and the actual start of valve motion, will not exceed

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-98-113 5.2-8 0.1 sec. The maximum full stroke opening time will not exceed 0.15 sec with 1000 psig steam at the valve inlet.

The SRVs can be operated in th e power-actuated mode by remote-manual controls from the main control room.

The SRVs are designed to operate to the exte nt required for overpressu re protection in the following accident environments:

a. 340°F for a 3-hr period, at drywell design pressure, b. 320°F for an additional 3-hr period, at drywell design pressure, c. 250°F for an additional 18-hr peri od, at 25 psig drywell pressure, and

d. 200°F during the next 99 days at 20 psig drywell pressure.

The automatic depressurization sy stem (ADS) utilizes selected SR Vs for depressurization of the reactor (see Section 6.3). Each of the SRVs utilized for automatic depressuri zation is equipped with an air accumulator and check valve arrangement. These accumulators ensure that the

valves can be held open followi ng failure of the air supply to the accumulators. The designed pneumatic supply to the ADS accumulator is such that, following a failure of the safety-related pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at 70% of design pressure. For a discussion of the noninterruptible air supply to the ADS valves, see Section 9.3.1. Three ADS SRVs and their associ ated solenoid pilot valves (SPV) are qualified for the full post-LOCA time frame for long-term c ooling. All other SRVs and their SPVs are qualified for 24 hr post-LOCA to provide overpressure protection capability.

The valve position indication (VPI) and the tailpipe temperature indication systems are discussed in Section 7.5.2. Each SRV discharges steam through a discharge line to a point below the minimum water level in the suppression pool. Safety/relief valve discharge line piping from the SRV to the suppression pool consists of two parts. The first part is attached at one end to the SRV and at

its other end penetrates and is welded to a 28-in. downcomer (considered a pipe anchor). The main steam piping, including this portion of the SRV discharge piping, is analyzed as a complete system. This portion of the SRV discharge line is cl assified as Quality Group C and Seismic Category I down to the jet deflector plate just above the diaphragm floor (through which it is rigidly guided) and Quality Group B and Seismic Cate gory I from the jet deflector plate to the downcomer.

The second part of the SRV discharge piping extends from the downcomer (anchor) to the suppression pool. Because of the anchor on this part of the line, it is physically decoupled from the main steam header and is, therefore, analyzed as a separate piping system. In analyzing this part of the discharge piping in accordance with the requirements of Quality Group B, the following load combination was considered as a minimum:

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-9 a. Pressure and temperature, b. Dead weight, and

c. Fluid dynamic loads due to SRV operation.

As a part of the preoperational and startup testing of the main steam lines, movement of the SRV discharge lines were inspected w ith negligible vibration observed.

The SRV discharge piping is designed to limit va lve outlet pressure to 40% of maximum valve inlet pressure with the valve open. Water in the line more than a few feet above suppression pool water level would cause excess ive pressure at the valve disc harge when the valve is again opened. For this reason, re dundant 10-in. vacuum relief va lves are provided on each SRV discharge line to prevent drawing an excessive amount of water up into the line as a result of steam condensation following termina tion of relief operation. Each vacuum relief valve pair is situated with the valves in parallel, the discharge being routed to a common tee in the SRV discharge line.

The nuclear pressure relief syst em automatically depressurizes the nuclear system sufficiently to permit the LPCI and LPCS systems to operate as a backup for the HPCS system. Further descriptions of the operation of the automatic depressurization feature are found in Sections 6.3 and 7.3.1.1.1 . 5.2.2.4.2 Desi gn Parameters

Table 5.2-6 lists design temperature, pressure, and maximum test pressure for the RCPB components. The specified opera ting transients for components within the RCPB are given in

Section 3.9. Refer to Section 3.7 for discussion of the input criteria for design of Seismic Category I structures, systems, and components.

A summary of the number of cycles for transients used in design and fatigue analysis is listed in Table 3.9-1 and categorized under the appropriat e design condition (i.e., normal, upset, emergency, and faulted).

The design requirements establishe d to protect the principal com ponents of the reactor coolant system against environmental ef fects are discussed in Section 3.11. 5.2.2.4.2.1 Safety/Relief Valve . The discharge area of the valve is 16.117 in. 2 and the coefficient of discharge KD is equal to 0.966, as certified by the National Board of Boiler and Pressure Vessel Inspectors.

The design pressure and temperature of the va lve inlet and outlet are 1250 psig at 575°F and 625 psig at 500°F, respectively.

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-10 The valves have been designe d to achieve the maximum pr actical number of actuations consistent with state-of-the-art technology. Cyclic testing has de monstrated that the valves are capable of at least 60 actuation cy cles between required maintenance. See Figure 5.2-8 for a schematic cross section of the valve.

5.2.2.5 Mounting of Pressure Relief Devices

The pressure relief devices are located on the main steam piping headers. The mounting consists of a special contour nozzle and an oversized flange connection. This provides a high

integrity connection that accounts for the thru st, bending, and torsiona l loadings which the main steam pipe and relief valve discharge pipe are subjected to.

In no case will allowable valve flange loads be exceeded nor will the stress at a ny point in the piping exceed code allowables for any specified combination of loads. The design criteria and

analysis methods for considering loads due to SRV discharge is contained in Section 3.9.3.3. 5.2.2.6 Applicable C odes and Classification

The RCPB overpressure protection system is designed to satisfy the requirements of Section III, Subsection NB, of the ASME B& PV Code. The gene ral requirements for protection against overpressure as given NB-7120 of Section III of the code recognize that RCPB overpressure protection is one function of the reactor protective systems and allows the

integration of pressure relief devices with the protective syst ems of the nuclear reactor. Hence, credit is taken for the scram protective system as a complement ary pressure protection device.

5.2.2.7 Material Specification

Pressure retaining components of SRVs are constructed only from ASME Section III, Class 1 designated materials.

5.2.2.8 Process Instrumentation

Overpressure protection process instru mentation is listed in Table 1 of Figure 5.2-5 and shown in Figure 10.3-2 . 5.2.2.9 System Reliability

Overpressure protection system reliability is princi pally a function of the SRVs in their spring-opening mode of ope ration. No credit is taken in th e ASME Code Section III required overpressure protection report for power actuation of the SRVs to provide protection against overpressure.

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 5.2-11 Section 5.2.2.10 discusses the inspection and testing c onducted to ensure hi gh SRV reliability. As demonstrated by the extensive qualification and production testing, the valves are very reliable.

In addition to SRV testing to ensure high SRV quality, an extensive in-depth quality assurance program was followed in the manufacture and production testing of the valves to provide assurance of high quality.

A significant amount of BWR operating experience was been accumu lated on this type of SRV, approximately 150 individual valv e years, only one "stuck-open relief valve" had occurred. This was due to an air solenoid valve sticking open after it was deener gized, thus holding the SRV open in the power-actuated mode. Proper ma intenance procedures ar e incorporated into the instruction manual to preclude recurrence.

This type of SRV has demonstrated good inservi ce operability similar to that demonstrated by the qualification test program.

In summary, this type of SRV has demonstrated excellent reliability , both in qualification testing and in act ual BWR operation.

5.2.2.10 Inspection and Testing

To verify the design of the SRV used will reliably operate, several SRVs were subjected to qualification test programs. These qualification test programs de monstrated the design of the valve is capable of performi ng its overpressure protection function under normal, upset, emergency, and faulted c onditions and its designated mechanical motion(s) to fulfill its safety function to shut down the plant or mitigate the c onsequence of a postulated event. To ensure that valves to be installed ar e operable, each valve is manuf actured, inspected, and production tested in accordance with quality control procedures to veri fy compliance with both ASME Code and operability assura nce acceptance criteria.

The SRV design used at CGS su ccessfully complete d the following qua lification tests:

a. Life Cycle Test

Following the prequalification production tests, each modified SRV was then subjected to life cycle qua lification tests with satu rated steam conditions, in accordance with GE specification 22A6595. This included approximately 300 relief (power) and safety (pressur e) actuations to demonstrate and characterize each valve for acceptable BWR service. Tests parameters included:

1. Seat tightness/leakage characteristics, COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-12 2. Set pressure,

3. Opening and closing response time,

4. Blowdown,

5. Safety/relief valve lift-achieving rated flow capacity lift during each activation,

6. Safety/relief valve reclosure without chattering, disc oscillation, or sticking open, and

7. Capability to open without inlet steam when activated on demand.

Test conditions were varied according to facility capability to ensure valve operability across the design limits to which the SRV ma y be subjected while in service. These included temperature, pr essure ramp rates, pneumatic operating pressure, solenoid voltage, inlet pr essure, and the dynamically imposed backpressure.

Test results indicate essen tially zero leakage for both the relief (power) and safety (pressure) modes of SRV opera tion. All valves demonstrated seat-tightness capability to meet the 20 lb/hr specific ation limit under saturated steam conditions. Each valve demons trated safety actuation within the nameplate value plus 1% at a confidence level of 0.95. The response is also linear with ambient temperature in the negative direction; i.e., at temperatures

above 135°F the actual pop pressure is lo wer than the namepl ate value. The temperature correction value is 0.2 psi/ °F for this SRV. Set pressure is

independent of ramp rate variance. Res ponse of the SRV is directly related to the effective differential pr essure force acting to open the SRV; therefore, outlet static pressure at th e exit can be accurately accounted for. Opening times were as follo ws during the test set up: Safety actuation time - 0.020 t 0.30 sec Relief actuation time - 0.020 t 0.15 sec Actual installation times could result in a delay time >0.10 sec due to wire lengths and other non-SRV wire losses. Closing times were:

Safety actuation - none, contro lled by blowdown requirement. COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-13 Relief actuation - time to deenergize solenoid < 0.90 sec disc travel after solenoid < 1.50 sec was deenergized Blowdown within the require d range of 2% to 11% wa s demonstrated. Each SRV is adjusted by full flow testing for acceptable blowdown.

Qualification test results demonstrate the SRV will open to rated capacity lift in either the relief or safety modes of operation when actuated. The SRV reclosure was demonstrated th roughout the qualifica tion tests without sticking, chatter, or disc oscillation during the closure stroke. When inlet pressure was increased to repressurize to the set pressure, the SRV reactuated to the full open position. The modified SRV w ill open to its full rated capacity lift position when operated in the relief mode with the inlet pressure at zero psig, thus demonstrating its em ergency operability capability. Six SRVs were included in this life cy cle qualification test program. Test anomalies corrected during th is demonstration do not i nvalidate the adequacy of the test results obtained; the finalized modified SRV design is considered acceptable for BWR main steam applications.

b. Seismic and Moment Transfer Test One valve specimen was subjected to operating basis earthquake (OBE) and safe shutdown earthquake (SSE) accelerations and flange d end connection moment loading with valve inlet pr essurized with saturated st eam. Valve operability was demonstrated during and afte r application of loading. Maximum test loads were 8 x 105 in. pound moment at valve inlet and 6 x 10 5 in. pound moment at valve outlet. Seismic accelerations of 5.

0g horizontal and 4.2g vertical are the established maximum for a ny frequency between 5 to 200 Hz unless otherwise specified for a smaller frequency range.

c. Emergency Environmen tal Qualification Test

The solenoid valves and the pneumatic ac tuator assembly were subjected to a test sequence as follows:

1. Thermal aging equivalent to 343°F for 96 hours,

2. Radiation aging to greater than or equal to 30 x 10 6 rads, COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-14 3. Mechanical aging for 10 00 cycles (500 per solenoid),

4. Seismic testing as de scribed in item b. above,

5. Exposure to emergency environmental conditions of 340°F at 65 psig decreasing to 250°F at 25 psig for 4 days, and

6. Separate solenoid valve test 340°F, 3 hrs, 45 psig 320°F, 3 hrs, 45 psig 250°F, 18 hrs, 25 psig 200°F, 99 days, 20 psig.

Operability of the actuat or assembly was demons trated during and after exposure to the emergency environment.

d. Low-Pressure Water Discharge Test

Low-pressure water discharge tests as described and reported in GE Report NEDE-24988 to satisfy the requi rements of II.D.1 of NUREG-0737.

Test reports/records of the above qualific ation tests are available for inspection. Each SRV is production tested at the vendor's shop to ensure , by demonstration, each SRV manufactured will reliably perfor m its required function(s). Th e SRV production test consist of

a. Inlet and outlet hydrostatic tests at sp ecified conditions to satisfy ASME Code requirements,

b. Emergency operability test to verify capability of actuator to open the SRV without inlet pressure applied to the valve,

c. Actuator system leakage test to assure pneumatic leaktightness is compatible with plant air system make-up requirements,

d. Nitrogen set pressure and leakage test to rough adjust setpoint and ensure seat quality of seating surface prior to steam tests (optional),

e. Set pressure and blowdown test under thermally stabilized and saturated steam conditions,

f. Response time tests to verify relie f opening and closing times under thermally stabilized and saturate d steam conditions, and COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 5.2-15 g. Steam leakage tests to verify leaktightness.

The valves are normally installed as received from the factory providing there is no apparent evidence of damage during transportation, handling, and storage. For valves stored longer than one year, it is recommended they be recertified to ensure operability. The GE equipment specification requires certification from the va lve manufacturer that de sign and performance requirements have been met.

Testing to satisfy the ASME Code requirements is normally perfor med in situ. Testing can be performed locally or remotely. The local test method is conducte d using a test fixture that is temporarily mounted on the SRV and then removed on completion of the test. Remote testing is accomplished using a permanently mounted pneumatic head assembly th at is controlled by a remote computer. This method does not require any pe rsonnel entry into the containment for the purpose of testing.

During the startup test program, all of the main steam SRVs were tested for proper operation. These tests include a documentation review to ensure that the valves were properly installed, properly handled during transporta tion, storage, and installation, and were properly maintained as to cleanliness prior to performance of any te sts. In addition, the air accumulator capacity, SRV nameplate set pressure, and capacity were compared with the system design documentation for compliance.

Actual mechanical tests incl uded an operability check of th e SRV discharge line vacuum breakers, actuation of the individual SRVs by each remote manual switch (main control room

and/or remote shutdown panel) to demonstrate full lift, sm ooth stroke, and opening time characteristics, actuation of each SRV in the relief mode by stimulating its pressure switch, and a demonstration that each SRV accumulator (ADS and/or normal) has sufficient capacity to operate the SRV air actuator as required by the system design documentation. Finally, the ADS logic was fully tested for proper performa nce. Note that only the air actuator was exercised during many of the startup tests. This minimizes valve wear and unnecessary maintenance.

During the power ascension phase of the st artup test program, each SRV was manually actuated at approximately 250 ps ig reactor pressure to demonstrate valve operability. At approximately 50% power each SRV was actuated a second time to measure discharge capacity and to demonstrate that no blockage in the SRV di scharge line existed.

At commercial turnover the scope of SRV testing was governed by ASME B&PV Code Section XI, Article IWV and the Technical Specifications. This article specifies the rules and requirements for inservice testing to verify operational readine ss of the SRVs. This code section is applied to both AD S and non-ADS valves alike. Supplemental tests of the ADS COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 5.2-16 valves each operating cycle are required by the Technical Specific ations. Applying Section XI, the SRV test schedule (i n part) is as follows:

Time Period Number of Total Elapsed (Cycle) Valves Tested Tested Time (years)

1 6 6 1.5 2 4 10 2.5 3 4 14 3.5 4 4 18 4.5 5 4 4 1.0 6 4 8 2.0 7 4 12 3.0 8 4 16 4.0 9 2 18 5.0 Note that following the return to service of th e testing SRVs, an operability demonstration will be performed in compliance with Section XI, Article IWV-3200.

This combination of the start up test program, Technical Spec ifications surv eillance, and inservice inspection testing satis fies industry standards for SR V operability demonstrations. Energy Northwest participated in the BW R Owners' Group for TMI concerns on SRV reliability. The final test pr ogram description was submitted to the NRC by the BWR Owners' Group and is endorsed by Energy Northwest.

5.2.3 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS

5.2.3.1 Material Specifications

Table 5.2-7 lists the principal pressure retaining materials and the appropriate material specifications for the RCPB components.

5.2.3.2 Compatibility with Reactor Coolant 5.2.3.2.1 Pressurized Water Reacto r Chemistry of Reactor Coolant Not applicable to BWRs.

5.2.3.2.2 Boiling Water Reactor Chemistry of Reactor Coolant

Regulatory Guide 1.56 compliance is addressed in Section 1.8. COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-10-010 5.2-17 Reactor feedwater (RFW) quality is maintained in accordance with the Licensee Controlled Specifications (LCS) and as described in Section 10.4.6. Materials in the primary system are primarily austenitic stainles s steel and Zircaloy cladding. The reactor water chemistry limits are established to provide an environment favorable to these materials. Limits are placed on conductivity and chloride c oncentrations. Conductivity is limited because it can be continuously and relia bly measured and gives an indication of abnormal conditions and the presence of unusual ma terials in the coolant. Chloride limits are specified to prevent stress corrosion cracking of stainless stee

l. For further information, see Reference 5.2-2. Periodically an On-Line NobleChem application will be perfor med to create a catalytic layering of the noble metal platinum to reduce the hydrogen injection rate required to achieve a low electrochemical corrosion po tential (ECP). The low ECP achieves intergranular stress corrosion cracking (IGSCC) and irradiation assisted stress corrosion cracking (IASCC) protection while minimizing the effects of high dose rates attributed to regular hydrogen injection rates.

When conductivity is in its normal range, pH, chloride, and other impurities affecting conductivity will also be within their normal ra nge. When conductivity becomes abnormal, chloride measurements are made to determine whether or not they are also out of their normal operating values. Conduc tivity could be high due to the presence of a neutral salt, which would not have an effect on pH or chloride. In such a case, high cond uctivity alone is not a cause for shutdown. In some types of water-cooled reactors, conductivities are high because of the purposeful use of additives . In BWRs, however, where no additives which significantly affect conductivity are used a nd where near neutral pH is ma intained, conductiv ity provides a good and prompt measure of the quality of the reactor water. A depleted zinc oxide (DZO) skid is connected to the RFW system which maintains DZO concentration in reactor water. This has a small effect on conductivity. Significant changes in conductivity provide the operator with a warning mechanism so he can investigate and reme dy the condition before reactor water limits are reached. Methods available to the operator for correcting the off-standard condition include ope ration of the reactor cleanup sy stem, reducing the input of impurities, and placing the reactor in the cold shutdown condition. The major benefit of cold shutdown is to reduce the temperature-depende nt corrosion rates and provide time for the cleanup system to reestablish the purity of the reactor coolant.

During normal plant operation, the dynamic oxygen equilibrium, in the reactor vessel water phase, established by steam-gas stripping and radiol ytic formation (principally) rates, corresponds to a nominal value of approximately 200 ppb (0.2 ppm) of oxygen at rated operating conditions. Slight vari ations around this value have been observed as a result of differences in neutron fl ux density, core-flow, and r ecirculation flow rate.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-02-046, 03-069 5.2-18 A reactor water cleanup (RWCU) system is provided for removal of feedwater input impurities plus corrosion and fission products originating from primary sy stem components. The cleanup process consists of filtration a nd ion exchange and serves to maintain a high level of water purity in the reactor coolant.

Additional water input to the reactor vessel or iginates from the control rod drive (CRD) cooling water. The CRD water is of feedwate r quality. Additional filt ration of the CRD water to remove insoluble corrosion products takes place within the CRD system prior to entering the drive mechanisms and reactor vessel. An iron addition system is used to inject an ir on oxalate/demineralized water solution into the suction line of the condensate booster pumps. The injection flow rate is extremely small when compared to condensate system fl ow rate. This iron injection system will have a negligible affect on the oxygen concentration in the RFW.

A hydrogen injection system is installed across the condensate booster pumps. This hydrogen injection system will have a negligible affect on the oxyge n concentration in the RFW.

No other inputs of water or sources of oxygen are present during normal plant operation. During plant conditions other than normal ope ration, additional inputs and mechanisms are present as reactor coolant water coul d contain up to 8 ppm dissolved oxygen.

Conductivity of the primary coolant is continuous ly monitored with instruments connected to the reactor water recirculation loop and the RWCU system inlet. The effluent from the RWCU system is also monitored for conductivity on a continuous basis. These measurements provide reasonable surveillance of the reactor coolant.

Grab sample points are provide d at the locations shown in Table 5.2-8, for special measurements such as pH, oxygen, ch loride, and radiochemical content.

The relationship of chloride concentration to specific conduc tance measured at 25°C for chloride compounds such as sodium chloride and hydrochloric acid can be calculated (see Figure 5.2-10). Values for these compounds essentially bracket values of other common chloride salts or mixtures at the same chloride concentration. Surveillance requirements are based on these relationships. In addition to this program, limits, monitoring, and sampling requirements are established for the condensate, condensate treatment, and feedwa ter system. Thus, a total plant water quality surveillance program is established providing assurance that o ff specification conditions will quickly be detected and corrected.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-023 5.2-19 The sampling frequency establis hed for primary coolant at no rmal conductivity levels is adequate for instrument checks and routine audit purposes. When specific conductance increases and higher chloride c oncentrations are possible or when continuous conductivity monitoring is unavailable, sampling frequency is increased according to LCS. The primary coolant conductivity monitoring instrumentation, ranges, sensor, and indicator locations are shown in Table 5.2-8. The sampling is coordinated in a reactor sample station especially designed with constant temperature control and samp le conditioning a nd flow control equipment. Water Purity During a Condensate Leakage

Due to improved water quality limits, any appreci able circulating water inleakage would result in water chemistry conditions outside acceptable limits and require action(s) to return the water quality to within applicable limits for continued plant operation.

5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant

The materials of construction exposed to the reactor coolan t consist of the following:

a. Solution annealed austenitic stainless st eels (both wrought and cast) types 304, 304L, 316 and 316L,

b. Nickel base alloys -

Inconel 600 and Inconel X750 and Inconel 82 and 182 weld metal,

c. Carbon steel and low alloy steel,

d. Some 400 series martens itic stainless steel (all tempered at a minimum of 1100°F), and

e. Cobalt, chromium, nickel, and ir on based alloy hardfacing material

All of these materials of cons truction are generally resistant to stress corrosion in the BWR coolant. General corrosion on all materials, except carbon and low alloy steel, is negligible. Conservative corrosion allowances are provided for all exposed surfaces of carbon and low alloy steels.

Contaminants in the reactor coolant are cont rolled to very low limits by the reactor water quality specifications. No detrimen tal effects will occur on any of the materials from allowable contaminant levels in the high purity reactor coolant. Radiolytic products in the BWR have no adverse effects on the c onstruction materials.

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-10-010 5.2-20 The recirculation system piping and normally flooded sec tions of the reactor vessel are coated as needed utilizing the GEH On-Line NobleChem application process with a microscopic layer of noble metals. This coating serves to prevent as well as mitigate IGSCC by eliminating the dissolved oxygen at the meta l surface when an amount of hydr ogen gas is added in a molar ratio of greater than 2 to 1 hydrogen to oxygen.

Type 304 stainless steel has been replaced with type 316L stainless steel in the recirculation inlet line safe ends. The bypass lines and the CR D hydraulic return line were eliminated and nozzles capped. The core spra y lines are fabricat ed of carbon steel. The piping components that do not comply with the requirements of the Generic Letter 88-01 (GL 88-01), NRC Position on IGSCC BWR austenitic Stainless Steel Piping, will be subjected to the augmented inspection requirements of GL 88-01 as modified in Energy Northwest response (see Section 5.2.4 and Tables 5.2-9 and 5.2-10). 5.2.3.2.4 Compatibility of Cons truction Materials with Exte rnal Insulation and Reactor Coolant The materials of cons truction exposed to external insulation are

a. Solution annealed austenitic stainless steels (e

.g., types 304, 304L, and 316), and

b. Carbon and low alloy steel.

Two types of external insulation are used. Reflective metal in sulation used does not contribute to any surface contamination and has no effect on construction materials. The fibrous

insulation used meets the requirements of Regulat ory Guide 1.36.

DZO and iron are additives in the BWR coolant. Leakage would expo se materials to high purity demineralized water, DZO, and iron. Exposure to demine ralized water, DZO, and iron would cause no detrimental effects.

5.2.3.3 Fabrication and Proce ssing of Ferritic Materials a nd Austenitic Stainless Steels

Fracture toughness requirements for the ferritic material s used for piping and valves (no ferritic pumps in RCPB) of the RCPB were as follows:

Safety/relief valves were exempted from fracture toughness requirements because Section III of the 1971 ASME B&PV Code did not require impact testing on valves with inlet connections of 6 in. or less nominal pipe size. Main steam isolation valves were also exempted because the mandatory ASME Code, 1971 Edition through the Winter 1971 Addenda, required brittle fracture testing on ferritic pressure

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-21 boundary components only if re quired in the Design Specificati on. The Design Specification did not require brittle fracture testing because the system temperature is in excess of 250°F at pressure above 20% of the desi gn pressure. Material informa tion pertaining to the MSIVs is contained in Table 5.2-11 . Main steam piping was tested in accordance with and met the fr acture toughness requirements of Paragraph NB-230 0 of the 1972 Summer Addenda to ASME Code, Section III.

The ferritic pressure boundary material of the RPV was qua lified by impact testing in accordance with the 1971 Edition of Section III ASME Code and Addenda to and including the Summer 1971 Addenda.

Austenitic stainless steels with a yield strength greater than 90,000 psi are not used.

The degree of compliance with Regulatory Guides 1.31, 1.34, 1.37, 1.43, 1.44, 1.50, 1.66, and 1.71 is addressed in Section 1.8. 5.2.4 INSERVICE INSPECTION AND TESTING OF THE REACTOR COOLANT PRESSURE BOUNDARY

The structural integrity of AS ME Code Class 1, 2, and 3 components are maintained as required by the ISI program in accordance with 10 CFR 50.55a. With the structural integrity of any component not co nforming to the above re quirements, the structur al integrity will be restored to within its limits or the affected component will be isolated. For Class 1 components, this isolation will be accomplished prior to increasing reactor coolant system temperature more than 50 °F above the minimum temperature required by nil-ductility transition (NDT) considerations. For Class 2 components, isolation will be accomplished prior to increasing reactor coolant system temperature above 200 °F. Inservice Inspections are perf ormed in accordance with the requirements of 10 CFR 50.55a subparagraph (g) as described in th e Inservice Inspect ion Program Plan.

5.2.4.1 System Boundary Subject to Inspection

The system boundary subject to in spection is defined in the Inservice Inspection Program Plan. The RPV was examined prior to service in accordance with the requirements of the 1974 Edition of the ASME B&PV Code, Section X I, including the Summer 1975 Addenda. All Class 1 piping, pumps, and valves were examined prior to serv ice in accordance with the requirements of the 1974 Edition of the ASME B&PV Code, Section XI, with Addenda through Summer 1975, including Appendix III from the Winter 1975 Addenda.

The design of the RPV shield wall and external inse rvice inspection system was completed prior to the promulgation of amendments to 10 CFR 50.55a which require the upgrading of the COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-22 utility's inservice inspection code commitment for examina tions subsequent to the baseline examination. The design has allowed some additional access for inspections and coverages anticipated to be required by later codes, where possible. The result of this effort has increased the areas on the RPV available to inservice inspection (approximately 84% of the vessel weld volume is accessible) and has allowed the pipi ng examination to be upgraded to conform to the requirements of the Summer 1975 Addenda to Sec tion XI as far as practical. The preservice examination was performed on Class 1 components and piping pursuant to the requirements of the 1974 Edition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda for both the RPV and associated piping, pumps, and va lves. It is described in the Preservice Inspection Program Plan (Reference 5.2-6). 5.2.4.2 Arrangement of Systems and Components to Provide Accessibility

Access for the purpose of inservic e inspection is defined as the design of the plant with the proper clearances for exami nation personnel and/or equipment to perform inservice examinations. The RCPB for the RPV is designed to provide compliance with the provisions for access as required by Subarticle IWA-1500 of the 1974 Edition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda. The RCPB for piping, pumps, and valves is designed to provide compliance with the provis ions for access as required by Subarticle IWA-1500 of the 1974 Edition of the ASME B& PV Code, Section XI, with addenda through Summer 1975.

Access is provided for volumetr ic examination of the pressure containing welds from the external surfaces of components and piping by means of remo vable insulation, removable shielding, and permanent tracks for remote inspection devices in areas where personnel access is restricted. The provisions for suitable access for inservice inspection examinations minimizes the time required for th ese inspections and, hence, redu ces the amount of radiation exposure to both plant and examination personnel. Working pla tforms are provided at most strategic locations in the plant which permit re ady access to those area s of the RCPB which are designated as inspection points in the inserv ice inspection program. Temporary scaffolding will be used as required to gain access for examination.

Energy Northwest retained Southwest Research Institute to provide an independent assessment as to the suitability of plant access provisions for inservice inspection. This overview provided for identification of design modification or inspection technique development needs to ensure maximum practical complian ce with code requirements.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-23 5.2.4.2.1 Reactor Pressure Vessel

Access for inspection of the RPV is as follows:

a. Access to the exterior su rface of the RPV for inservice inspection is provided by removable insulation and shield plugs.

Hinged shield wall plugs around nozzles are used to gain access for nozzle inspection. A minimum annular space of 8.25 in. is provided between the vessel exterior surfa ce and the insulation interior surface to permit the insertion of remotely operated inspection devices between the insulation and the reactor vessel. Th e RPV nozzle insulation is removable. This design allows sufficient clearances for the mounting of a nozzle-to-shell examination device from tracks located either at the nozzle safe-end or at the pipe area. Examina tions that can be pe rformed from these tracks include the required coverage of the nozzle-to-she ll welds and depending on technique, could provid e examination coverage of the nozzle inner radius section and nozzle-to-safe-end weld. Access, geometry and radiation level considerations will determine those nozzl es scheduled for manual examination.

b. The vessel flange area and vessel closure head can be examined during refueling outages using m anual ultrasonic techniques.

With the closure head removed, access is afforded to the upper interior clad surface of the vessel by removal of a steam dryer and steam separ ator assembly. Removal of these components also enables the examination of remaining internal components by remote visual techniques. The volumetric examinati on of the vessel-to-flange weld and closure head-to-fl ange weld can be performe d by applying the search units directly to the seal surface areas. The vessel-to-flange weld is also

examined from vessel shell surface.

c. The closure head is dry st ored during refueling which facilitates direct manual examination. Removable insulation allo ws examination of the head welds from the outside surface. Reactor vessel nuts and washers are removed to dry storage for examination during refueling.

Selected studs are examined during re fueling in accordance with the Inservice Inspection Program Plan.

d. Openings in the RPV support skirt are provided to permit access to the RPV bottom head for purposes of inservice examination. The examinations performed include volumetric examinations of circumferential welds, portions of the meridional welds, portions of the do llar plate longitudinal welds, and visual examination of accessible penetration welds.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-24 5.2.4.2.2 Piping, Pu mps, and Valves The physical arrangement of piping, pumps, and valves is designed to allow personnel access to welds requiring inservice inspection. Mod ifications to the initial plant design have been incorporated where practicable to provide in spection access on Class 1 piping systems. Removable insulation is provided on those piping systems requiring inspection. In addition, the placement of pipe hangers and supports with respect to t hose welds requiring inspection have been reviewed and mod ified where necessary to reduc e the amount of plant support required in these areas during inspection. Wo rking platforms are provided to facilitate servicing most of the pumps and valves. Temporar y platforms, scaffolding, and ladders will be provided to gain additional access for piping and some pump and valve examinations. An effort has been made to mini mize the number of fitting-to-fitti ng welds within the inspection boundary. Welds requiring inspecti on are located to permit ultr asonic examinations from at least one side, but where compone nt geometries permit, access fr om both sides of the weld is provided. The surface of welds within the inspection boundary are prepared to permit effective ultrasonic examination.

5.2.4.3 Examination T echniques and Procedures

Examination techniques and proce dures for the preservice examination, including any special technique and procedure, met the requirements of Table IWB-2600 of the 1974 Edition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda for both the RPV and the associated piping, pump, and valve examinations. Examination techniques and procedures for inservice inspections are in accordance with the Inservice Inspection Program Plan. During plant design, an effort was m ade to upgrade the requirement for calibration standards. Where upgrading was not feasible, material of the same P series with similar acoustic characteristics were used.

5.2.4.3.1 Equipment for Inservice Inspection

Access for inservice inspection of the RPV seam welds is accomplishe d through openings in the sacrificial shield. These openings are provided at each nozzle location. Permanently installed tracks between the vessel surface and the insulation can be used for mounting remotely operated devices. Access is also provided for devices that do not require use of these tracks. Remote ultrasonic scanning equipment for examin ation of the nozzle-to-vessel welds will be supported and guided from tracks temporarily mounted on the pipe connected to the nozzle. The examination equipment will provide radial and circumferential motion to the ultrasonic transducer while rotating about the nozzle. Installation of th e equipment will be accomplished through the access openings in the sacrificial shield which are provided at each nozzle location.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-25 5.2.4.3.2 Coordination of Inspection Equipment With Access Provisions Access to areas of the plant requi ring inservice inspection is provi ded to allow use of standard equipment wherever practicable. Design in general provides for free space envelopes both radially and axially from welds to be examin ed so standard manual examination equipment may be utilized. Any special equipment or techniques used will achieve the sensitivities required by the codes.

5.2.4.3.3 Manual Examination In areas where manual ultrasoni c examination is performed, all reportable indications are recorded consistent with current inservice inspection codes in effect. Radiographic techniques may be used where ultrasonic techniques are not practical. In areas where manual surface or direct visual examinations are performed, all recordable indications will be in accordance with the Inservice Inspec tion Program Plan.

5.2.4.4 Inspection Intervals

Inspection intervals are defined in the Inservice Inspection Program Plan.

5.2.4.5 Examination Cate gories and Requirements

Examination categories and require ments for the preser vice inspection ar e defined in the Preservice Inspecti on Program Plan and closely follo w the categories and requirements specified in Tables IWB-2500 and IWB-2600 of the 1974 Edition with Addenda through Summer 1975 of the ASME B&PV Code, Section XI, for the RPV and the associated piping, pumps, and valves.

Examination categories and requirements for inse rvice inspections are in accordance with the requirements of ASME Section XI and are contained in the Inservice Inspection Program Plan.

5.2.4.6 Evaluation of Examination Results

Evaluation of results for the RPV, pump, and valve baseline examinations were conducted in accordance with Article IWB-3000 of the 1974 Ed ition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda. Evaluation of examination results for piping baseline examinations were conducted in accordance with Article IWB-3000 of the 1974 Edition of the ASME B&PV Code, Section IX, with Addenda through Winter 1975. Energy Northwest recognized that Section XI had been promulgated as an eff ective code by 10 CFR 50.55a, for the baseline examinations, only through th e Summer 1975 Addenda. However, Energy Northwest also recognized that even though the code through Summe r 1975 Addenda included evaluation criteria which could be interpreted to apply to pipi ng (Category B-J) welds, the evaluation criteria found in the Winter 1975 Adde nda clearly provides eva luation criteria which COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-26 are applicable to these welds. Energy Northwest was unaware that the NRC staff was opposed to these evaluation criteria and an ticipates that the criteria wh ich will appear in the future codes will be consistent therewith. Evaluations are performed in accordance with the Inservice Inspection Program Plan.

5.2.4.7 System Leakage and Hydrostatic Pressure Tests

The requirement for baseline hydr ostatic test for the RPV was satisfied by the hydrostatic test performed in accordance with the requirement s of ASME Section III . Similarly, the requirements for the baseline piping system leak age and hydrostatic test s were satisfied by reference to the Section III hydrostatic test report as permitted by ASME Section XI, IWA-5210(b). Subsequent hydrostatic a nd system leak tests are conduc ted to the code in effect in accordance with the Inservice Inspection Program Plan.

5.2.4.8 Inservice Inspection Commitment

All quality Group A components were examined once prior to startup in accordance with the above requirements. This pre operational examination served to satisfy the requirements of IWB-2100 of the 1974 Edition of the ASME B&PV Code, Section XI, including the Summer 1975 Addenda for the RPV and associated piping, pumps, and valves. Inservice inspection of Columbia Genera ting Station is performed in accordance with the Inservice Inspection Program Plan.

5.2.4.9 Augmented Inservice Inspection to Protect Against Postulated Piping Failures

An augmented Inservice Inspection Program Pl an has been implemented for Columbia Generating Station, on high energy

• Class 1 piping systems whic h penetrate containment for which the effects of postulated pipe breaks would be unacceptable. This program is described in the Inservice Inspection Program Plan.
• High-energy lines include those systems that, during normal plant conditions, are either in operation or maintained pressuri zed and where either the maximu m operating pressure exceeds 275 psig or maximum opera ting temperature exceeds 200

°F. If, for a particular line, the above pressure and temperature limits are not exceeded more than 2% of the time that the system is in operation, then that line is considered moderate energy and is exempt from the requirement for augmente d inservice inspection. COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-27 5.2.4.10 Augmented Inservice Inspection of Reactor Pressure Vessel Feedwater Nozzles 5.2.4.10.1 Preservi ce Examination

Energy Northwest performed a preservice inspection ultrasonic examination of the RFW nozzle inner radii, bore, and sa fe end regions as desc ribed in the Preservi ce Inspection Program Plan.

In addition, a preservice liqui d penetrant examination was perf ormed on the accessible areas of all RFW nozzle inner radius surfaces.

5.2.4.10.2 Inservice Examination

Inservice examinations of RFW nozzles are performed in accordance with the Inservice Inspection Program Plan.

5.2.4.11 Augmented Inservice Inspecti on for Intergranular Stress Corrosion Cracking Energy Northwest performed an ultrasonic examination of all Code Class 1 piping which is considered susceptible to IGSCC. The results are reported in the Preservice Inspection Summary Report (References 5.2-9 and 5.2-10). GL 88-01 weld categories and augmented insp ection requirements are described in the Inservice Inspecti on Program Plan.

5.2.4.12 ASME Section XI Repairs/Replacements

The repair or modification of N-stamped comp onents will be performed in accordance with the Edition and Addenda of ASME S ection XI defined in the Inservice Inspection Program Plan and in accordance with ASME Section III (Code Edition and Addenda to which the component was fabricated).

Deviations to the above refe renced code edition and addenda as allowed by code will be reviewed by Energy Northwest and authorized on a case-by-case basis.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-11-005 5.2-28 5.2.5 DETECTION OF LEAKAGE THROUGH REACTOR COOLANT PRESSURE BOUNDARY

5.2.5.1 Leakage Detection Methods

The nuclear boiler leak detection system consists of temperatur e, pressure, and flow sensors with associated instrumentation and alarms. This system detects, annuncia tes, and isolates (in certain cases) leakages in the following systems:

a. Main steam lines,

b. RWCU system,

c. RHR system,

d. Reactor core isolation cooling (RCIC) system,

e. Feedwater system,

f. HPCS,

g. LPCS, and

h. Coolant system within the primary containment.

Isolation and/or alarm of affe cted systems and the detection methods used are summarized in Table 5.2-12 . Small leaks (5 gpm and less) are detected by te mperature and pressure changes, drain sump pump activities, floor drain flow monitoring, an d fission product monitoring. Large leaks are also detected by changes in reactor water leve l and changes in flow rates in process lines.

The 5-gpm leakage rate is the limit on unidentified leakage. The leak detection system sensitivity and response is di scussed in Section 7.6.2.4. Compliance with Regulatory Guide 1.45 is described in Section 1.8. Table 5.2-12 summarizes the actions taken by each le akage detection function. The table shows that those systems which detect gross leakage initiate immediate auto matic isolation. The systems which are capable of detecting small leaks initiate an alarm in the control room. The operator can manually isolate the violated system or take othe r appropriate action. 5.2.5.1.1 Detection of Abnormal Leakage Within the Primary Containment Leaks within the drywell are detected by m onitoring for abnormally high-pressure and temperature within the drywell, high fillup rates of equipment and floor drain sumps, excessive

temperature difference between th e inlet and outlet cooling wate r for the drywell coolers, a decrease in the reactor vessel water level, and high levels of fission products in the drywell atmosphere. Temperatures within the drywell ar e monitored at various elevations. Also the temperature of the inlet and exit ai r to the atmosphere is monitored. Excessive temperatures in COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-29 the drywell, increased drywell drain sump flow rate, and drywell high-pressure are annunciated by alarms in the control room. Drywell high pressure and low reactor vessel water level will cause automatic primary containment isolation. In addition, low reactor vessel water level will isolate the main steam lines. The systems within the drywell share a common area; therefore, their leakage detection system s are common. Each of the leakage detection systems inside the drywell is designed with a capability of detecting le akage rates less than those established by the Technical Specifications. 5.2.5.1.2 Detection of Abnormal Leakage Outside the Primary Containment

Outside the drywell, the piping within each system monitored for leakage is in compartments or rooms, separate from other systems where feasible, so th at leakage may be detected by area temperature indications. Each leakage detecti on system discussed in the following paragraphs is designed to detect leak rates that are less than thos e established by the Technical Specifications. The method used to monito r for leakage for each RCPB component is described in Table 5.2-12 . a. Ambient and differential room ventilation temperature

A differential temperature se nsing system is installed in each room containing equipment that is part of the RCPB. These rooms are the RCIC, RHR, and the RWCU systems equipment rooms and main steam line tunnel. Temperature sensors are placed in the inlet and outlet ventilation ducts or across room boundaries. Other sensors are installed in the equi pment areas to monitor ambient temperature. A differential temperature monitor reads each set of sensors and/or ambient temperature and initiates an alarm and isolation when the temperature reaches a preset value. Annunciator and remote readouts from temperature sensors are indi cated in the control room.

Spurious isolations of systems due to a relatively sharp drop in outside ambient temperature is highly unlikely. For ex ample, the normal approximate operating differential temperature for the RHR and RCIC pump rooms is 26°F and 32°F respectively. The temperat ure elements are lo cated at the face of the supply and return ductwork in each pump room. The setpoint differential for isolation is 50°F and 55°F for RCIC and RHR to allow for heat released from a predetermined steam leak. Analysis has shown that it would take a 30°F/hr

ambient (outside) temperature decrease for about 2 hr to cause isolation. This magnitude of temperature drop is not supported historically because meteorological data for Hanford has not recorded ch anges of this magnitude.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-30 b. Reactor building sump flow measurement Instrumentation monitors and indicates the amount of leakag e into the reactor building floor drainage system. The normal leakage collected in the system consists of leakage from the RWCU and CRD systems and from other miscellaneous vents and drains.

c. Visual and audible inspection Accessible areas are inspected periodically and the temperature and flow indicators discussed above are monitored regularly as required by the Technical Specifications. Any instrument indication of abnormal leakage will be investigated.

d. Differential flow measur ement (cleanup system only)

Because of the arrangeme nt of the RWCU systems, differential flow measurement provides an accurate leakage detection method. The flow from the reactor vessel is compared w ith the flow back to the vessel. An alarm in the control room and an isolation signal are initiated when higher flow out of the reactor vessel indicates that a leak may exist.

5.2.5.2 Leak Detection Devices

a. Drywell floor drain sump measurement

The normal design leakage collected in the floor drain sump consists of leakage from the CRDs, valve flange leakage, floor drains, closed co oling water system drywell cooling unit drains, and potential valve stem leaks. The floor drain sump collects unidentified leakage. Design details are given in Section 9.3.3. b. Drywell equipment drain sump

The equipment drain sump collects only id entified leakage. This sump receives condensate drainage from pump seal leakoff and the reactor vessel head flange vent drain. Collection in excess of background leakage would indicate reactor coolant leakage. Design de tails are given in Section 9.3.3. c. Drywell air sampling

The primary containment radiation monitori ng system is used to supplement the temperature, pressure, and flow variati on method described previously to detect

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-31 leaks in the nuclear system process barrier. This system is described in Sections 11.5 and 7.6. Radiation monitors are useful as leak detection devices because of their sensitivity and rapid response to leaks. After several weeks of full power operation, a set level of b ackground radiation is established. Any sudden or unexplained increase in b ackground radiation indicat es a possible primary coolant leak within the primary containment. If an increase is noted, a comparison with other leak detection devices having a relationship to each other is made, particularly the equipment and floor drain flow rate monitors, and the reactor building sump pumps activation on high sump level. Using the flow rate monitors as a reference, the comparisons provide independent indications of a leak within the primary containment. Th is provides diversity in leak detection.

d. Reactor vessel head closure

The reactor vessel head clos ure is provided with double seals with a leak off connection between seals that is piped to the equipm ent drain sump. Leakage through the first seal is annunciated in the control room. When pressure between the seals increases, an alarm in the control room is actuated. The second seal then operates to contain the vessel pressure.

e. Reactor water recirculation pump seal

Reactor water recirculation pump seal leaks are detected by monitoring the drain line. Leakage, indicated by high flow rate, alarms in the control room. Leakage is piped to th e equipment drain tank.

f. Safety/relief valves

Tail pipe temperature sensors connected to a multipoint recorder are provided to detect SRV leakage during reactor operation. Safety/relief valve temperature elements are mounted, using a thermowell, in the SR V discharge piping several feet from the valve body. Temperature ri se above ambient is recorded in the main control room.

5.2.5.3 Indication in the Control Room

Details of the leakage detection system indications are included in Section 7.6.1.3. COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-32 5.2.5.4 Limits for Reactor Coolant Leakage 5.2.5.4.1 Total Leakage Rate

The total leakage rate consists of all leakage, iden tified and unidentified, that flows to the drywell floor drain and equipment drain sumps. The total leakage rate li mit is established so that, in the absence of normal ac power with loss of feedwater supply, make-up capabilities are provided by the RCIC system.

The equipment sump and the floor drain sump co llect all leakage. Th e equipment sump is drained by one 50-gpm pump and th e floor drain sump is draine d by two 50-gpm pumps. The total leakage rate limit from inside containm ent is established at 25 gpm, which includes no more than 5 gpm unidentified l eakage. The total l eakage rate limit is lo w enough to prevent overflow of the drywell sumps.

5.2.5.4.2 Normally Expected Leakage Rate

The pump packing glands and other seals in systems that are part of the RCPB and from which normal design leakage is expected , are provided with drains or auxiliary sealing systems. Nuclear system pumps inside th e drywell are equipped with double seals. Leakage from the primary recirculation pump seal s is piped to the equipment drain sump. Leakage in the discharge lines from the main steam SRVs is m onitored by temperature sensors that transmit a signal to the control room. Any temperature increase above the drywe ll ambient temperature detected by these sensors indicates valve leakage.

Thus, the leakage rates from pumps and the re actor vessel head seal are measurable during plant operation. These leakage rates, plus any other leakage rates meas ured while the drywell is open, are defined as identified leakage rates.

The identified leakage is measured continuously and the leakage rate will be calculated and recorded on a frequency of at least once per 12 hr in accordance with the Technical Specifications. The procedures describing how the identified leakage rate is determined include provisions for showing the identified leakage rate has not exceeded the maximum allowable value of 25 gpm, including no mo re than 5 gpm unidentified leakage. Each equipment leak-off connection has been provided with a temperature element which will identify to the operator that a higher than normal temperature exists at that particular location.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2-33 5.2.5.5 Unidentified Leak age Inside the Drywell 5.2.5.5.1 Unidentified Leakage Rate

The unidentified leakage rate is the portion of the to tal leakage rate recei ved in the drywell sumps that is not identified as pr eviously described. A threat of significant compromise to the nuclear system process barrier ex ists if the barrier contains a crack that is large enough to propagate rapidly (critical crack length). The unidentified leakage rate limit must be low because of the possibility that most of the unidentified leakage rate might be emitted from a single crack in the nuclear system process barrier.

An allowance for leakage that does not compromise barrier integr ity and is not identifiable is made for normal plant operation.

The unidentified leakage rate limit is established at the 5-gpm rate to allow time for corrective action before the process barrier c ould be significantly compromised.

The following indications are available to the control room operator for evaluating and detecting unidentified leakage:

Drywell pressure recorders,

Drywell temperature recorders,

Drywell floor drain total flow recorder, Reactor building floor drain sump fillup rate timer, Reactor building floor drain sump pump out rate timer, Drywell cooler cooling water differential temper ature recorder, Reactor vessel water level, and

Drywell atmosphere radiation monitors.

While the indications listed above have no definitive correla tion between their engineering units, they provide an early warn ing of a potential leak to the ope rator. The actual unidentified leak rate is determined by observing the drywell floor drain system flow rate recorders provided in the control room. Since the monitoring is not computerized, a computer failure would not affect indications.

5.2.5.5.2 Length of Through-Wall Flaw Experiments conducte d by GE and Battelle Memorial Ins titute (BMI) permit an analysis of critical crack size and crack opening displacement (References 5.2-4 and 5.2-5). This analysis relates to axially oriented through-wall cracks and provides a realis tic estimate of the leak rate to be expected from a crack of critical size. In every case, the leak rate from a crack of critical size is significantly gr eater than the 5-gpm criterion.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-10-029, 11-005 5.2-34 If either the total or unidentified leak rate limits are exceeded, an orderly shutdown would be initiated and the reactor would be placed in a cold shutdown condition in accordance with the Technical Specifications.

5.2.5.5.3 Criteria to Evaluate the Adequacy and Margin of the Leak Detection System

For process lines that ar e normally open, there are at least two different met hods of detecting abnormal leakage from each system within the nuclear system pr ocess barrier lo cated in the drywell, reactor building, and auxiliary building as shown in Table 5.2-12 . The instrumentation is designed so it can be set to provide alarms at established leakage rate limits and isolate the affected system, if necessary. The alarm points are determ ined analytically or based on measurements of appr opriate parameters made duri ng startup and preoperational tests. Some alarm points requi re hot operation data for their determination. Preoperational testing verified proper operation of the instrumentation for the alarm point used.

The unidentified leakage rate limit is based with an adequate margin for contingencies on the crack size large enough to propagate rapidly. The establishe d limit is sufficien tly low so that, even if the entire unidentified leakage rate we re coming from a single crack in the nuclear system process barrier, correctiv e action could be take n before the integrity of the barrier would be threatened with significant compromise.

The leak detection system sensitivity and response tim e is discussed in Section 7.6.2.4 such that an unidentified leakage rate increase of 1 gpm in less than 1 hr will be detected.

5.2.5.6 Safety Interfaces

The balance of plant/GE nuclear steam supply system safety inte rfaces for the leak detection system are the signals from the monitored balance-of-plant equipment and systems that are part of the nuclear system process barrier and associated wiring and cable lying outside the nuclear steam supply equipment. These balance-of-pla nt systems and equipment include the main steam line tunnel, the SRVs, a nd the turbine building sumps.

5.2.5.7 Testing and Calibration

Provisions for testing and calibration of the leak detection syst em are described in Section 7.6. 5.

2.6 REFERENCES

5.2-1 "Qualification of the One-Dimensional Core Transient Model (ODYN) for BWR's," NEDO-24154-A, Vol. 1 and 2, General Electric, August 1986.

5.2-2 J. M. Skarpelos and J. W. Bagg, "Chloride C ontrol in BWR Coolants," June 1973, NE DO-10899. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 5.2-35 5.2-3 W. L. Williams, Corrosi on, Vol. 13, 1957, p. 539t.

5.2-4 GEAP-5620, "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flows," by M. B. Reynolds, April 1968.

5.2-5 "Investigation and Evalua tion of Cracking in Austeniti c Stainless Steel Piping of Boiling Water Reactor Plants," NUREG-76/067, NRC/PCSG, dated

October 1975.

5.2-6 Washington Public Power Supply Sy stem, 1985, "WNP-2 Preservice Inspection Program Plan," Washington Public Power Supply System, Richland,

Washington.

5.2-7 NEDE-32906P Supplement 3-A, "Migration to TRACG04/PANAC11 fromTRACG02/PANAC10 for TRACG AOO and ATWS Overpressure Transients," April 2010.

5.2-8 "Columbia Generating Station TRACG Implementation for Reload Licensing Transient Analysis," (T1309), 001N9 271-R1, Revision 1, January 2015.

5.2-9 Letter GO2-85-110 from G. C. Sorens on, Supply System, to A. Schwencer, NRC,

Subject:

Nuclear Project No. 2, CPPR-93 Preservice Inspection Program Plan, Amendment No. 4, Su mmary Report Supplement No . 1, NIS-1 Code Data Report, dated February 28, 1985.

5.2-10 Letter GO2-83-401 from G. D. Bouchay, Supply Syst em, to A. Schwencer, NRC,

Subject:

Nuclear Project No. 2, CPPR-93, Preservice Inspection

Program Plan, Volume No. 4, "Preservice Inspection Summary Report", dated May 3, 1983.

5.2-11 "Supplemental Reload Licensing Report for Columbia" (most recent version referenced in COLR). Table 5.2-1 Exceptions to Conformance to 10 CFR 50.55a Reactor Coolant Pressure Boundary Components Component Description Quantity Plant Identification System Number Purchase Order Date Code Applied ASME Section III Code Required by 10 CFR 50.55(a) Component Status COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 20015.2-37Main steam safety

relief valves 18 MS-RV-1 A-D MS-RV-2 A-D MS-RV-3 A-D MS-RV-4 A-D

MS-RV-5 B-C

(B22-F013 A-V) April 1971 1971 Edition 1971 Summer Addenda FSa Recirc pumps 2 RRC-P-1A (B35-C001) April 1971 1971 Edition 1971 Summer Addenda FS Recirc gate valves 4 RRC-V-23/ RRC-V-67 (B35-F023/F067) June 1971 1971 Edition 1971 Summer Addenda FS Recirc flow control

valve 2 RRC-V-60 (B35-F060) June 1971 1971 Edition 1971 Summer Addenda FS Recirc piping 1 lot B35-G001 October 1971 1971 Summer Addenda 1971 Winter Addenda FS a FS = Fabricated and Shipped COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-2 Reactor Coolant Pressure Boundary Component Code C ase Interpretations

Number Tit le Remarks 5.2-38 1. 1332 - Revision 6 Requirements for steel forgi ngs Regulatory Guide 1.85, Revision 6

2. 1401 - Revision 0 Welding repairs to cladding of Class I, Section III, components after heat treating

3. 1420 - Revision 0 5b-167 Ni-Cr-Fe all oy pipe or tube

4. 1441 - Revision 1 Waiving of 3 Sm requirement for Section III construction

5. 1141 - Revision 1 Foreign p roduced steel Regulatory Guide 1.85, Revision 5

6. 1361 - Revision 2 Socket wel ds, Section I II Regulatory Guide 1.84, Revision 9 7. 1525 Pipe descaled by means other than pickling, Section III

8. 1535 -

Revision 2 Hydrostatic test of Cl ass 1 nuclear valves, Section III Regulatory Guide 1.84, Revision 9 9. 1567 Testing lots of carbon and low alloy steel covered electrodes, Section III Regulatory Guide 1.85,

Revision 6 10. 1621 - Revision 1 Internal and external valve items,

Section III, Class 1 Regulatory Guide 1.84,

Revision 12 (for 1621-2) 11. 1588 Electro-etching of Section III code symbols Regulatory Guide 1.84,

Revision 9 12. 1820 Alternative ultrasonic examination technique Section III, Division 1 Regulatory Guide 1.85,

Revision 11 13. N181 Steel castings refined by the argon oxygen decarbonization process Section 3,

Division 1 construction

14. 1711 Pressure relief valve, design rules, Section III, Division 1, Class 1, 2, 3

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-3 Nuclear Sy stem Safety/Relief Setp oints Number of Valves Spring Set Pressure (psig) ASME Rate Capacity at 103% Spring Set Pressure (lb/hr each) Pressure Setpoint for the Power Actuated Mode (psig) 5.2-39 2 1165 876,500 1091 4 1175 883,950 1101 4 1185 891,380 1111 4 1195 898,800 1121 4 1205 906,250 1131 Note: Seven of the safety/relief valves serve in the automatic dep ressurization function.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-4 Systems Which May Initiate During Safety Valve Capacity Overpressure Event System Initiating/Trip Signal(s) a 5.2-40 Reactor Protection System Reactor trips "OFF" on high flux RCIC "ON" when reactor water level L2 "OFF" when reactor water level L8 HPCS "ON" when reactor water level L2 "OFF" when reactor water level L8 Recirculation system "OFF" when reactor water level L2 "OFF" when reactor pressure 1143 psig RWCU "OFF" when reactor water level L2 a Note: Vessel level trip se ttings L2 and L8 shown in Figure 5.3-3 . COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 5.2-5 Sequence of Events for Figure 5.2-2 Time-Sec Event LDCN-15-011 5.2-41 0 Initiate closure of all main steam isolation valves (MSIV). 0.45 MSIVs reached 85% open and in itiated reactor scram. However, hypothetical failure of this position scram was assumed in this analysis. 2.0 Neutron flux reached the high APRM flux scram setpoint and

initiate reactor scram. 2.9 Steam line pressure reached the group safety relief valve pressure setpoint (spring-action mode and safety relief valves started to open). 3.0 MSIVs completely closed. 3.5 All safety relief valves opened.

3.9 Vessel bottom pressure reached its peak value.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6 Design Te mperature, P ressure and Maximum Test

Pressure for RCPB Components

Component Design Temperature (F) Design Pressure (psig) Maximum Test Pressure (psig) 5.2-42 Reactor vessel 575 1250 1563 Recirculation system Pump discharge piping, through

valves 575 1650 (a) Pump discharge piping, beyond

valves 575 1550 (a) Pump suction piping 575 1250 (a) Pump and discharge valves 575 1650 (b) Suction valves 575 1250 (b) Flow control valve 575 1675 (a) Vessel drain line 575 1275 (a) Main steam system Main steam line 575 1250 (a) Main steam line valves 575 1250 (b) Residual heat removal system Shutdown suction Recirculation header to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) Pump discharge Reactor ve ssel to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6

Design Te mperature, P ressure and Maximum Test Pressure for RCPB Components (Continued) Component Design Temperatu re (F) Design Pressure (psig) Maximum Test Pressure (psig) 5.2-43 Shutdown return Recirculation header to second

isolation valve Piping 575 1575 (a) Valves 575 1575 (b) Reactor feedwater Reactor ve ssel to man ual valve

(F011) Piping 575 1300 (a) Valves 575 1300 (b) Reactor co re isolation cooling system Steam to RCIC. 575 1250 (a) Pump turbine Reactor ve ssel to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) Pump discharge to reactor 170 1500 (a) Reactor ve ssel to second isolation valve Piping 575 1500 (a) Valves 575 1500 (b) High-pressure core spray system Outboard containment isolation valve to and including

maintenance valve insi de containmen tc Piping 575 1250 (a) Valves 575 1250 (b) COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6 Design Te mperature, P ressure and Maximum Test

Pressure for RCPB Components (Continued) Component Design Temperature (F) Design Pressure (psig) Maximum Test Pressure (psig) 5.2-44 From maintenance val ve to reactor ve ssel Piping 575 1250 (a) Valves 575 1250 (b) Low-press ure core spray system Outboard i solation valve to

reactor ve ssel Piping 575 1250 (a) Valves 575 1250 (b) Standby liquid control Pump discharge to reactor vessel Reactor to second isolation valved Piping 150 1400 (a) Valves 150 1400 (b) Reactor water cleanup system Pump suction Recirculation piping to isolation valve outside drywell Piping 575 1250 (a) Valves 575 1250 (b) Control rod drive system Piping to HCUs 150 1750 2187 a Test pressure at the bottom of the reactor vessel is nominally 1565. The piping is field tested with the reactor vessel. b Test pressure is based on ASME III Table NB-3531-9 (1971 Edition through Winter 1973 Addenda). c For dual design conditions, see Figure 6.3-3.1 . d The design temperature and pressure of the original injection piping were 575°F and 1250 psig. This portion of piping was rerouted to the HPCS injection and was tested in accordance with ASME Section XI , 1980 Edition, Winter Addenda.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Table 5.2-7 Reactor Coolant Pressure

Boundary Materials Component Form Material Specification (ASTM/ASME) LDCN-00-096 5.2-45 Reactor vessel Rolled plate Low alloy steel SA-533 grade B class 1 Heads, shel ls Forgings Welds Low alloy s teel SA-508 class 2

SFA-5.5 Closure flange Forged ring Welds Low alloy s teel Low alloy s teel SA-508 class 2

SFA-5.5 Nozzle safe ends Forgings or Plates Stainless steel SA-182, F304 or F316 SA-336, F8 or F8 M

SA-240, 304 or 316 Welds Stainless steel SFA-519, TP-308L or 316L Nozzle safe ends Forgings Welds Ni-Cr-Fe

Ni-Cr-Fe SB-166 or SB-167 SFA-5.14, TP ERNiC r-3 or SFA-5.11,

TP ENCrFe-3 Nozzle safe ends Forgings Carbon steel SA-105 grade 2, SFA-5.18 grade A, or

SFA-5.17 F70 Nozzle safe ends Forgings Austenitic stainless steel SA-182 grade F, 316L Cladding Weld overlay Austenitic stainless steel SFA-5.9 or SFA-5.4

TP-309 with carbon

content on final surface

limit to 0.09% maximum Control rod

drive housings Pipe Forgings

Welds Austenitic stainless steel Inconel SA-312 type 304

SFA-5.11

type ENiCrFe-3 or

SFA-5.14

type ERNiCr-3

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 5.2-7 Reactor Coolant Pressure Boundary Materials (Continued) Component Form Material Specification (ASTM/ASME) LDCN-14-018 5.2-46 In-core housings Pipe Forgings

Welds Austenitic stainless steel

Inconel SA-312 type 304

SFA-5.11

type ENiCrFe-3 or

SFA-5.14

type ERNiCr-3

Additional RCPB component materi als and specifications to be used are specified below.

Depending on whether impact test s are required and depending on the lowest service metal temperature when impact tests are required, the following ferritic materials and specifications are used:

Pipe SA-106 grade B and C; SA-333 grade 5; SA-155 grade KCF 70

Valves SA-105 grade II-normalized; SA-350 grade LF1 or LF2 and SA-216 grade WCB, normalized; and SA-352 grade LCB

Fittings SA-105 grade II-normalized; SA-350 grade LF1 or LF2-normalized; SA-234 grade WPB-normalized; and SA-420 grade WPL1

Bolting SA-193 grade B7; and SA-194 grades 7 and 2H

Welding Material Welding materials conform to the applicable SFA specifications listed in ASME B&PV Code Section IIc. Individual selection of filter metals are reviewed for conformity to the ba se materials being welded by the

Consulting Engineers' review of welding procedures.

For those systems or portions of systems such as the reactor recirculation system, which require austenitic stainless steel, the following materials and specifications are used:

Pipe SA-376 type 304; SA-312 type 304; SA-358 type 304 Valves SA-182 grade F-304 and F-316; SA-351 grades CF-3, CF-3M, CF-8 and CF-8M

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-7 Reactor Coolant Pressure Boundary Mater ials (Continued)

5.2-47 Pump SA-182 grade F-304; SA-351 grades CF-8 and CF-8M

Flanges SA-182 grade F-316

Bolting SA-193 grade B7; SA-194 grades 7 and 2H Welding SFA-5.4 (E308-15, E308L-15, E316 -15); SFA-5.9 (ER-308, ER-308L, ER-316)

Fittings SA-182 grade F304; SA-351 grade CF-8; SA-403 grade WP-304, 304W

Table 5.2-8 Water Sample Locations COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 2011LDCN-09-032 5.2-48 Sample Origin Sensor Location Indicator Location Recorder Location Range mho/cm Low Alarm High Reactor water recirculation loop Sample line Sample station Control room 0-1 0.0 1.0 Reactor water cleanup system inlet Sample line Sample station Control room 0-1 0.0 1.0 Reactor water cleanup system outlets Sample line Sample station Control room 0-0.3 NA 0.15

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-9 IHSI Summary Prior to First Refueling GL 88-01,

Category B Welds

Energy Northwest ISI Weld Number Welds 5.2-49 Stainless steel to s tainless s teel 24RRC(2)-A-2 thru 24RRC(2)-A-12 11 24RRC(1)-A-13 thru 24RRC(1)-A-22 10 16RRC(1)-A-1 thru 16RRC(1)-A-4 4 12RRC(1)-N2A-1, 1A 2 12RRC(1)-N2B-1, 1A 2 12RRC(1)-N2C-1, 1A 2 12RRC(1)-N2D-1, 1A 2 12RRC(1)-N2E-1, 1A 2 20RRC(6)-1 thru 20RRC(6)-7, 7A, 8 9 4RRC(8)-2A-1, 2 2 4RRC(8)-1A-1, 2 2 12RRC(7)-A-1 thru 12RRC(7)-A-6 6 12RHR(1)-A15 thru 12RHR(1)-A18 4 24RRC(2)-B-2 thru 24RRC(2)-B-10 9 16RRC(1)-B-1 thru 16RRC(1)-B-4 4 24RRC(1)-B-11 thru 24RRC(1)-B-20 10 12RRC(1)-N2F-1, 1A 2 12RRC(1)-N2G-1, 1A 2 12RRC(1)-N2H-1, 1A 2 12RRC(1)-N2J-1, 1A 2 12RRC(1)-N2K-1, 1A 2 4RRC(8)-2B-1, 2 2 4RRC(8)-1B-1, 2 2 12RRC(7)-B-1, 2, 2A thru 12RRC(7)-B-6 7 12RHR(1)-B-11 thru 12RHR(1)-B-13 3 20RHR(2)-1 1 Stainless steel to s tainless s teel caps 24RRC(1)-A13/8CAP-1, A20/12CAP-1 2 24RRC(1)-B-11/CAP-1, 18/12CAP-1 2 Stainless steel to carbon steel 20RHR(2)-2 1 12RHR(1)-A14 1 12RHR(1)-B-10 1 TOTAL 113 COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-10

IHSI Summary During First Refueling GL 88-01,

Category B Welds

Energy Northwest ISI Weld Number Welds 5.2-50 4RRC(4) A-1 thru 4R RC(4) A-11 11 4RRC(4) B-1 thru 4RRC(4) B-12 12 24RRC(2) A-10/4RRC(8)-4S 1 24RRC(2) A-10/4RRC(4)-4S 1 24RRC(1) A-13/4RRC(8)-4S 1 24RRC(1) A-13/8 Cap 1 24RRC(1) A-20/12 Cap 1 24RRC(1) A-20/12RRC(7)-4S 1 24RRC(2) B-8/4RRC(8)-4S 1 24RRC(2) B-8/4RRC(4)-4S 1 24RRC(1) B-11/8 Cap 1 24RRC(1) B-11/4RRC(8)-4S 1 24RRC(1) B-18/12 Cap 1 24RRC(1) B-18/12RRC(7)-4S 1 TOTAL 35 Type 304 Welds with Low Carbon Content a4JP (NZ) A-1 Inconel 182 buttering 1 a4JP (NZ) B-1 Inconel 182 buttering 1 a4JP (NZ) A-2 1 a4JP (NZ) B-2 1 TOTAL 4 a Confirmed by CMTR review safe end material used was type 304 with a carbon content of 0.025%. COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-11 Main Steam Isolation Valves Material Information Item Material Spec Material Type Minimum Design Wall Thickness 5.2-51 Body SA-216 GR WCB 1.58 in. Bonnet SA-105 GR II 7.66 in. Stem disc a SA-105 N/A 1.56 in. Disc piston a SA-105 N/A 3.24 in. Stema SA-564 or A-182 Tp 630 H1100

GR F6A C1 3 Bonnet studs SA-540 Class 4 1-5/8 in. diameter Bonnet nuts SA-194 GR 7 1-5/8 in. diameter See Section 5.2.3.3 for fracture toughness response.

Piping connecting the MSIV

Outside diameter 12 in.

Nominal wall thickness = 1.103 in. plus 0.125 in. a Redesign/replacement mater ials

Table 5.2-12 Summary of Isolation/Alarm of System Monitored and the Leak Detec tion Methods Used COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-12-020 5.2-52 Variable Monitored FUNCTION A A A A/I A/I A A/I A/I A/I A/I A/I A A

Source of Leakage

Location

High PC F PC Sump High Flow Rate High/Dry-well Cooler Condensate Flowa Equip- ment Area High T and T Low Steam Line Pressure RB Sump or Drain High Flow Rate PC Pressure (High) High Flow Rateb RCIC Diaphragm High Exhaust Line Pressure RWCU Flow (High) Reactor Low Water Level High Differential Pressure Fission Products Higha Main steam line PC X X X Xc X X X X RB X Xc X X X RHR PC X X X X X X RB X X X X RCIC steam PC X X X X X X X RB X X X X RCIC water PC X RB X RWCU water PC X X X Xb X X X RB hot X X X X X RB cold X X X X Feedwater PC X X X X RB Xd X ECCS water PC X X X RB X X Reactor coolant PC X X X X X X RB PC - Primary containment RB - Reactor building RWCU - Reactor water cleanup CCW - Closed cooling water

A - Alarm I - Isolation NOTE: a All systems within the drywell share a common detection system. b Break downstream of flow element will isolate the system. c In run mode only. d Alarm only (steam tunnel).

Simulated Safety Relief Valve Spring Mode Characteristic used for Capacity Sizing Analysis1-2.564.096069 1008060402000.960.970.980.991.001.011.021.031.041.05"Opening" Path"Closing" PathCode Approved Capacity Pressure/Pressure Set Point FigureAmendment 53 November 1998Form No. 960690.veR.oN .warD Columbia Generating Station Final Safety Analysis Report FigureForm No. 960690 Draw. No. Rev.950021.16 5.2-2Columbia Generating Station Final Safety Analysis Report Amendment 63December 2015 LDCN-15-011 1 Peak Vessel Pressure Versus Safety Valve Capacity 960690.47 5.2-31400135013001250(psig)406080100120Safety Valve Capacity - % NB Rated Steam FlowNumber of Operating Safety Valves 81012141618MSIV - Flux Scram (REDY)MSIV - Flux Scram (ODYN) Code Limit(1375 psig)LR W/O BP (ODYN) 1200FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis ReportPeak Vessel Bottom Pressure (psig) Time Response of Pressure Vessel forPressurization Events 960690.48 5.2-41350130012501200115011001050MSIV Closure - Flux Scram (ODYN) MSIV Closure -

Flux Scram (REDY) LR w/o BP

Direct Scram Time (Sec) Vessel Bottom Pressure (psig) (ODYN)2468101214FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.2-52202B22-04,26,1Nuclear Boiler System - P&IDRev.FigureDraw. No. Safety/Relief Valve Schematic Elevation 960690.49 5.2-6DrywellMain Steam LineReactor Vessel Main SteamIsolation ValvesSafety/Relief Valves Suppression Pool FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Flow Restrictor Columbia Generating StationFinal Safety Analysis Report FigureForm No. 960690 Amendment 53November 1998Draw. No.Rev.960690.62Safety/Relief Valve and Steam Line Schematic 5.2-7Reactor Vessel S/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VS/R VMain Steam Lines Main Steam IsolationValvesDrywellColumbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.85Schematic of Safety Valve with Auxiliary Actuating Device 5.2-8Setpoint Adjust ScrewBonnetSpindleBalancing Piston BellowsEductorBlowdownAdjusting Ring Eductor Sleeve SteamFlowInletNozzleRingDiscDisc Ring Disc Holder Piston-type Pneumatic Actuator AssemblySPVD Linear Variable Differential Transformer (LVDT)Valve Position Indication (VPI) LVDTSet Pressure Verification Device

(SPVD) Pneumatic Head SPVD Load Cell "C""B""A"Solenoid/ Air ControlValveAssemblies Discharge NozzleBodySpringLeverSchematic of Crosby 6R10/8R10 Dual-Function Type Spring-Loaded Direct-Acting Safety/Relief Valve Columbia Generating StationFinal Safety Analysis Report FigureSafety Valve Lift Versus Time Characteristics 960690.50 5.2-9050100Time (Sec) T1 = Time at which pressure exceeds the valve set pressure T1Safety Valve openingcharacteristicsValve achieves rated capacity at < 103% of set pressureSafety Valve Lift (% of full open)ValveStroke Time 0.3Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Conductance Versus pH as a Function of ChlorideConcentration of Aqueous Solution at 25C960690.51 5.2-101001010.10.01pH (at 25C)45678910Specific Conductance (mho/cm at 25°C) 0.5Chloride(ppm)0.20.11FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Typical BWR Characteristic MSIV Closure Flux Scram 960690.525.2-11FigureAmendment 63 December 2015 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report DELETEDLDCN-15-011 COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-000 5.3-1 5.3 REACTOR VESSEL

5.3.1 REACTOR VESSEL MATERIALS

5.3.1.1 Materials Specifications

The materials used in the reactor pressure vessel and appurtena nces are shown in Table 5.2-7 together with the app licable specifications. 5.3.1.2 Special Processes Used for Manufacturing and Fabrication The reactor pressure vessel is primarily constructed from low alloy, high strength steel plate and forgings. Plates are or dered to ASME SA-533, Grade B, Class 1, and forgings to ASME SA-508, Class 2. These materials are me lted to fine grain practice and are supplied in the quenched and tempered conditio

n. Further restrictions incl ude a requirement for vacuum degassing to lower the hydrogen level and impr ove the cleanliness of the low alloy steels.

Studs, nuts, and washers for the main closure flange are ordered to ASME SA-540, Grade B23 or Grade B24. Welding electrodes are low hydrogen type ordered to ASME SFA 5.5.

All plate, forgings, and bolting are 100% u ltrasonically tested and surface examined by magnetic particle methods or li quid penetrant methods in acco rdance with ASME Section III Subsection Nuclear Boiler (NB) standards. Fr acture toughness propertie s are also measured and controlled in accordance with subsection NB requirements.

All fabrication of the reactor pressure vessel is performed in accordance with the General Electric Company (GE) approved dr awings, fabrication procedures , and test procedures. The shells and vessel heads are ma de from formed plates and the flanges and nozzles from forgings. Welding performed to join these vessel components is in accordance with procedures qualified per ASME Section III and IX requirements. Weld test samples are required for each procedure for major vessel full penetration welds. Tensile and impact tests are performed to determine the properties of the base metal, heat-affected zone (HAZ) and weld metal. Submerged arc and manual stick electrode welding processes are employed. Electroslag welding is not permitted. Preheat and interp ass temperatures employed for welding of low alloy steel meet or exceed the requirements of ASME Section III, Subsection NB. Postweld heat treatment at 1100°F minimum is a pplied to all low al loy steel welds.

Radiographic examination is performed on all pressure contai ning welds in accordance with requirements of ASME Section III, Subsection NB-5320. In addition, all welds are given a supplemental ultrasonic examination.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-2 The materials, fabrication procedures, and testing me thods used in the c onstruction of boiler water reactor (BWR) reactor pressure vessels meet or exceed requirements of ASME Section III, Class 1 vessels.

5.3.1.3 Special Methods for Nondestructive Examination

The materials and welds on the reactor pressu re vessel were examin ed in accordance with methods prescribed and met the acceptance requirements specified by ASME Boiler and Pressure Vessel (B&PV) Code Section III. In addition, the pressure retaining welds were ultrasonically examined using manual techni ques. The ultrasonic examination method, including calibration, instrument ation, scanning sensitivity, a nd coverage was based on the requirements imposed by ASME Co de Section XI in Appendix I. Acceptance standards were equivalent or more restrictive than required by ASME Code Section XI.

5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels

The degree of compliance with Regulatory Guides 1.31, 1.34, 1.43, 1.44, 1.50, 1.71, and 1.99 is described in Section 1.8. 5.3.1.5 Fracture Toughness

5.3.1.5.1 Compliance w ith Code Requirements

The ferritic pressure boundary mate rial of the reactor pressure vessels was qualified by impact testing in accordance with the 1971 edition of Section III ASME Code and Summer 1971 Addenda. From an operational standpoint, the minimum temperature limits for pressurization defined by the 1998 Edition of Section XI ASME Code and 2000 Addenda, Appendix G, Protection Against Nonductile Failu re, are used as the basis for compliance with ASME Code Section III.

5.3.1.5.2 Compliance with 10 CFR 50 Appendix G

A major condition necessary for full compliance to Appendix G was satisfaction of the

requirements of the Summer 1972 Addenda to Section III. This was not possible with components which were purchased to earlier Code requirements. For the extent of the compliance, see Table 5.3-1 . Ferritic material complying w ith 10 CFR 50 Appendix G must ha ve both drop-weight tests and Charpy V-notch (CVN) tests with the CVN specimens oriented transverse to the maximum material working direct ion to establish the RTNDT. The CVN tests must be evaluated against both an absorbed energy and a lateral expansion criteria. The maximum acceptable RT NDT must be determined in accordance with the analytical procedures of ASME Code Section III, Appendix G. Appendix G of 10 CFR 50 requir es a minimum of 75 ft-lb upper shelf CVN

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-3 energy for beltline material. It also requires at least 45 ft-lb CVN energy and 25 mils lateral expansion for bolting material at the lower of the preload or lowest service temperature.

By comparison, material for the Columbia Generating Statio n (CGS) reactor vessels was qualified by either drop-weight tests or longitudinally oriented CVN tests (both not required), confirming that the material nil-ductility transi tion temperature (NDTT) is at least 60°F below the lowest service temperature. When the CVN test was app lied, a 30 ft-lb energy level was used in defining the NDTT. There was no upper shelf CVN energy requirement on the beltline material. The bolting material was qualified to a 30 ft-lb CVN energy requirement at 60°F below the minimum preload temperature.

From the previous comparison it can be seen that the fracture toughness testing performed on the CGS reactor vessel material cannot be shown to comply with 10 CFR 50 Appendix G. However, to determine operating limits in accordance with 10 CFR 50 Appendix G, estimates of the beltline material RT NDT and the highest RT NDT of all other material were made and are discussed in Section 5.3.1.5.2.2 . The method for developing these operating limits is also described therein.

On the basis of the last paragraph on page 19013 of the July 17, 1973, Federal Register, the following is considered an appr opriate method of compliance.

5.3.1.5.2.1 Intent of Proposed Approach . The intent of the prop osed special method of compliance with 10 CFR 50 Appendix G for this vessel is to provide operating limitations on pressure and temperature based on fracture tou ghness. These operating limits ensure that a margin of safety against a nonductile failure of this vessel is very nearly the same as that for a vessel built to the Summer 1972 Addenda.

The specific temperature limits for operation when the core is critical are based on 10 CFR 50 Appendix G, Paragr aph IV, A.2.C.

5.3.1.5.2.2 Operating Limits Based on Fracture Toughness . Operating limits which define minimum reactor vessel metal temperatures versus reactor pre ssure during normal heatup and cooldown and during inservice hydrostatic testi ng were established us ing the methods of Appendix G of Section XI of the ASME B&PV Code, 1998 Edition, 2000 Addenda. The results are shown in Figure 5.3-1 . All the vessel shell and head area s remote from discontinuities plus the feedwater nozzles were evaluated, and the operating limit curves are ba sed on the limiting location. The boltup limits for the flange and adjacent shell region ar e based on a minimum metal temperature of RTNDT +60°F. The maximum through-wall temperatur e gradient from continuous heating or cooling at 100°F/hr was considered. The safety factors applied were as specified in ASME Section XI Appendix G.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-4 For the purpose of setting these operating limits the reference temperature, RT NDT, is determined from the toughness te st data taken in accordance with requirements of the code to which this vessel is designed and manufactured. This tough ness test data, CVN and/or dropweight NDT, is analyzed to permit complian ce with the intent of 10 CFR 50 Appendix G. Because all toughness tes ting needed for strict compliance with Appendix G was not required at the time of vessel procurement some toughne ss results are not available. For example, longitudinal CVNs, instead of transverse, were tested, usually at a single test temperature of +10°F or -20°F, for absorbed energy. Also, at the time either CVN or NDT testing was permitted; therefore, in many cases both tests were not performed as is currently required. To substitute for this absence of certain data, toughness property corr elations were derived for the vessel materials to operate on the available data to give a conservative estimate of RT NDT compliant with the intent of Appendix G criteria.

These toughness correlations vary , depending upon the specific ma terial analyzed, and were derived from the results of We lding Research Counc il (WRC) Bulletin 217, "Properties of Heavy Section Nuclear Reactor Steels," and from toughness data from the CGS vessel and other reactors. In the case of vessel plate material (SA-533 Grade 8, Class 1), the predicted limiting toughness property is either NDT or transverse CVN 50 ft-lb temperature minus 60°F. NDT values are available for CGS vessel shell plates. The transverse CVN 50 ft-lb transition temperature is estimated from longitudinal CV N data in the following manner. The lowest longitudinal CVN 50 ft-lb value is adjusted to derive a longitudinal CVN 50 ft-lb transition temperature by adding 2°F per ft-lb to the test temperature. If the actual data equals or exceeds 50 ft-lb, the test temperature is used. Once the longitudinal 50 ft-lb temperature is derived, an additional 30°F is added to account for orientati on effects and to estimate the transverse CVN 50 ft-lb temperature minus 60°F, estimated in the preceding manner.

Using the above general approach, an initial RT NDT of 28°F was established for the core beltline region.

For forgings (SA-508 Class 2), the predicted limiting property is the same as for vessel plates. CVN and NDT values are availabl e for the vessel flange, closure head flange, and feedwater nozzle materials for CGS. RT NDT is estimated in the same way as for vessel plate.

For the vessel weld metal th e predicted limiting property is the CVN 50 ft-lb transition temperature minus 60°F, as the NDT values are -50°F or lower for these materials. This temperature is derived in th e same way as for the vessel plate material, except the 30°F addition of orientation effects is omitted since there is no princi pal working direction. When NDT values are available, they are also considered and the RT NDT is taken as the higher of NDT or the 50 ft-lb temperat ure minus 60°F. When NDT is not available, the RTNDT shall not be less than -50°F, since lower values are not supported by the correlation data.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-5 For vessel weld HAZ material the RT NDT is assumed the same as for the base material as ASME Code weld procedure qualification test requirements, and postweld heat treatment indicates this assumption is valid.

Figure 5.3-2 provides a sketch of the reactor ve ssel, including the basic dimensions, all longitudinal and circumferential welds, and all pl ates of the beltline region. Tables 5.3-2 through 5.3-7 contain the supporting information for Figure 5.3-2, such as piece mark, heat number, and impact data for th e plates and filler material used in the beltline region. Closure bolting material (SA-540 Grade B24) t oughness test requirement s for CGS were for 30 ft-lb at 60°F below the boltup temperature. Current code requirements are for 45 ft-lb and 25 mils lateral expansion at the preload or lowest service temperature, including boltup. All CGS closure stud materials meet current requirements at +10°F. The effect of the main closure flange discontinuity was considered by adding 60°F to the RTNDT to establish the minimum temperature fo r boltup and pressurization. The minimum boltup temperature of 80°F for CGS, which is shown on Figure 5.3-1 , is based on an initial RTNDT of +20°F for the shell plate connec ting to the closure flange forgings.

The effect of the feedwa ter nozzle discontinuities were consid ered by adjusting the results of a BWR/6 reactor discontinuity analysis to the reactor. The ad justment was made by increasing the minimum temperatures required by the diffe rence between the CGS and BWR/6 feedwater nozzle forging RT NDT. The feedwater nozzle adju stment was based on an RT NDT of 0°F.

The reactor vessel closure studs have a minimum Charpy impact energy of 45 ft-lb and 26 mils lateral expansion at 10°F. The lowest service temperature for the closure studs is 10°F.

Vessel irradiation embrittlement of beltline materials, as measured by adjusted reference temperatures and upper shelf en ergies due to increased flux , was evaluated against the requirements of 10 CFR 50 Appendix G. For a predicted fluence of 7.41 x 10 17n/cm2, fracture toughness values are acceptable and remain within Appendix G limits.

5.3.1.5.2.3 Temperature Limits for Boltup . A minimum temperature of 10°F is required for the closure studs. A sufficient number of studs may be tensioned at 70°F to seal the closure flange O-rings for the purpose of raising reactor water level above the clos ure flanges to assist in warming them. The flanges and adjacent shell are required to be warmed to a minimum temperature of 80°F before they are stressed by the full intended bolt preload. The fully preloaded boltup limits are shown in Figure 5.3-1 . 5.3.1.5.2.4 Inservice Inspection Hy drostatic or Leak Pressure Tests . Based on 10 CFR 50 Appendix G, and Regulatory Guid e 1.99, Revision 2, requirements, pressure/temperature limit curves were estab lished based on an RT NDT of 28°F for the limiting beltline material; see Figure 5.3-1 . The fracture toughness analysis for inse rvice inspection of le ak test resulted in

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-13-009 5.3-6 curve A shown in Figure 5.3-1 . The predicted shift in the RT NDT temperature was determined using the methodology outlined in Regulatory Guide 1.99, Revision 2.

Technical Specification 3.10.1 allo ws inservice leak and hydrostatic testing to be performed in Mode 4 when the metallurgical characteristics of the reactor pressure vessel require testing at temperatures greater than 200F, given specified Mode 3 Limiting Conditions for Operations are met. This exemption is only applicable provided reactor coolant temperature does not exceed 275F. 5.3.1.5.2.5 Operating Limits During Heatup, Cooldown, and Core Operation. The fracture toughness analysis was done for the normal heat up or cooldown rate of 100°F/hr. The temperature gradients and thermal stress effects corresponding to th is rate were included. The results of the analysis ar e operating limits defined by Figure 5.3-1 . Curves A, B, and C give the limits for hydrotest, nonnucl ear heating, and nuclear heating. The minimum boltup temperature of 80°F is based on an RT NDT at 20°F for a shell plate wh ich connects to the lower flange (Heat and Slab No. C-1307-2); above 80°F the core beltline plate (Heat and Slab No. C-1272-1), which has an initial RT NDT of 28°F, is most limiting for inservice hydrostatic or leak pressure tests (curve A). The feedwater nozzles, which have an RT NDT of 0°F, are more restrictive than the core beltline at lower pressures during nonnucl ear and nuclear heating (curves B and C).

5.3.1.5.2.6 Reactor Vessel Annealing. Inplace annealing of the reactor vessel to counteract radiation embrittlement is unnecessary because beltl ine material adjusted reference temperature of the NDT is well within the 10 CFR 50 Appendix G 200°F screening limit.

5.3.1.6 Material Surveillance

The materials surveillance progr am monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting from exposure to neutron irradiation and ther mal environment.

The CGS plant-specific RPV ma terials surveillance program is replaced by the NRC approved BWR Vessel and Internals Proj ect (BWRVIP) Integrated Su rveillance Program (ISP), as described in the latest approved revision of BWRVIP-86 (Reference 5.3.4-2). The ISP meets the requirements of 10 CFR 50, Appendix H.

The current surveillance capsule withdrawal schedule for the re presentative materials for the CGS vessel is based on th e latest approved revision of BWRVIP-86 (Reference 5.3.4-2). No capsules from the CGS ve ssel are included in the ISP. Th e withdrawal of capsules for the CGS plant-specific surveillance program is perman ently deferred by participation in the ISP. Capsules from other plants will be remove d and tested in acco rdance with the ISP COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005, 04-033 5.3-7 implementation plan. The results from these tests will provide the necessary data to monitor embrittlement for the CGS vessel.

Materials for the plant-specific materials surveillance program were se lected to represent materials used in the reactor beltline region. The specimens were manufactured from a plate actually used in the beltline region and a weld typi cal of those in the be ltline region and thus represent base metal, weld meta l, and the transition zone betw een base metal and weld. The plate and weld were heat treated in a manner which simulates the actual heat treatment performed on the core regi on shell plates of the comp leted vessel. WPPSS-ENT-089 (Reference 5.3.4-1) provides additional de tail and supporting inform ation for the materials surveillance program. For the extent of compliance to 10 CFR 50 Appendix H, see Table 5.3-8 . NEDO-21708 also addressed the requirements of Appendix H to 10 CFR 50 and supports the current application of Regulatory Guide 1.99.

5.3.1.6.1 Positioning of Surve illance Capsules and Method of Attachment for Plant-Specific Surveillance Program

Surveillance specimen capsules are located at three azimuths at a common elevation in the core beltline region. The sealed capsules are not atta ched to the vessel but are in welded capsule holders. The capsule holders are mechanically restrained by capsule holder brackets as shown in Figure 5.3-4. The capsule holder brackets allow the capsule holder to be removed at any desired time in the life of the plant for specimen testing. A positive spring-loaded locking device is provided to retain the capsules in pos ition throughout any anticipated event during the lifetime of the vessel.

The capsule holder brackets are designed, fabricat ed, and analyzed to th e requirements of the ASME B&PV Code Section III. The surveillance brackets are welded to the clad material which surfaces the pressure vessel walls. As attached , the brackets do not ha ve to comply with specifications of the ASME Code.

5.3.1.6.2 Time and Number of Dosimetry Measurements

General Electric provides a sepa rate neutron dosimeter so that fluence measurements may be made at the vessel ID during the first fuel cycle to verify the predicted fluence at an early date in plant operation. This measurement is made ov er this short period to avoid saturation of the dosimeters now available. Once the fluence-to -thermal power output is verified, no further dosimetry is considered necessary because of the linear relationship be tween fluence and power output.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-8 5.3.1.6.3 Neutron Flux a nd Fluence Calculations

A description of the methods of analysis for neutron flux and fl uence calculations is contained in Sections 4.1.4.5 and 4.3.2.8. 5.3.1.7 Reactor Vessel Fasteners

The reactor vessel closure head (flange) is fastened to the reactor vessel shell flange by multiple sets of threaded studs and nuts. The lower end of each stud is installed in a thread hole in its vessel shell flange. A nut and washer are installed on the upper end of each stud. The proper amount of preload can be applied to the studs by sequential te nsioning using hydraulic tensioners. The design a nd analysis of this area of th e vessel is in full compliance with all Section III Class 1 Code requirements. The material for studs, nuts, and washers is SA-540, Grade B23 or B24. The maximum reported ultimate te nsile stress for the bolting material was 167,000 psi whic h is less than the 170,000 psi limitation in Regulatory Guide 1.65. Also the Charpy impact test recommendations of Pa ragraph IV.A.4 of Appendix G to 10 CFR 50 were not specified in the vessel order since the order was placed prior to issuance of Appendix G to 10 CFR 50. However, impact data from the certified materials report shows that all bolting material has met the Appendix G im pact properties. For example, the lowest reported CV N energy was 45 ft-lb at 10°F ve rsus the required 45 ft-lb at 70°F and the lowest reported CV N expansion was 26 mils at 10°F versus the required 25 mils at 70°F.

Hardness tests are performed on a ll main closure bolting to demonstrate that heat treatment has been properly performed. Studs, nuts, and washers are ultras onically examined in accordance with Section III, N8-2585 and the following additiona l requirements:

a. Examination is performed after heat treatment and pr ior to machining threads.

b. Straight beam examination is performed on 100% of each stud. Reference standard for the radial scan is 0.5-in

. diameter flat bottom hole having a depth equal to 10% of the material thickness. For the end scan the reference standard is a 0.5-in. flat bottom hole having a dept h of 0.5 in. For additional details of the techniques used to examine the reactor vessel studs, s ee the response to Regulatory Guide 1.65, Revision 0, October 1973, in Section 1.8.

c. Nuts and washers are examined by angle beam from the outside circumference in both the axial and circ umferential directions.

There are no metal platings applied to closure studs, nuts, or washers. A phosphate coating is applied to threaded areas of studs and nuts and bearing areas of nuts and washers to act as a rust inhibitor and to assist in re taining lubricant on these surfaces.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-005 5.3-9 5.3.2 PRESSURE-TEMPERATURE LIMITS

5.3.2.1 Limit Curves

Limits on pressure and temperat ure for inservice leak and hydr ostatic tests, normal operation (including heatup and cool down), and reactor core operation are shown in Figure 5.3-1 . The basis used to determine these limits is described in Section 5.3.1.5. 5.3.2.2 Operating Procedures

By comparison of the pressure versus temperature limits in Figure 5.3-1 with intended normal operating procedures for the most severe upset transient, it is shown that the limits will not be exceeded during any foreseeable upset condition. Reactor operating procedures have been

established such that actual tran sients will not be more severe than those for which the vessel design adequacy has been demonstrated. Of the design transients, the upset condition producing the most adverse temp erature and pressure condition anywhere in the vessel head and/or shell areas has a minimu m fluid temperature of 250°F a nd a maximum pressure peak of 1180 psig. Scram automatically oc curs with initiation of this even t, prior to the reduction in fluid temperature, such that the applicable operating limits are bounded by curve A of Figure 5.3-1 . Figure 5.3-1 show that at the maximum tran sient pressure of 1180 psig, the minimum allowable reactor ve ssel metal temperature conser vatively bounds the minimum 250°F reactor fluid temperature.

5.3.3 REACTOR VESSEL INTEGRITY

The reactor vessel was fabricated for GE's Nuclear Energy Di vision by CBI Nuclear Co., and was subject to the requirements of GE's Quality Assurance program.

Assurance was made that measures were es tablished requiring that purchased material, equipment, and services associated with the reactor vessel and appurt enances conform to the requirements of the subject purchase documents . These measures included provisions, as appropriate, for source evalua tion and selection, objective ev idence of quality furnished, inspection at the vendor source, and examin ation of the comple ted reactor vessel.

Energy Northwest's agent provided inspection surveillance of the reactor vessel fabricators in process manufacturing, fabrication, and tes ting operations in accordan ce with GE's Quality Assurance program and approved inspection procedures. The reactor vessel fabricator was responsible for the first level in spection of manufactur ing, fabrication, and testing activities, and GE was responsible for the first level of audit a nd surveillance inspection.

Adequate documentary evidence that the reactor vessel material, manufacture, testing, and inspection conforms to the specified quality assurance re quirements contained in the procurement specification is available in plant records. COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-033, 05-021 5.3-10 5.3.3.1 Design

5.3.3.1.1 Description

5.3.3.1.1.1 Reactor Vessel . The reactor vessel shown in Figure 5.3-5 is a vertical, cylindrical pressure vessel of welded cons truction. The vessel is designed, fabricated, tested, inspected, and stamped in accordance with the ASME Code Section III, Cla ss 1, including the addenda in effect at the date of order pl acement. Design of the reactor ve ssel and its support system meets Seismic Category I equipment requirements. The materials used in the reactor pressure vessel are shown in Table 5.2-7 . The cylindrical shell and bottom head sections of the reactor vessel are fabricated of low alloy steel, the interior of which is clad with stainless steel weld overlay. Nozzle and nozzle weld zones are unclad except fo r those mating to stainless steel piping systems.

Inplace annealing of the reactor vessel is unnecessary because shifts in transition temperature caused by irradiation during the 40-year life can be accommodated by raising the minimum pressurization temperature. Radiation embrittle ment is not a problem outside of the vessel beltline region because the irradiation in those areas is less than 1 x 10 18 nvt with neutron energies in excess of 1 MeV. The inside diameter and mini mum wall thickness of the reactor vessel beltline is provided in Table 5.3-9 . Quality control methods used dur ing the fabrication and assemb ly of the reactor vessel and appurtenances ensure that design specifications were met. The ve ssel top head is secured to the reactor vessel by studs and nuts. These nuts are tightened with a stud tensioner. The vessel flanges are sealed with two concentric metal seal rings de signed to permit no detectable leakage through the inner or outer seal at any operating condition, including heating to operating pressure and te mperature at a maximum rate of 100°F/hr in any 1-hr period. To detect seal failure, a vent tap is located between the two seal rings. A monitor line is attached to the tap to provide an indication of leakage from the inner seal ring seal.

5.3.3.1.1.2 Shroud Support . The shroud support is a circular plate welded to the vessel wall. This support is designed to ca rry the weight of the shroud, shroud head, peripheral fuel elements, neutron sources, core plate, top guide, the steam separators, the jet pump diffusers, jet pump slip joint clamps, and to laterally support the fuel as semblies. Design of the shroud support also accounts for pressure differentials across the shroud support plate, for the restraining effect of component s attached to the support, and for earthquake loadings. The shroud support design is specified to m eet appropriate ASME Code stress limits.

5.3.3.1.1.3 Protec tion of Closure Studs. The BWR does not use borated water for reactivity control. This section is therefore not applicable.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-11 5.3.3.1.2 Safety Design Bases

Design of the reactor vessel a nd appurtenances meet the foll owing safety design bases:

a. The reactor vessel and appurtenances will withstand adverse combinations of loading and forces resulting from operation under abnor mal and accident conditions, and

b. To minimize the possibility of brittle fracture of the nucl ear system process barrier, the following are required:

1. Impact properties at temperatures related to vessel ope ration have been specified for materials used in the reactor vessel.

2. Expected shifts in transition temp erature during design life as a result of environmental conditions, such as ne utron flux, are considered in the design. Operational limitations ensure that NDTT shifts are accounted for in reactor operation.

3. Operational margins to be obser ved with regard to the transition temperature are specified for each mode of operation.

5.3.3.1.3 Power Gene ration Design Basis

The design of the reactor vessel and appurte nances meets the following power generation design basis:

a. The reactor vessel has been desi gned for a useful life of 40 years,

b. External and internal supports that ar e integral parts of the reactor vessel are located and designed so that stresses in the vessel and supports that result from reactions at these supports are within ASME Code limits, and

c. Design of the reactor vessel and appurte nances allow for a suitable program of inspection and surveillance.

5.3.3.1.4 Reactor Vessel Design Data

Reactor vessel design data are contained in Tables 5.2-6 and 5.2-7. COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-12 5.3.3.1.4.1 Vessel Support . The concrete and steel vessel support pedestal is constructed as an integral part of the building foundation. Steel anchor bolts set in the concrete extend through the bearing plate and secure the flange of the reactor vessel support skirt to the bearing plate and thus to the support pedestal.

5.3.3.1.4.2 Contro l Rod Drive Housings . The control rod drive (C RD) housings are inserted through the CRD penetrations in the reactor vessel bottom head and are welded to the reactor vessel. Each housing transmits loads to the bottom h ead of the reactor. These loads include the weights of a control rod, a CRD, a CRD t ube, a four-lobed fuel s upport piece, and the four fuel assemblies that rest on the fuel support piece. The housings are fabricated of Type 304 austenitic stainless steel.

5.3.3.1.4.2.1 Control Rod Drive Return Line . To preclude CRD return line cracking on CGS, the return line was deleted and the system modified. The modification cons ists of adding pressure equalizing valves be tween the exhaust and cooling water headers and the use of reverse flow through multiple hydr aulic control unit (HCU) solenoi d valves as the CRD system exhaust flow path. The acceptance of this modification is based on system analyses and performance tests conducted on operating BWRs which have shown satisfactory system operation. The system tests showed that system pressure transients, CRD settling times, and CRD speeds were all unchanged. The tests also showed that all syst ems functions performed normally.

5.3.3.1.4.3 In-Core Neut ron Flux Monitor Housings. Each in-core neutron flux monitor housing is inserted through the in-core penetrati ons in the bottom head and is welded to the inner surface of the bottom head.

An in-core flux monitor guide t ube is welded to the top of each housing and either a source range monitor/intermediate range monitor drive unit or a local power range monitor is bolted to the seal/ring flange at the bottom of the housing.

5.3.3.1.4.4 Reactor Vessel Insulation . The insulation panels for the cylindrical shell of the vessel are self-supporting, with seis mic restraints attach ed to the sacrificia l shield wall. The insulation is designed to be re movable over those portions of the vessel where required for the purpose of in-service inspection. 5.3.3.1.4.5 Reactor Vessel Nozzles . All piping connecting to the reactor vessel nozzles has been designed so as not to exceed the allowable loads on any nozzle. The vessel top head nozzle is provided with a flange with large groove facing. The drain

nozzle is of the full penetration weld design. The recirculation inlet nozzles (located as shown in Figure 5.3-5), feedwater inlet nozzles, core spray inlet nozzles, low-pressure coolant injection (LPCI) nozzles, and the CRD hydraulic system return nozzle all have thermal sleeves. Nozzles connecting to stainless steel piping have safe ends or extensions made of COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-13 stainless steel. These safe ends or extensions were welded to the nozzles after the pressure vessel was heat treated to avoid furnace sensitization of the stainless steel. The material used is compatible with the material of the mating pipe.

The nozzle for the standby liquid control (SLC) pipe was designed to minimize thermal shock effects on the reactor vessel in th e event of injection of cold SLC solution. However, the SLC injection pipe has been relocate d to a nozzle on the high-pressure core spray (HPCS) injection line and no longer uses the old nozzle in the bottom head of the reactor pressure vessel. The old nozzle is still in service as the connection for pressure sensing belo w the core plate, but there is no flow through the nozzle under any oper ating condition.

In the past, thermal fatigue cracking of feedwater nozzles and vibrational cracking of sparger arms have been observed at other operating BWRs. The mechanisms which have caused cracking in other operating BWRs are understood . A summary discussion of these problems and the solutions incorporated in the CGS design is presented in the following.

A detailed evaluation of the problems of the feedwater nozzle and spar ger is presented in NEDE-21821, "BWR Feedwater No zzle/ Sparger Final Report," March 1978. The solution of the feedwater nozzle and sparger cracking pr oblems involved severa l elements, including material selection and processing, nozzle clad elimination, and ther mal sleeve and sparger redesign. The following summarizes the problem s and solutions that have been implemented in the CGS design.

Problem Cause Fix Sparger arm cracks Vibration Eliminated clearance between thermal sleeve and safe end

RPV feedwater Thermal Eliminated clad, thermal fatigue eliminated leakage with a welded joint between the sparger and safe end The sparger vibration has been a ttributed to a self-excitation caused by instability of leakage flow through the annular clearance between the thermal sleeve and safe end. Tests have shown that the vibration is eliminated if the clearance is reduced sufficiently or sealed. The solution that was selected for CGS uses a welded joint to ensure no leakage. This feature is also an essential part of the solution of the nozzle cracking problem. Freedom from vibration over a range of conditions has been demonstrated by the tests reported in NEDE-23604 (see Figures 5.3-6 and 5.3-7). COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-033 5.3-14 The cracking of the feedwater noz zles is a two-part process. The crack initiation mechanism as discussed above is the resu lt of self-initiated thermal cycling. If this were the only mechanism present, the cracks would initiate, grow to a depth of approximately 0.25 in., and arrest. This degree of cracking could be to lerated; however, there is another mechanism which supports crack growth. This mechanism is the system induced tr ansients, primarily the startup/shutdown transients. Because of CGS's welded thermal sleeve arrangement, leakage flow is eliminated and the heat transfer between the feedwater and the nozzle are reduced to the point where the thermal stresses in the nozzle are not high enough to cause a significant crack growth. Analyses presented in NEDE-21821, Section 4.7, demonstrated the benefits of the welded thermal sleeve and of using unclad nozzles. With these demonstrated benefits and inservice surveillance, CGS found it unnecessary to install instrumentation for design verification.

CGS has installed two automatic feedwater low flow control va lves, RFW-FCV-10A and 10B. These valves have the capacity to control flow down to 362 gpm, or about 1.25% of total flow. This valve configuration will substantially reduce the temperature differential between the feedwater and the water in the RPV during low power operation, also reducing the thermal stresses in the nozzle.

5.3.3.1.4.6 Materials and Inspection . The reactor vessel was de signed and fabricated in accordance with the appropriate ASME B&PV Code as defined in Section 5.2.1.2. Table 5.2-7 defines the materials and specifications. Table 5.3-8 defines the compliance with reactor vessel material surve illance program requirements.

5.3.3.1.4.7 Reactor Vessel Schematic (BWR) . The reactor vessel sche matic is contained in Figure 5.3-3 . Trip system water levels are indicated as shown.

5.3.3.2 Materials of Construction

All materials used in the construction of the reactor pressure ve ssel conform to the requirements of ASME Code Section II materials. The vessel heads, shells, flanges, and nozzles are fabricated from low alloy steel plate and forgings purchased in accordance with ASME specifications SA533 Grad e B Class 1 and SA-508 Class

2. Special requirements for the low alloy steel plate and forgings are discussed in Section 5.3.1.2. Cladding employed on the interior surfaces of the vessel consists of austenitic stainless steel weld overlay.

These materials of construction were selected because they provide adequate strength, fracture toughness, fabricability, and compatibility with the BWR environment. Their suitability has been demonstrated by long-term successful operating experience in reactor service.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-15 5.3.3.3 Fabrication Methods The reactor pressure vessel is a vertical cyli ndrical pressure vessel of welded construction fabricated in accordance with ASME Code Section III, Class 1, requirements. All fabrication of the reactor pressure vessel was performed in accordance with buyer-approved drawings, fabrication procedures, and test procedures. The shells and vessel heads were made from formed low alloy steel plates and the flanges and no zzles from low alloy steel forgings. Welding performed to join these vessel components was in accordance with procedures qualified per ASME Section III and IX requirements. Weld test samples were required for each procedure for major vesse l full penetration welds.

Submerged arc and manual stick electrode welding processes we re employed. Electroslag welding was not permitted. Preheat and interpass temperatures employed for welding of low alloy steel met or exceeded the requirements of ASME Section III, Subsection NB. Postweld heat treatment of 1100°F minimum was applied to all low alloy steel welds.

All previous BWR pressure vesse ls have employed sim ilar fabrication met hods. These vessels have operated for periods up to 16 years and their service history is excellent.

The vessel fabricator, CBI Nu clear Co., has had extensive experience with GE, reactor vessels, and has been the primary supplier for GE domestic reactor vesse ls and some foreign vessels since the company was formed in 1972 from a merger agreement between Chicago Bridge and Iron Co. and GE. Prior experience by the Chicago Bridge and Iron Co. with GE reactor vessels dates back to 1966.

5.3.3.4 Inspection Requirements

All plate, forgings, and bolti ng were 100% ultrasonically te sted and surface examined by magnetic particle methods or li quid penetrant methods in acco rdance with ASME Section III requirements. Welds on the reactor pressure vessel were examin ed in accordance with methods prescribed and met the acceptance requi rements specified by AS ME Section III. In addition, the pressure-retaining welds were ultrasonically examined usin g acceptance standards which were required by ASME Section XI.

5.3.3.5 Shipment and Installation

The completed reactor vessel was given a thorough cleaning and examination prior to shipment. The vessel wa s tightly sealed for shipment to pr event entry of dirt or moisture. Preparations for shipment were in accordance with de tailed written procedures. On arrival at the reactor site the reactor vessel was carefully examined for evidence of any contamination as a result of damage to shipping covers. Suitable measures were taken during installation to ensure that vessel integrity was maintained; for example, acces s controls were applied to COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3-16 personnel entering the vessel, weather protec tion was provided, peri odic cleanings were performed, and only approved miscellaneous materials were us ed during assembly. 5.3.3.6 Operating Conditions

Restrictions on plant operation to hold thermal stresses within acceptable ranges are included in the Technical Specifications. These re strictions on coolant temperature are

a. The average rate of change of react or coolant temperatur e during normal heatup and cooldown,

b. Coolant temperature difference between the dome (inferred from P sat) and the bottom head drain, and

c. Idle reactor recirculation loop a nd average reactor c oolant temperature differential.

The limit regarding the normal rate of heatup and cooldown (item a) as sures that the vessel closure, closure studs, vessel support skirt, and CRD housing and stub tube stresses and usage remain within acceptable limits. The vessel temperatur e limit on recirculating pump operation and power level increase restriction (item b) augments the it em a limit in further detail by ensuring that the vessel bottom head region will not be warmed at an ex cessive rate caused by rapid sweep out of cold coolant in the vessel lower head region by recirculating pump operation or natural circulation (cold coolant can accumulate as a result of control drive inleakage and/or low recirculati on flow rate during startup or hot standby). The item c limit further restricts operation of the recirculating pumps to avoid high thermal stress effects in the pumps and piping, while also minimizing thermal stresses on the vessel nozzles.

The above operational limits when maintained insu re that the stress limi ts within the reactor vessel and its components are with in the thermal limits to whic h the vessel was designed for normal operating conditions. To maintain the material integrity of the vess el in the event that these operational limits are exceeded the reactor vessel has also been designed to withstand a limited number of transients caused by operator error. Reactor vessel material integrity is also maintained during abnorm al operating conditions where safety systems or controls provide an automatic response in the reactor vessel. The special and transi ent events cons idered in the design of the vessel are discus sed or referenced in Section 5.2.2. 5.3.3.7 Inservice Surveillance

Inservice inspection of the reactor pressure vessel is in acco rdance with the requirements as discussed in Section 5.2.4. The vessel was examined once prior to startup to satisfy the preoperational requirements of IS-232 or the ASME Code, Secti on XI. Subsequent inservice COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-13-009 5.3-17 inspection will be scheduled and performed in accordance with the requirements of 10 CFR 50.55a subparagraph (g).

The materials surveillance progr am monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting fr om their exposure to neutron irradiation and thermal environment. See Section 5.3.1.6 for description of the materials surveillance program. Operating procedures will be modified in accordance with test results to ensure adequate brittl e fracture control. Material surveillance programs and inservice inspection programs ar e in accordance with applicable ASME Code require ments and provide assurance th at brittle fracture control and pressure vessel integrity will be maintained throughout the service lifetime of the reactor pressure vessel.

5.

3.4 REFERENCES

5.3.4-1 WPPSS-ENT-089, "WNP-2 RPV Surv eillance Program," Current Revision.

5.3.4-2 BWRVIP-86, Revision 1-A, "BWR Vessel and Inte rnals Project, Updated BWR Integrated Surveillance Program (ISP) Implementation Plan," Final Report, October 2012.

Table 5.3-1 10 CFR 50 Appendix G Matrix Appendix G Paragraph Topic ComplyYes/Noor N/A Alternative Actions or Comments COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 19985.3-19I, II Introduction; Definitions -- III.A Compliance with ASME Code, Section NB-2300 Yes See Section 5.3.1.5.2 for discussion. III.B.1 Location and Orientation of Impact Test Spec Yes See III.A above. III.B.2 Materials Used to Prepare Test Specimens No Compliance except for CVN orientation and CVN upper shelf. III.B.3 Calibration of Temperature Instruments and Charpy Test Machines No Paragraph NB-2360 of the ASME B&PV Code Section III was not in existence at the time of purchase of the CGS reactor pressure vessel. However, the requirements of the 1971 edition of the ASME B&PV Section III code, Summer 1971 addenda, were met. For the discussions of the GE interpretations of compliance and NRC acceptance see References 1 and 2. The temperature instruments and Charpy Test Machines calibration data are retained until the next recalibration. This is in accordance with Regulatory Guide 1.88, Revision 2, GE Alternative Position 1.88, and ANSI N45.2.9-1974. Therefore, the instrument calibration data for CGS would not be currently available. III.B.4 Qualification of Testing Personnel No No written procedures were in existence as required by the regulation; however, the individuals were qualified by on-the-job training and past experience. For the discussion of the GE interpretation of compliance and NRC acceptance see References 1 and 2. III.B.5 Test Results Recording and Certif ication Yes See References 1 and 2. III.C.1 Test Conditions No See III.A, III.B.2 above. Table 5.3-1 10 CFR 50 Appendix G Ma trix (Continued) Appendix G Paragraph Topic ComplyYes/Noor N/A Alternative Actions or Comments COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000LDCN-99-086 5.3-20III.C.2 Materials Used to Prepare Test Specimens for Reactor Vessel Beltline Yes Compliance on base metal and weld metal tests. Test weld not made on same heat of base plate necessarily. IV.A.1 Acceptance Standard of Materials -- IV.A.2.a Calculates Stress Intensity Factor Yes IV.A.2.b Requirements for Nozzles, Flanges, and Shell Region Near Geometric Discontinuities No Plus 60F was added to the RTNDT for the reactor vessel flanges. For feedwater nozzles the results of the BWR/6 analysis was adjusted to CGS RTNDT conditions. IV.A.2.c RPV Metal Temperature Requirement When Core is Critical Yes Comply with 10 CFR 50 Appendix G. IV.A.2.d Minimum Permissible Temperature During Hydro Test Yes IV.A.3 Materials for Piping, Pumps, and Valves No Main steam line piping is in compliance. See 5.2.3.3 for discussions on pumps and valves. IV.A.4 Materials for Bolting and Other Fasteners Yes Current toughness requirements for closure head studs are met at +10F even though testing was done per the 1971 ASME code. IV.B Minimum Upper Shelf Energy for RPV Beltline No Weld and longitudinal CVN data were taken at -20F and +10F only. An estimate of compliance to requirements should be made from the first surveillance capsule results per MTEB 5-2. Table 5.3-1 10 CFR 50 Appendix G Ma trix (Continued) Appendix G Paragraph Topic ComplyYes/No or N/A Alternative Actions or Comments COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORTDecember 2005LDCN-04-005, 04-033 5.3-21IV.B (continued) Beltline plates were tested with longitudinal CVNs at +10 °F only. The minimum values are for Heat C1272-1 (0.15% Cu; 34, 26, 30, 31, 34, 30 ft-lb; 10 and 40% shear at +10 °F) and Heat C1273-1 (0.14% Cu; 33, 33, 30, 30, 34, 35 ft-lb; 10% shear at +10 °F). Beltline welds were tested with CVNs at 10 °F or -20°F only. Lowest weld values are found for Heat 04P046/Lot D217A27A (0.06% Cu; 34, 36, 37, 39, 40 ft-lb; 20 and 30% shear at -20 °F). Heat C3L46C/Lot J020A27A (0.02% Cu; 35, 39, 40 ft-lb; 60% shear at +10 °F) and Heat 05P018/Lot D211A27A (0.09% Cu; 29, 30, 31, 36, 38 ft-lb; 30 and 40% shear at -20 °F). Because of the preceding relatively low test temperatures and Cu contents, it is anticipated that end-of-life upper shelf CVN values would

be in excess of 50 ft-lb. IV.C Requirements for Annealing when RTndt >200 N/A V.A Requirements for Material Surveillance Program See Table 5.3-8 V.B Conditions for Continued Operation Yes Requirements for continued operations are covered in Technical Specifications and the Reactor Pressure Vessel Surveillance Program document (WPPSS-ENT-089, Reference 5.3.4-1). See Section 5.3.1.6 for description of the Materials Surveillance Program. V.C Alternative if V.B Cannot be Satisfied N/A The Surveillance Program demonstrates compliance with Appendix G, Section IV. See Section 5.3.1.6 for description of the Materials Surveillance Program.

Table 5.3-1 10 CFR 50 Appendix G Matr ix for (Continued) Appendix G Paragraph Topic ComplyYes/No or N/A Alternative Actions or Comments COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORTNovember 1998 5.3-22V.D Requirement for RPV Thermal Annealing if V.C Cannot be Met N/A V.E Reporting Requirements for V.C and V.D N/A REFERENCES

1. Letter MFN-414-77 from G. G. Sherwood, G E, to Edson G. Case, NRC, dated October 17, 1977.

2. Letter from Robert B. Minoque, NRC, to G. G. Sherwood, GE, dated February 14, 1978.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-2 Plate Material Cross Reference Heat Slab 5.3-23 Ring 21 PCMK 21-1-1 C1272 1 PCMK 21-1-2 C1273 1 PCMK 21-1-3 C1273 2 PCMK 21-1-4 C1272 2 Ring 22 PCMK 22-1-1 B5301 1 PCMK 22-1-2 C1336 1 PCMK 22-1-3 C1337 1 PCMK 22-1-4 C1337 2 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-3

Weld Mate rial Cross Reference

Weld Identification Type Heat Lot 5.3-24 AB - Girthweld E8018NM 492L4871 A422B27AF RAC01NMM 5P6756 0342 RAC01NMM 3P4955 0342 E8018NM 04T931 A423B27AG Ring 21 BA E8018NM 04P046 D217A27A E8018NM 07L669 K004 A27A RAC01NMM 3P4966 1214 BB E8018NM 04P046 D217A27A E8018NM 07L669 K004 A27A E8018NM C3L46C J020A27A RAC01NMM 3P4966 1214 E8018NM 08M365 G128 A27A BC E8018NM 09L853 A111 A27A E8018NM C3L46C J020A27A RAC01NMM 3P4966 1214 BD E8018NM C3L46C J020A27A

RAC01NMM 3P4966 1214 E8018NM 04P046 D217A27A

E8018NM C3L46C J020A27A Ring 22 BE RAC01NMM 3P4966 1214 BF E8018NM 04P046 D217A27A E8018NM 05P018 D211A27A

RAC01NM 3P4966 1214 BG E8018NM 624063 C228A27A E8018NM 624039 D224A27A RAC01NMM 3P4966 1214 BH E8018NM 04P096 D217A27A E8018NM 624039 D205A27A RAC01NMM 3P4966 1214 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-4 Plate Material Charpy Impact ft-lb @ +1 0F Charpy Expansion MLE Drop Weight NDT (F) RTNDT (F) 5.3-25 Ring 21 PCMK 21-1-1

Heat C1272-1 34, 26, 30/31, 34, 30 30, 34, 24/27, 26, 32 10 28 PCMK 21-1-2

Heat C1273-1 33, 33, 30/30, 34, 35 30, 31, 27/26, 34, 32 20 20 PCMK 21-1-3

Heat C1273-2 38, 48, 55/66, 61, 71 44, 39, 34/53, 52, 56 30 4 PCMK 21-1-4

Heat C1272-2 40, 42, 44/51, 55, 50 32, 36, 38/41, 44, 42 30 0 Ring 22 PCMK 22-1-1

Heat B5301-1 64, 62, 66/52, 52, 55 56, 56, 56/45, 44, 44 30 20 PCMK 22-1-2

Heat C1336-1 70, 72, 71/60, 44, 66 59, 60, 62/56, 41, 51 30 8 PCMK 22-1-3

Heat C1337-1 71, 76, 74/70, 72, 55 61, 60, 60/63, 61, 52 30 20 PCMK 22-1-4

Heat C1337-2 62, 72, 82/73, 67, 73 51, 61, 66/52, 59, 61 50 20

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature (°F) RTNDT(°F) LDCN-04-005 5.3-26 Girth Weld AB E8018NM/492L4871 Lot A422B27AF 78, 82, 105, 93, 81 55, 60, 72, 74, 60 20a 50 RAC01NMM/5P6756 b Lot 0342 76, 79, 77, 80, 72 64, 72, 55, 69, 60 +10 50 RAC01NMM/5P6756 c Lot 0342 76, 79, 77, 80, 72 64, 72, 55, 69, 60 +10 50 RAC01NMM/3P4955 b Lot 0342 49, 63, 47, 49, 64 39, 48, 36, 43, 57 +10 20 RAC01NMM/3P4955 c Lot 0342 52, 37, 45, 55, 33 44, 30, 43, 50, 32 +10 16 E8018NM/04T931 Lot A423B27AG 86, 84, 102, 63, 61 69, 58, 60, 57, 70 20 50 Ring 21BA E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 E8018NM/07L669 Lot K004A27A 50, 50, 54 44, 44, 46 +10a 50 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10a -48 Ring 21BB E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 E8018NM/07L669 Lot K004A27A 50, 50, 54 44, 44, 46 +10a 50 E8018NM/C3L46C Lot J020827A 35, 39, 40 34, 39, 39 +10a 20 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material (Continued) Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature (°F) RTNDT(°F) LDCN-04-005 5.3-27 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10a 48 E8018NM/08M365 Lot G128A27A 49, 50, 51 38, 40, 43 +10a 48 Ring 21BC E8018NM/09L853 Lot A111A27A 78, 78, 79 60, 62, 62 +10a 50 E8018NM/C3L46C Lot J020A27A 35, 39, 40 34, 39, 39 +10a 20 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10a 48 Ring 21BD E8018NM/C3L46C Lot J020A27A 35, 39, 40 34, 39, 39 +10a 20 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10a 48 E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 Ring 22BE RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material (Continued) Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature (°F) RTNDT(°F) LDCN-04-005 5.3-28 Ring 22BF E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 E8018NM/05P018 Lot D211A27A 29, 30, 31, 36, 38 26, 26, 31, 33, 35 20a 38 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 Ring 22BG E8018NM/624063 Lot C228A27A 37, 40, 51, 57, 70 33, 34, 41, 47, 55 20a 50 E8018NM/624039 Lot D224A27A 28, 33, 34, 36, 42 29, 32, 33, 34, 42 20a 36 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 Ring 22BH E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20a 48 E8018NM/624039 Lot D205A27A 41, 44, 49, 54, 58 32, 36, 40, 41, 45 20a 50 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 a Drop weight NDT not applicable. b Tandem wire process. c Single wire process.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-6 Vessel Beltline Plate Plate P Cu C Mn Si S Ni Mo V LDCN-04-005 5.3-29 C1272-1 0.013 0.15 0.23 1.31 0.26 0.02 0.60 0.55 -- C1272-2 0.013 0.15 0.23 1.31 0.26 0.02 0.60 0.55 -- C1273-1 0.014 0.14 0.23 1.28 0.23 0.0180.60 0.57 -- C1273-2 0.014 0.14 0.23 1.28 0.23 0.0180.60 0.57 -- B5301-1 0.017 0.13 0.20 1.34 0.23 0.0140.50 0.52 -- C1336-1 0.017 0.13 0.21 1.36 0.22 0.0130.50 0.49 -- C1337-1 0.018 0.15 0.22 1.32 0.21 0.0130.51 0.50 -- C1337-2 0.018 0.15 0.22 1.32 0.21 0.0130.51 0.50 -- Peak I.D. EOL (33.1 EF PY) fluence = 7.41 x 10 17 n/cm2. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 Table 5.3-7 Vessel Beltline Weld Material Chemistry a Weld Heat/Control Cu C Mn Si S Ni Mo V P LDCN-08-023 5.3-30 492L4871b 0.03 0.07 1.17 0.32 0.02 0.98 0.51 0.02 0.02 5P6756/0342 c 5P6756/0342 d 0.08f 0.08f 0.063 0.078 1.27 1.24 0.57 0.53 0.011 0.012 0.936f0.936f 0.45 0.46 0.006 0.006 0.01 0.01 3P4955/0342 d 3P4955/0342 c 0.027f 0.027f 0.035 0.054 1.33 1.28 0.56 0.55 0.011 0.010 0.921f0.921f 0.52 0.54 0.006 0.007 0.016 0.01604T931b 0.03 0.05 1.03 0.28 0.024 1.00 0.53 0.01 0.02 04P046b 0.06 0.044 1.04 0.40 0.021 0.90 0.58 0.02 0.009 07L996b 0.03 0.05 1.24 0.48 0.016 1.02 0.54 -- 0.014 3P4966/3481 d 3P4966/3481 c 0.025f 0.025f 0.074 0.067 1.38 1.39 0.36 0.38 0.013 0.014 0.913f0.913f 0.49 0.53 0.006 0.008 0.010 0.0113P4966/3482 c 3P4966/3482 d 0.025f 0.025f 0.059 0.077 1.35 1.42 0.38 0.41 0.013 0.013 0.913f0.913f 0.50 0.53 0.005 0.005 0.013 0.014CL46Cb 0.02 0.063 0.96 0.32 0.017 0.87 0.53 -- 0.01908M365b 0.02 0.057 1.23 0.47 0.023 1.10 0.57 -- 0.02 09L853b 0.03 0.052 1.23 0.46 0.023 0.86 0.51 -- 0.018 05P018b 0.09 0.057 1.21 0.44 0.021 0.90 0.53 0.01 0.008 624063b 0.03 0.041 1.12 0.41 0.018 1.00 0.54 0.01 0.009 624039b,e 0.07 0.060 1.11 0.45 0.025 1.01 0.57 0.02 0.015 624039b,e 0.10 0.041 1.12 0.45 0.02 0.92 0.53 0.01 0.01 a As deposited. b M = Manual Welding Process c S = Single Wire Process d T = Tandem Wire Process e Different lot numbers f GE Nuclear Energy, "Pressure-Temperature Curves for Energy Northwest Columbia," NEDC-33144-P (CVI CAL 1012-00,3), Table 4-6b.

Table 5.3-8 10 CFR 50 Appendix H Matrix Appendix H Paragraph Topic ComplyYes/No or N/A Alternative Actions or Comments I Introduction N/A II.A Fluence 10 17n/cm2 Yes CGS Plant-specific RPV Surveillance Program is replaced by the

BWRVIP ISP. See Section 5.3.1.6. II.B Standards Requirements (ASTM) for Surveillance

No Plant-specific Surveillance Program: Noncompliance with ASTM E185-73 in that the surveillance specimens are not necessarily from the limiting beltline material. Specimens are from actual beltline material, however, and can be used to predict behavior of the limiting material. Heat and heat/lot numbers for surveillance specimens were supplied. See Section 5.3.1.6. II.C.1 Surveillance Specimen Shall be Taken for Locations Alongside the Fracture Test Specimens

(Section III.B of Appendix G)

No Plant-specific Surveillance Program: Noncompliance in that specimens may not have necessarily been taken from alongside specimens required by Section III of Appendix G and transverse CVNs may not be employed. However, representative materials have been used, and

RTNDT shift appears to be independent of specimen orientation. See Section 5.3.1.6. II.C.2 Locations of Surveillance Capsules in RPV

Yes Code basis is used for attachment of brackets to vessel cladding.

II.C.3.a Withdrawal Schedule of Capsules, RTNDT <100°F N/A See Section 5.3.1.6. Starting RT NDT of limiting material is based on alternative action (see paragraph III.A of Appendix G). II.C.3.b Withdrawal Schedule of Capsules, RTNDT <200°F N/A II.C.3.c Withdrawal Schedule of Capsules, RTNDT >200°F N/A COLUMBIA GENERATING STATION Amendment59 FINAL SAFETY ANALYSIS REPORTDecember 2007LDCN-06-000 5.3-31 Table 5.3-8 10 CFR 50 Appendix H Ma trix (Continued) Appendix H Paragraph Topic Comply Yes/No or N/A Alternative Actions or Comments

III.A Fracture Toughness Testing Requirements of

Specimens

Yes Requirements for postirradiation testing of surveillance material are addressed in the BWRVIP ISP implementation plan (Reference 5.3.4-2). III.B Method of Determining Adjusted Reference

Temperature for Base Metal, HAZ, and Weld Metal Yes Method of determining adjusted reference temperatures found in the BWRVIP ISP implementation plan (Reference 5.3.4-2). IV.A Reporting Requirements of Test Results

Yes Reporting requirements are discussed in the BWRVIP ISP implementation plan (Reference 5.3.4-2). IV.B Requirement for Dosimetry Measurement

Yes Dosimetry requirements are discussed in the BWRVIP ISP implementation plan (Reference 5.3.4-2). IV.C Reporting Requirements of Pressure/Temperature Limits Yes A discussion of the pressure/temperature limits and reporting requirements is found in the BWRVIP implementation plan (Reference 5.3.4-2). COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-13-009 5.3-32 COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-9 Reactor Vessel Beltline Minimum Wall Thickness and Diameter LDCN-04-005, 04-033 5.3-33 Inside diameter with clad = 251 in. (minimum) Wall thickness (ring #22, lo wer intermediate shell) = 6.188 in. (minimum) Wall thickness (ring #2 1, lower shell) = 9.5 in. (minimum) Clad thickness = 0.1875 in. (nominal)

= 0.125 in. (minimum)

Refer to Figure 5.3-2 and CVI 02B13-06,2 Rev. 8 (VPF #3133-001-9) CBI Nuclear Company Drawing No. 1, Rev. 8, "Vessel Outline."

900547.42 Columbia Generating Station Final Safety Analysis Report Pressure Temperature Limits Testing Curve A (Inservice Leak and Hydrostatic Testing Curve)Draw. No.Rev.FigureAmendment 58 December 2005 5.3-1.1Form No. 960690FH LDCN-04-005 0 25 50 75 100 125 150 175 200MINIMUM REACTOR VESSEL METAL TEMPERATURE (F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig) 1035 PSIG 88.6°F800 PSIG68°F1035 PSIG117.1°FUPPER VESSELAND BELTLINE

LIMITSBOTTOM HEADCURVEACCEPTABLE AREA OFOPERATION TO THE RIGHT OF THIS CURVEBELTLINE CURVES ADJUSTED AS SHOWN:EFPY SHIFT (°F) 33.1 35INITIAL RTndt VALUES ARE28°F FOR BELTLINE, 34°F FOR UPPER VESSEL, AND34°F FOR BOTTOM HEADHEATUP/COOLDOWNRATE OF COOLANT FLANGEREGION80°FBOTTOMHEAD68°F910 PSIG110°F 14001300 120011001000900 800 700 600 500 400 300 200 1000 990578.74 Columbia Generating StationFinal Safety Analysis ReportPressure Temperature Limits Curve B(Non-Nuclear Heating and Cooldown Curve)Draw. No.Rev.FigureAmendment 58December 2005 5.3-1.2Form No. 960690FH LDCN-04-005 0100200300400 500600 700800 9001000110012001300 14000 25 5075 100125 150 175200225250MINIMUM REACTOR VESSEL METAL TEM PERATURE(F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig)UPPER VESSELAND BELTLINELIMITSBOTTOM HEADCURVEBELTLINE CUR VES ADJUSTED AS S HOWN: EFPY SHIFT (F)33.1 35HEATUP/COOLDOWNRATE OF COOLANT< 100F/HRBOTTOMHEAD 68FFLANGEREGION 80FACCEPTABLE AREA OF OPERATION TO THERIGHT OF THIS CURVE600 PSIG68F790 PSIG140FINITIAL RT ndt VALUES ARE 28F FOR BELTLINE,34F FOR UPPER VESSEL, AND34F FOR BOTTOM HEAD1035 PSIG148.1F1035 PSIG109.3F 0 25 50 75 100 125 150 175 200 225 250 275 300 900547.43 Columbia Generating Station Final Safety Analysis Report Pressure Temperature Limits Curve C(Nuclear Heating and Cooldown Curve)Draw. No.Rev.FigureAmendment 58 December 2005 5.3-1.3Form No. 960690FH LDCN-04-005MINIMUM REACTOR VESSEL METAL TEMPERATURE (F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig) 1035 PSIG 188.1F14001300 120011001000900 800 700 600 500 400 300 200 1000BELTLINE ANDNON-BELTLINELIMITSBELTLINE CURVE ADJUSTED AS SHOWN: EFPY SHIFT (F)33.1 35INITIAL RT ndt VALUESARE28F FOR BELTLI NE, 34F FOR UPPERVESSEL, AND34F FOR BOTTOM HEAD HEATUP/C OOLDOWN RATE OF C OOLANT < 100F/HRACCEPTABLE AREA OF OPERATION TO THERIGHT OF THIS CURVE790 PSIG180F60 PSIGMinimum CriticalityTemperature 80F312 PSIG Amendment 57December 2003 910402.30 5.3-2FigureForm No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis ReportVessel Beltline Plate and Weld Seam Identification LDCN-02-064 PCMK 22-1-4 Heat C1337

Slab 2Weld "BG"Weld "BF" PCMK 22-1-2

Heat C1336

Slab 1Weld "BE"Girth Weld "AB"Weld "BH" PCMK 21-1-2

Heat C1273

Slab 1Weld "BC"Weld "BB" PCMK 21-1-3

Heat C1273

Slab 2Weld "BA"Weld "BD" PCMK 21-1-1

Heat C1272

Slab 1PCMK 21-1-4

Heat C1272

Slab 2PCMK 22-1-3 Heat C1337

Slab 1PCMK 22-1-1

Heat B5301

Slab 1251" dia. Ring #22Ring #21405" Elev.360.31" TopCore Elev.230" Elev.99 13/16" Elev. 216.31" Bott.Core Elev. 0" Elevation EOL Limiting Plate

Nominal Reactor Vessel Water Level Trip and Alarm Elevation Settings 960690.53 5.3-3High Water Level Alarm, L7 = 568.0 in.Normal Water Level = 563.55 in.Low Water Level Alarm, L4 = 559.0 in. Recirc Outlet Nozzle = 172.5 in.Top of Active Fuel Zone = 366.31 in.Bottom of Active Fuel Zone = 216.31 in. Elevation 0.00 in. Recirc. Inlet Nozzle = 181.0 in.Low Water Level, L1 = 398.5 in. Steam Line Nozzle = 648.0 in.High Water LevelTrip, L8 = 582.0 in.Low Water Level Scram, L3 = 540.5 in. Feedwater Nozzle = 493.25 in.Low Water Level,

L2 = 477.5 in. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Bracket for Holding Surveillance Capsule 960690.54 5.3-4FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.-.00-C-11B.12Vessel Inside Clad Radius FullPenetration Weld (Typ.) -B-.25.25Typ.C.50 Total118.31-.25.06.621.38.06.06.062.00.75.752.00.06.061.18.622.00.06.06+.25+.12Columbia Generating StationFinal Safety Analysis Report Rev.FigureDraw. No. Form No. 960690 Amendment 53 November 1998 Columbia Generating Station Final Safety Analysis Report 020002.44 5.3-5Reactor Vessel Feedwater Nozzle 960690.56 5.3-6FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Nozzle, SA-508, CI.II Safe End, SB-166, Inconel Thermal Sleeve Extension, SB-166 Thermal Sleeve, SA-336, CI.F8 Inconel OverlayWeld Illustration Back-up Ring, SB-168 12345676 3/4"1453767/8"7/16"1 1/8"7 1/8"9/16"22 3/4"R3 9/16"R Feedwater Sparger 960690.57 5.3-72136"End BracketForged TeeTyp. for Weld Nozzle, SA-508, CI.IIForged Tee, 304S.S Sparger Header, 304S.S 123FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-1 5.4 COMPONENT AND SUBSYSTEM DESIGN Pumps and valves within the reactor coolant pressure boundary (RCPB) are described in Table 5.4-1. 5.4.1 REACTOR RECIRCULATION PUMPS

5.4.1.1 Safety Design Bases The reactor recirculation system (RRC) has been designed to meet the following safety design bases: a. An adequate fuel barrier thermal margin shall be ensured during postulated transients,

b. A failure of piping inte grity shall not compromise the ability of the reactor vessel internals to provide a refloodable volume, and

c. The system shall mainta in pressure integrity duri ng adverse combinations of loadings and forces occurring during a bnormal, accident, and special event conditions.

5.4.1.2 Power Gene ration Design Bases

The RRC meets the following power generation design bases:

a. The system shall provide sufficient flow to remove heat from the fuel, and

b. System design shall minimize maintenance situations that would require core disassembly and fuel removal.

5.4.1.3 Description

The RRC consists of the two r ecirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reacto r vessel jet pumps (see Figure 5.4-1 ). Each external loop contains one hi gh-capacity variable-s peed motor-driven recirculation pump. The motor is powered by an adjustable speed driv e (ASD). The external loop also contains two motor-operated gate valves (for pump maintenance). Each pump

suction line contains a flow meas uring system. The recirculati on loops are part of the RCPB and are located inside the drywell structure. The jet pumps are reactor vessel internals. Their location and mechanical desi gn are discussed in Section 3.9.5. The important design and performance characteristics of the RRC is shown in Table 5.4-2 . COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-10-010 5.4-2 The head, flow, torque, net pos itive suction head (NPSH), BHP, and efficiency curves are shown in Figures 5.4-2 , 5.4-3, and 5.4-4. Instrumentation and cont rol description is provided in Sections 7.6 and 7.7. The recirculation system pi ping and normally flooded secti on of the reactor vessel is periodically coated with a micros copic layer of noble metals. Th is coating serv es to create a catalytic layering of the noble me tal platinum to reduce the hydr ogen addition injection rate required to achieve a low electrochemical corrosion potential (ECP). The low ECP achieves intergranular stress corrosion cr acking (IGSCC) and irradiation assisted stress corrosion cracking (IASCC) protection while minimizing the effects of high dose rates attributed to regular hydrogen injection rates.

The recirculated coolant consists of saturated water from the steam separators and dryers that have been subcooled by incoming feedwater. This water passes down the annulus between the reactor vessel wall and the core shroud. A po rtion of the coolant flows from the vessel, through the two external recirc ulation loops, and beco mes the driving flow for the jet pumps. Each of the two external recirc ulation loops discharg es high pressure flow into an external manifold from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remain ing portion of the coolant mixtur e in the annulus provides the driven flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the driving flow. The flows, both driving and driven, are mixed in the jet pump throat section and result in partial pressure recovery. The balance of recovery is obtained in the jet pump diffusing suction (see Figure 5.4-5 ). The adequacy of the to tal flow to the core is discussed in Section 4.4. The allowable heatup rate for the recirculation pump casing is the same as the reactor vessel. If one loop is shut down, the id le loop can be kept hot by leav ing the loop valves open; this permits the reactor pressure plus the active jet pump head to cause reverse flow in the idle loop. When starting the pump in an idle recirc ulation loop with the other loop in operation, the operating loop flow will be verified to be less than 50% of rated loop flow within 15 minutes prior to pump start.

Because the removal of the reactor recirculation gate valve in ternals would re quire unloading the core, the objective of the valve trim design is to minimize the need for maintenance of the valve internals. The valves are provided with high quality backseats that permit renewal of stem packing while the system is full of water.

The 20-in. motor-operated gate valves provide pump and flow control valve (FCV) isolation during maintenance. The suction valve is capable of closing w ith up to 50 psi differential, while the discharge valve can clos e with up to 400 psi differential. Both valves are remote manually operated.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-3 The FCV is blocked open (seized in the full open position). This condition does not affect the pressure integrity or impact the transient duty cycle of the valve or allow the ball to break away from the shaft.

The required NPSH for the recirculation pumps and jet pumps is supplied by the subcooling provided by the feedwater flow. Accurate temperature detectors are provided in the recirculation lines. Steam dome temperature is provided through pressu re conversion. The difference between these two readings is a di rect measurement of the subcooling. If the subcooling falls below the time-delayed setpoint 10.7°F, the ASD system is reduced to minimum frequency 15 Hz (25% pump speed) on both of the RRC loops. Each loop has independent instrumentati on for cavitation protection.

When preparing for hydrostatic te sts, the nuclear system temperat ure must be raised above the vessel nil ductility transition (NDT) temperature lim it. The vessel is heat ed by core decay heat and/or by operating th e recirculation pumps.

Connections to the piping on the suction and discharge sides of the pumps provide a means to

flush and decontaminate the pum p and adjacent piping. The pi ping low point dr ain, designed for the connection of temporar y piping, is used during fl ushing or decontamination.

Each recirculation pump is driven by an adjustable speed motor and is equipped with a two-stage mechanical seal cart ridge. Each of the two seals in the package is subject to one-half the total pressure being sealed. Each seal is structurally capable of sealing full pressure for limited periods of operation. The two seals can be replaced without removing the motor from the pump. The pump shaft passes through a breakdown bushing in the pump casing to reduce leakage in the event of a gross failure of both shaft seals. The cavity temperature and pressure drop across each individual seal can be monitored.

Each recirculation pump motor is a vertical, solid-shaft, totally enclosed, air-water-cooled, induction motor. The combined rotating inertias of the recirculation pump and motor provide a slow coastdown of flow following loss of ASD-supplied power to the drive motors so that they are adequately cooled during the transient. This inertia requirement is met without a flywheel.

The ASD can vary the discharge flow of the pump proportionally to a reactor operator remote manually adjusted demand signal. The RRC GE-FANUC digital control scheme is described in Sections 7.6 and 7.7. The recirculation loop flow rate can be varied, within the expected flow range, in response to changes to system demand.

The design objective for the recirculation system equipment is to provide units that will not require removal from the system for rework or overhaul. Pump casing and valve bodies are designed for a 40-year life and are welded to the pipe.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 LDCN-04-041 5.4-4 The pump drive motor, impeller, and wear rings ar e designed for as long a life as is practical. Pump mechanical seal parts and the valve packing have life expectancies which afford convenient replacement during the refueling outages.

The ASD system selected to drive the recirculation pump induction motor is a dual channel system. Two ASDs are provided, capable of 11,200 hp at 66 Hz per RRC loop. If one channel fails, the RRC loop flow capability must be reduced to the capability of a single channel ASD. The dual channel ASD system provides for high ava ilability of the ASD system. The ASD system is a solid-state frequency converter with overall high availability. Sections 7.6 and 7.7 provide more detail of the system design.

The recirculation system piping is designed and constructed to meet the requirements of the applicable ASME and ANSI codes.

The RRC pressure boundary equipment is designe d as Seismic Category I equipment. The pump is assumed to be filled w ith water for the analysis. Vibr ation snubbers located at the top of the motor and at the bottom of the pump casing are designed to resist the horizontal reactions.

The recirculation piping, valves, and pumps ar e supported by hangers to avoid the use of piping expansion loops th at would be required if the pumps were anchored. In addition, the recirculation loops are provided with a system of restraints designed so that reaction forces associated with any split or ci rcumferential break do not jeopard ize drywell integrity. This restraint system provides adequate clearance for normal therma l expansion movement of the loop. The criteria for the protection agai nst the dynamic effects associated with a loss-of-coolant accident (LOCA ) are contained in Section 3.6. The recirculation system piping, valves, and pump casings are c overed with thermal insulation having a total maximum heat tr ansfer rate of 65 Btu/hr-ft 2 with the system at rated operating conditions. This heat loss includes losses through joints, laps , and other openings that may occur in normal application.

The insulation is primarily the al l-metal reflective type. It is prefabricated into components for field installation. Removable insulation is provided at various locations to permit periodic inspection of the equipment. The residual heat removal (RHR) system can use the recirculation loop jet pumps to provide circulation through the reactor core. Operating restrictions limit RHR operation to regions where jet pump cavitation does not occur.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-5 5.4.1.3.1 Recirculation Syst em Cavitation Consideration Cavitation Coefficients

The recirculation pump, jet pump, and FCV were tested to determine their cavitation coefficients so that prolonged operati on in cavitating regime s can be avoided.

Equipment Damage Provisions Cavitation interlocks are provided for the recirculation pum p and jet pumps; since cavitation produces material damage afte r long-term operation and the damage potential decreases with an increase in water temperature, short periods of cavitation during a transient or accident are not a concern. However, long-te rm operation that might occur is of sufficient concern to call for inspections during the next refueling outage. Consequently , to avoid the need for such inspections, automatic interlocks are installed. Class 1E equipment is not necessary for power generation design requirements, so the automatic interlocks are non-Class 1E.

The consequences of cavitation would require inspection of the affected compone nt and repair or replacement if the inspection showed unacceptable damage. Consequently, cavitation could call for increased scheduled outag e time for inspection/repair aff ecting plant availability power generation design goals.

The ASD and its GE-FANUC digital control syst em is a non-safety-related system. The ASD and control system have alar m and protective systems and ar e provided with on-line video diagnostic displays at the main control room ope rating benchboard.

5.4.1.4 Safety Evaluation

Reactor recirculation system malfunctions that pose threats of damage to the fuel barrier are described and eval uated in Section 15.3. It is shown in Section 15.3 that none of the malfunctions result in significan t fuel damage. The RRC has sufficient flow coastdown characteristics to maintain fuel thermal margins during ab normal operational transients.

The core flooding capability of a jet pump design plant is discussed in detail in the emergency core cooling system (ECCS) docum ent submitted to the NRC (Reference 5.4-1). The ability to reflood the boiling water reactor (BWR) core to the top of the jet pumps is shown schematically in Figure 5.4-6 and is discussed in Reference 5.4-1.

Piping and pump design pressures for the RRC are based on peak steam pressure in the reactor dome, appropriate pump head allowances, and the elevation head above the lowest point in the recirculation loop. Piping and related equipment pressure part s are chosen in accordance with applicable codes. Use of the listed code design criteria ensure s that a system designed, built,

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-6 and operated within design limits has an extrem ely low probability of failure caused by any known failure mechanism.

Purchase specifications require that the recirculation pumps first critical speed shall not be less than 130% of operating speed. Calculation submittal was requi red and approved.

Purchase specifications require that integrity of the pum p case be maintained through all transients and that the pump remain operable through all normal and upset transients. The design of the motor bearings are required to be such that dynamic load capability at rated operating conditions is not exceed ed during the safe shutdown ear thquake (SSE). Calculation submittal was required of the vendor and has been received and approved by GE.

Pump overspeed occurs during the course of a LOCA due to blowdown through the broken loop's pump. Design studies determined that the overspeed was not sufficient to cause destruction of the motor; c onsequently no pump overspeed protection provision was made.

A failure modes effects analysis (FMEA) was performed on the bl ock valves. In addition, an analysis was made to determine the effect of block valve closure on recirculation pump coastdown. The analysis postulates that coincident with a recirculation pump trip, the block valves begin to close. It was concluded that any closure time greater than 1 minute will have no effect on coastdown times. The consequences of an in advertent closure without a coincident pump trip is covered in the FMEA.

5.4.1.5 Inspection and Testing

Quality control methods we re used during fabrication and asse mbly of the RRC to ensure that design specifications were met. Inspection and testing is carried out as described in Chapter 3 . The reactor coolant system was thoroughly cl eaned and flushed before fuel was loaded initially.

During the preoperational test program, the RR C was hydrostatically tested at 125% reactor vessel design pressure. Preoperational tests on the RRC also included checking operation of the pumps, flow control system, and gate valves, and are discussed in Chapter 14 . During the startup test program, horizontal and vertical motions of the RRC piping and equipment were observed as described in Section 5.4.14. 5.4.2 STEAM GENERATORS (Pressurized Water Reactor)

This is not applicab le to BWR plants.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-7 5.4.3 REACTOR COOLANT PIPING

The RCPB piping is di scussed in Sections 3.9.3.1 and 5.4.1. The recirculation loops are shown in Figures 5.4-1 and 5.4-7. The design characteristics are presented in Table 5.4-2 . Avoidance of stress corrosion crack ing is discussed in Section 5.2.3. 5.4.4 MAIN STEAM LINE FLOW RESTRICTORS

5.4.4.1 Safety Design Bases

The main steam line flow restrictors were designed to

a. Limit the rate of vessel blowdown to 200 percent of the normal rated flow in the event of a steam line break outside c ontainment. This limits the reactor depressurization rate to a value which will ensure that the steam dryer and other reactor internal struct ures remain in place.

b. Withstand the maximum pressure difference expected across the restrictor, following complete severan ce of a main steam line,

c. Limit the amount of radiological releas e outside of the drywell prior to main steam isolation valve (MSIV) closure, and

d. Provide trip signals for MSIV closure.

5.4.4.2 Description

A main steam line flow restrictor (see Figure 5.4-8 ) is provided for each of the four main steam lines. The restrictor is a complete assembly welded into the main steam line. It is located between the last main steam line safety/relief valve (SRV) and the inboard MSIV.

The restrictor limits the coolant blowdown rate from the reactor vessel in the event a main steam line break occurs outside the containment. The restrict or assembly consists of a venturi-type nozzle insert welded, in accordance with applicable code requirements, into the main steam line. The flow rest rictor is designed and fabricated in accordance with the ASME "Fluid Meters," 6th edition, 1977.

The flow restrictor has no moving parts. Its mechanical structure can withstand the velocities and forces associated with a main steam line break. The ma ximum differential pressure is conservatively assumed to be 1375 psi, the reactor vessel ASME Code limit pressure.

The ratio of venturi throat diameter to steam line inside diameter of approximately 0.55 results in a maximum pressure different ial (unrecovered pressure) of a bout 10 psig at 100% of rated

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009 5.4-8 flow. This design limits the steam flow in a severed line to le ss than 200% rated flow, yet it results in negligible increase in steam moisture content during normal operation. The restrictor is also used to measure steam flow to initiate closure of the MSIVs when the steam flow exceeds preselected operational limits.

5.4.4.3 Safety Evaluation

A postulated guillotine break of one of the four main steam lines outside the containment results in mass loss from both ends of the break. The flow from the upst ream side is initially limited by the flow restrictor upstream of the inboard isolation valve. Flow from the downstream side is initially limited by the total area of the flow restrictors in the three unbroken lines. Subsequent closur e of the MSIVs further limits the flow when the valve area becomes less than the limiter area and finally terminates the mass loss when full closure is reached.

Analysis of the main steam break accident outside containment demonstrates that the radioactive materials released to the environs results in calculated doses that are in compliance with 10 CFR 50.67 and Regulat ory Guide 1.183 dose limits.

Tests on a scale model determined final design and performance characteristics of the flow restrictor. The characteristics include maximum flow rate of the restrictor corresponding to the accident conditions, unrecoverable losses under normal plant ope rating conditions, and discharge moisture level. The te sts showed that flow restriction at critical throat velocities is stable and predictable.

The steam flow restrictor is exposed to steam of 0.10% to 0.20% moisture flowing at velocities approximately 150 ft/sec (steam piping I.D.) to 600 ft /sec (steam restrictor throat). The cast austenitic stainless steel (ASME SA351, or ASTM A351, Type CF8) was selected for the steam flow restrictor material because it has excellent resistance to erosion-corrosion in a high velocity steam atmosphere. The excellent performance of st ainless steel in high velocity steam appears to be due to its resistance to corrosion. A protective surface film forms on the stainless steel which prevents any surface attack and this film is not removed by the steam.

Hardness has no significant effect on erosion-corrosion. For example, hardened carbon steel or alloy steel will erode rapidl y in applications where soft stainless steel is unaffected.

Surface finish has a minor effect on erosion-corro sion. Experience shows that a machined or a ground surface is sufficiently smooth and th at no detrimental erosion will occur.

5.4.4.4 Inspection and Testing

Because the flow restrictor fo rms a permanent part of the ma in steam line piping and has no moving components, no test ing program is planned. Only ve ry slow erosion will occur with

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009 5.4-9 time, and such a slight enlargement will have no sa fety significance. Stainless steel resistance to corrosion has been substantiated by turbine inspections at the Dresden Unit 1 facility, which have revealed no noticeable effects from erosion on the stainless steel nozzle partitions. The Dresden inlet velocities are about 300 ft/sec an d the exit velocities ar e 600 to 900 ft/sec. However, calculations show that, even if the erosion rates are as high as 0.004 in. per year, after 40 years of operation the increase in restrictor choked flow rate would not exceed 5%. The impact on calculated accident radiological releases would be minimal.

5.4.5 MAIN STEAM LINE ISOLATION SYSTEM The MSIV leakage control system has been deactivated.

5.4.5.1 Safety Design Bases

The MSIVs, individually or collectively, shall

a. Close the main steam li nes within the time establis hed by design-basis accident analysis to limit the release of reactor coolant,

b. Close the main steam line s slowly enough that simultaneous closure of all steam lines will not induce transients that exceed the nuclear system design limits,

c. Close the main steam line when required despite single failure in either valve or in the associated controls, to provide a high level of reliability for the safety

function,

d. Use separate energy sources as the motive force to clos e independently the redundant isolation valves in the individual steam lines,

e. Use local stored energy (compressed air and/or spri ngs) to close at least one isolation valve in each steam pipe line without relying on the continuity of any variety of electrical power to furnish the motive force to achieve closure,

f. Have capability to close the steam lines, either during or after seismic loadings, to ensure isolation if the nuclear system is breached, and

g. Have capability for testing during no rmal operating conditions to demonstrate that the valves will function.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-10 5.4.5.2 Description Two isolation valves are welded in a horizontal run of each of the four main steam pipes; one valve is as close as possible to the inside of the drywell a nd the other is just outside the primary containment.

Figure 5.4-9 shows an MSIV. Each is a 26-in. Y-patte rn, globe valve. Ra ted steam flow rate through each valve is 3.85 x 10 6 lb/hr. The main disc or poppet is attached to the lower end of the stem. Normal steam flow tends to close the valve, and higher inlet pressure tends to hold the valve closed. The bottom end of the valve stem closes a small pressure balancing hole in the poppet. When the hole is open, it acts as a pilot valve to relieve differential pressure forces on the poppet. Valve stem travel is suff icient to give flow ar eas past the wide open poppet approximately equal to the seat port area. The poppet travels approximately 90% of the valve stem travel to close the main disc and approximately the last 10% of travel to close the pilot hole. The air cylinder can open the poppet with a maximum differential pressure of

200 psi across the isolation valv e in a direction that tends to hold the valve closed.

A 45-degree angle permits the inlet and outlet passages to be streamlined; this minimizes pressure drop during normal steam flow and help s prevent debris blockage. The pressure drop at 105% of rated flow is 7 psi maximum. Th e valve stem penetrates the valve bonnet through a stuffing box that has Grafoil packing. To help prevent leakage through the stem packing, the poppet backseats when th e valve is fully open.

Attached to the upper end of the stem is an air cylinder that ope ns and closes the valve and a hydraulic dashpot that controls its speed. The speed is adjusted by a valve in the hydraulic return line bypassing the dashpot piston. Valve closing time is adjustable to between 3 and 10 sec.

The air cylinder is supported on the valve bonnet by actuator suppor t and spring guide shafts. Helical springs around the spring guide shafts maintain the valve in the closed position if air pressure is not available.

The valve is operated by pneuma tic pressure and by the action of compressed springs. The control unit is attached to the air cylinder. This unit contains three types of control valves that open and close the main valve and exercise it at slow speed. Remote manual switches in the control room enable the opera tor to operate the valves.

Operating air is supplied to the outboard valves from the plant air system and to the inboard valves from the containment instrument system (nitrogen). An air accumulator between the control valve and a check valve provides bac kup operating air. The outboard MSIVs will close on spring force or air cylinder pressure; the inboard valves require spring force and air pressure to close.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-11 Each valve is designed to acco mmodate saturated steam at plant operating conditions, with a moisture content of approxi mately 0.25%, an oxygen content of 30 ppm, and a hydrogen content of 4 ppm. The valves are furnished in conformance with a design pressure and temperature rating in excess of plant operati ng conditions to accommodate plant overpressure conditions.

In the worst case if the main steam line should rupture down stream of the valve, steam flow would quickly increase to 200% of rated flow. Further increase is prevented by the venturi flow restrictor inside the containment. During approximately the first 75% of closing, the valve has little effect on flow reduction because the flow is choked by the venturi restrictor. After the valve is approximately 75% closed, flow is reduced as a function of the valve area versus travel characteristic.

The design objective for the valve is a minimum of 40-years service at the specified operating conditions. Operating cycles (excluding routine exercise cycles) are estimate d to be 100 cycles per year during the first year a nd 50 cycles per year thereafter.

In addition to minimum wall thic kness required by applicable code s, a corrosion allowance of 0.120-in. minimum is added to provide for 40 years of service.

Design specification ambient conditions for normal plant operation are 135°F normal temperature, 150°F maximum temperature, 100% hum idity, in a radiation field of 15 rad/hr gamma and 25 rad/hr neutron plus gamma, conti nuous for design life. The inside valves are not continuously exposed to maximum conditions, particularly during reactor shutdown, and valves outside the primary containment and sh ielding are in ambien t conditions that are considerably less severe.

The MSIVs are designed to close under accident environmental conditions of 340°F for 1 hr at drywell design pressure. In addition, they ar e designed to remain cl osed under the following postaccident environment conditions:

a. 340°F for an additional 2 hr at drywell design pressure of 45 psig maximum,

b. 320°F for an additional 3 hr at 45 psig maximum, c. 250°F for an additional 24 hr at 25 psig maximum, and d. 200°F during the next 1 00 days at 20 psig maximum.

To resist sufficiently the response motion from the SSE, the main steam line valve installations are designed as Seismic Categor y I equipment. The valve a ssembly is manufactured to withstand the SSE forces applied at the mass center of the exte nded mass of the valve operator, assuming the cylinder/spring opera tor is cantilevered from th e valve body and the valve is located in a horizontal run of pipe. The stre sses caused by horizontal and vertical seismic forces are assumed to act simu ltaneously. The stresses in the actuator supports caused by

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-12 seismic loads are combined with the stresses caused by other live and dead loads, including the operating loads. The allowable stress for this combination of loads is based on the allowable stress set forth in applicable codes. The parts of the MSIVs that constitute a process fluid pressure boundary are designed, fabricated, inspected, and tested as required by the ASME Code Section III.

5.4.5.3 Safety Evaluation

The analysis of a comp lete, sudden steam line break outside the containment is described in Chapter 15, "Accident Analyses." The shortest cl osing time (approximately 3 sec) of the MSIVs is also shown in Chapter 15 , to be satisfactory. The switches on the valves initiate reactor scram when specific conditions (extent of valve closure, number of pipe lines included, and reactor power level) are exceeded (see Section 7.2.1.1). The ability of this 45-degree, Y-design globe valv e to close in a few sec onds after a steam line break, under conditions of high pressure differentials and flui d flows with fluid mixtures ranging from mostly steam to mostly water, ha s been demonstrated in a series of dynamic tests. A full-size, 20-in. valve was tested in a range of steam-water blowdown conditions simulating postulated accident conditions (Reference 5.4-2). The following specified hydrosta tic, leakage, and stroking te sts, as a minimum, were performed by the valve ma nufacturer in shop tests:

a. To verify valve capability to close at settings between 3 and 10 sec,

• each valve was tested at rated pres sure (1000 psig) and no flow

. The valve was stroked several times, and the closing time recorded. The valve was closed by spring only and by the combination of air cylinder and springs. The closing time is slightly greater when closure is by springs only;

b. Leakage was measured with the valve seated and backseated. The specified maximum seat leakage, using cold water at design pressure, was 2 cm 3/hr/in. of nominal valve size. In addition, an ai r seat leakage test was conducted using 50 psi pressure upstream. Maximum permissible leakage was 0.1 scfh/in. of nominal valve size. There was no visible leakage from the stem packing at hydrostatic test pressure. The valv e stem was operated a minimum of three times from the closed position to the open position, and the packing leakage was zero by visual examination;

• Response time for full closure is set prior to plant operati on for 3 sec minimum, 5 sec maximum.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-13 c. Each valve was hydrostatic ally tested in accordance w ith the requirements of the applicable edition and adde nda of the ASME Code. During valve fabrication, extensive nondestructive test s and examinations were conducted. Tests included radiographic, liquid penetran t, or magnetic particle examinations of castings, forgings, welds, hardfacings, and bolts; and

d. The spring guides and guiding of the sp ring seat member on support shafts and rigid attachment of the seat member ensure correct alignment of the actuating components. Binding of the valve poppet in the internal guides is prevented by making the poppet in the form of a cyli nder longer than its diameter and by applying stem force near the bottom of the poppet.

After the valves were installed in the nuclear system, each valve was test ed as discussed in Chapter 14 .

Two isolation valves provide redundancy in each steam line so either can perform the isolation function, and either can be tested for leakage after the other is closed. The inside valve, the outside valve, and their respective c ontrol systems are separated physically.

Electrical equipment that is a ssociated with the isolation valv es and operates in an accident environment is limited to the wiring, solenoi d valves, and position switches on the isolation valves. The expected pressure and temperature transients following an accident are discussed in Chapter 15 .

5.4.5.4 Inspection and Testing

The MSIVs can be functionally tested for ope rability during plant ope ration and refueling outage. The test provisions are listed below. During refu eling outage the MSIVs can be functionally tested, leak tested, and visually inspected.

The MSIVs can be tested and exercised indivi dually to the 90% open position, because the valves still pass rated steam flow when 90% open.

The MSIVs can also be tested and exercised indi vidually to the fully closed position if reactor power is reduced sufficiently to avoid scram fr om reactor overpressure or high flow through the steam line flow restrictors.

Leakage from the valv e stem packing will become suspect during reactor operation from measurements of leakage into th e drywell, or from observation or similar measurements in the steam tunnel.

The leak rate through the pipe line valve seats (pilot and poppet seats) can be measured accurately during shutdown by the pro cedure described in the following:

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-14 a. With the reactor at approximately 125°F and normal water level and decay heat being removed by the RHR system in th e shutdown cooling mode, all MSIVs are closed utilizing both spring force and air pressure on the operating cylinder;

b. Air from the instrument air system is introduced between the isolation valves at 25 to 26 psig. A pressure decay test or an air makeup test is used to determine combined inboard and outboard isolation valve seat leakage;

c. If combined inboard and outboard isol ation valve seat leakage is above the allowed leakage for a single isolation valve, the outboard isolation valve is then tested for seat leakage;

d. To leak-test the outboard isolation valves, the reactor vessel side of the inboard valves is pressurized to approximately the same pressure as the test pressure between the inboard and outboard valves using nitrogen gas or a hydrostatic head. A pressure decay or makeup leak test is then performed on the area between the isolation valves. This ensures essentially zero leakage through the inboard valves with test results indicating outboard va lve seat leakage. The volume between the closed valves is accurately known. Corrections for temperature variation during the test period are made to obtain the required

accuracy; and

e. At each refueling outage, the MSIVs are slow closed to verify the stem packing is not too tight. Also, the inboard MS IV containment instrument air (CIA) supply pressure boundary from the accumu lator check valve to the actuator is verified to not exceed the allowable leak rate.

Such a test and leakage measurement program ensure that the valves are operating correctly and that any leakage trend is detected.

During prestartup tests following an extensive shutdown, the valves will receive the same pressure boundary leakage or hydro tests (approximately 1000 psi) that are imposed in the primary system.

5.4.6 REACTOR CORE ISOLATION COOLING SYSTEM

5.4.6.1 Design Bases

The reactor core isolation cooling (RCIC) system initiates the discharge of a specified constant flow into the reactor vessel over a specified pressure range with in a 30-sec time interval. The RCIC water discharge into the reactor vessel varies between a temperature of 40°F up to and

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-030 5.4-15 including a temperature of 140°F. The mixture of the RCIC water and the hot steam does the following:

a. Quenches the steam,

b. Removes reactor residual heat by reducing the heat level (enthalpy) due to the temperature differential between the steam and water, and

c. Replenishes reactor vessel inventory.

The RCIC system uses an elec trical power source of high reliability, which permits operation with either onsite power or offsite power.

The steam supply to the RCIC tu rbine is automatically isolat ed on detection of abnormal conditions in the RCIC system or in RCIC equipment areas. See Section 7.4.1.1.2 . The RCIC system is neither an ECCS nor an engineered safety feature (ESF) system; however, it is included in these sections because of its similar functions. No credit (simulation) is taken in the accident analysis of Chapter 6 or 15 for its operation. However, the system is designed to initiate during plant transients that cause low reactor water level. The design bases with respect to General Design Criteria 34, 55, 56, and 57 are provided in Chapter 3 . Reactor core isolation cooling containmen t isolation valve arrangement s are described in Section 6.2. The RCIC system as noted in Table 3.2-1 is designed commensura te with the safety importance of the system and its equipment. Each componen t was individually tested to confirm compliance with system requirements. The system as a whole was tested during both the startup and preoperational phases of the plant to set a base mark for system reliability. To confirm that the system maintains this mark, functional and operability testing is performed at predetermined intervals throu ghout the life of the plant.

In addition to the automatic operational fe atures, provisions have been included for remote-manual startup, operation, and shutdown of the RCIC system, provided initiation or shutdown signals have not been act uated for startup and operation.

The RCIC system is physically located in a different quadrant of the reactor building and uses different divisional power (and se parate electrical routings) than the HPCS system. The system operates for the time intervals and the environmen tal conditions specified in Section 3.11.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-16 5.4.6.2 System Design 5.4.6.2.1 General

5.4.6.2.1.1 Description. The RCIC system consists of a turbine, pump, piping, valves, accessories, and instrumentation designed to ensure that sufficient reactor water inventory is maintained in the reactor vessel to permit adequate core cooling. This prevents reactor fuel overheating should the vessel be isolated and accompanied by loss-of-coolant flow from the reactor feedwater system. Following a reactor shutdown, steam generation will continue at a reduced rate due to the core fission product decay heat. At this time the turbine bypass system will di vert the steam to the main condenser, and the feedwater system will supply the make up water required to maintain reactor vessel inventory.

In the event the reac tor vessel is isolated and the feedwater supply is un available, relief valves are provided to automatically (or remote manually) maintain vessel pressure within desirable limits. The water level in the reactor vessel will drop due to conti nued steam generation by decay heat.

On reaching a predetermined low level, the RCIC system is initiated automatically. The RCIC turbine is driven with a portion of the decay heat steam from th e reactor and exhausts to the suppression pool. The turbine-driven pump take s suction from the condensate storage tank

(CST) during normal modes of ope ration and injects into the reactor vessel. Condensate storage tank freeze protecti on is discussed in Section 9.2.6. Since the CST is a covered tank, the water supply is not affect ed by dust storms. If the water supply from the CST becomes exhausted there is an automatic switchover to the suppression pool as the water source for the RCIC pump. This automatic sw itchover feature for RCIC cons ists of two Class 1E level switches mounted on a standpipe in the pump suc tion line. This standpi pe is located on the condensate supply line inside the reactor build ing at the reactor building/service building interface.

The standpipe is open ended and is used to indicate either a low water level condition in the CST or a loss-of-suction supply from the CST. The standpipe is desi gned, fabricated, and installed to Seismic Category I, Quality Class I, and ASME Se ction III, Class 2 standards.

The piping from the reactor building/service build ing interface to the RCIC system is Seismic Category I; each circumferential buttweld has been radiographically examined per ASME Section III, NC-5230, and a chemic al analysis has been performe d on all piping materials and as-deposited weld materials.

The inline suction reserve from the CST has sufficient volume to maintain the minimum required NPSH for the RCIC pump plus an ap proximate four-ft margin while the switchover

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-04-029 5.4-17 occurs, thus ensuring a water supply for continuous operation of the RC IC system. The CST

switchover level of 448 ft 3 in. pr ovides an additional submergen ce of 2 ft (above the top of the CST outlet pipe), which is more than ade quate to preclude vortex formation in the CST since less than 6 in. of add itional submergence for vortex pr evention is required for RCIC.

The available NPSH for worst-case operating conditions (i.e., 625 gpm rated flow, maximum water temperature) was calcula ted for the RCIC pump suction from the suppression pool and the CST. Using the conservative water temperat ure of 140°F, the NPSH available from the suppression pool is approximately 60 ft. For the CST, using 100°F water, the NPSH available is 48 ft. In both cases, the NPSH available is greater than the required NPSH of 20 ft indicated in Figure 5.4-10 for the RCIC turbine high speed setpoint of 4500 rpm.

The RCIC suction line from the su ppression pool has also been eval uated for vortex formation. The RCIC system has adequate NPSH and will not vortex unde r the conditions it would be expected to operate.

During RCIC operation, the s uppression pool acts as the heat sink for steam generated by reactor decay heat. This will re sult in a rise in pool water temp erature. Heat exchangers in the RHR system are used to ma intain pool water temperature within acceptable limits by cooling the pool water directly.

The RCIC turbine discharges in to a 10-in. exhaust pipe (see Figure 5.4-11 ), which has been installed as a sparger to prev ent flow-induced oscillations due to steam bubble formation and collapse in the suppression pool. Also, a vacuum breaker system has b een installed close to the RCIC turbine exhaust line suppression pool penetr ation to avoid siph oning water from the suppression pool into the exhaust line as steam in the line conde nses during and after turbine operation. The vacuum breaker line runs from the suppression pool air volume to the RCIC exhaust line through two norma lly open motor-operate d gate valves a nd two swing check valves arranged to allow air flow into the exhaust line and to precl ude steam flow to the suppression pool air volume. Condensate buildup in the turbine exhaust line is removed by a drain pot in the low point of the line near the turb ine exhaust connection. The condensate collected in the drain pot drains to the barometric condenser.

5.4.6.2.1.2 Diagrams. The following diagrams are included for the RCIC systems:

a. A schematic "Piping and Instrumentation Diagram" (

Figures 5.4-11 ) shows all components, piping, points where interfa ce system and subsys tems tie together and instrumentation and controls associated with subsystem and component actuation,

b. A schematic "Process Diagram" (

Figure 5.4-12) shows temperature, pressures, and flows for RCIC operation and system process data hydrau lic requirements, and COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-18 c. RCIC turbine and pump performance curves; Constant Pump Flow Figure 5.4-10 and Constant Pump Speed Figure 5.4-13 . 5.4.6.2.1.3 Interlocks . The following defines the various electrical interlocks:

a. There are four key-locked valves, RCIC-V-63 (F063), RCIC-V-8 (F008), RCIC-V-68 (F068), and RCIC-V-69 (F069

), and two key-locked resets, the "isolation resets;"

b. RCIC-V-31 (F031) limit switch acti vates when fully open and closes RCIC-V-10 (F010), RCIC-V-22 (F022), and RCIC-V-59 (F059);

c. RCIC-V-68 (F068) limit switch activate s when fully open and clears RCIC-V-45 (F045) permissive so RC IC-V-45 (F045) can open;

d. RCIC-V-45 (F045) limit switch activate s when RCIC-V-45 (F045) is not fully closed and energizes 15-sec time delay fo r low pump suction pressure trip and also initiates startup ramp function. This ramp resets each time RCIC-V-45 (F045) is closed;

e. RCIC-V-45 (F045) limits switch activates when fully closed and permits RCIC-V-4 (F004), RCIC-V-5 (F005), RCIC-V-25 (F025), and RCIC-V-26

(F026) to open and closes RCIC-V-13 (F013), RCIC-V-46 (F046) and RCIC-V-19 (F019). RCIC-V-13 (F013) and RCIC-V-46 (F046) auto open on initiation signal if RCIC-V-45 (F045) and RCIC-V-1 (F001) are open;

f. The turbine trip throttle valve RCIC-V-1 limit switch activates when fully closed and closes RCIC-V-13 (F013), RCIC-V-46 (F046) and RCIC-V-19 (F019);

g. The combined pressure switches at reactor low pressure and high drywell pressure when activated closes RCIC-V-110 a nd 113 (F080 and F086);

h. RCIC high turbine exhaust pressure, low pump suction pressure, low discharge header pressure, or an isolation signal actuates and closes the turbine trip throttle valve. When signal is cleared, the trip throttle valve must be reset from control room;

i. 125% overspeed trips both th e mechanical trip at the tu rbine and the trip throttle valve. The former is reset at the turbine and then the la ter is reset in the control room; COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-19 j. Valves RCIC-V-8 (F008), RCIC-V-63 (F063), and RCIC-V-76 (F076) automatically isolate on low reactor pressure, high turbine e xhaust line pressure, high ambient temperature in RCIC equipment areas (leak de tection) and high turbine steam supply flow rate (>300% - break detection). A setpoint of 300%

for break isolation provides sufficient operating margin to prevent inadvertent isolations due to startup tr ansients and yet is low e nough to detect large pipe breaks. Small breaks are detected by the leak detection system. Steam condensing supply valv e RCIC-V-64 (F064) has been lo ck closed as a part of the steam condensing mode deactivation. Note, the key-lo cked switches for RCIC-V-8 (F008) and RCIC-V-63 (F063) do not prevent automatic isolation of these valves. The key-locked switche s are provided to prevent inadvertent manual isolation of the RCIC steam supply during system operation;

k. An initiation signal opens RCIC-V-10 (F010) if closed, RCIC-V-45 (F045), and RCIC-V-46 (F046) if RCIC-V-1 and RC IC-V-45 (F045) are not closed. The initiation signal also starts barometric condenser vacuum pump; and closes RCIC-V-22 (F022) and RCIC

-V-59 (F059) if open;

l. The combined signal of low flow plus high discharge pressure opens and with increased flow closes RCIC-V-19 (F 019). Also see items e and f above;

m. The signal of in-line reserve tank low water level opens valve RCIC-V-31 (F031);

n. High reactor water level closes RCIC-V-45 (F045); and

o. Main turbine trips if RCIC

-V-13 and RCIC-V-45 are open.

5.4.6.2.2 Equipment and Component Description

5.4.6.2.2.1 Design Conditions . Operating parameters for the components of the RCIC systems defined in the following are shown in Figure 5.4-12 .

a. One 100% capacity tu rbine and accessories,

b. One 100% capacity pump a ssembly and accessories, and

c. Piping, valves, a nd instrumentation for

1. Steam supply to the turbine,

2. Turbine exhaust to the suppression pool,

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-20 3. Makeup supply from the CST to the pump suction,

4. Makeup supply from the suppre ssion pool to the pump suction, and

5. Pump discharge to the head cooling spray nozzle, incl uding a test line to the CST, a minimum flow bypass line to the suppression pool, and a coolant water supply to accessory equipment.

5.4.6.2.2.2 De sign Parameters. Design parameter for the RCIC system components are listed below. See Figure 5.4-11 for cross reference of com ponent numbers listed below:

a. RCIC pump operation RCIC-P-1 (C001) (Reference to Figures 5.4-11 and 5.4-13) Flow rate Injection flow - 600 gpm Lube oil cooling water flow 25 gpm

Total pump discharge - 625 gpm

(includes no margin for pump wear) Water temperature range 40°F to 140°F NPSH 21 ft minimum Developed head 3016 ft @ 1225 psia reactor pressure 610 ft @ 165 psia reactor pressure BHP, not to exceed 761 HP @ 3016 ft developed head 130 HP @ 610 ft developed head Design pressure 1500 psia Design temperature 40°F to 140°F

b. RCIC turbine operation RCIC-DT-1 (C002)

HP condition LP condition Reactor pressure (saturation temperature) 1225 psia 165 psia Steam inlet pressure 1210 psia 150 psia Turbine exhaust press 15 to 25 psia 15 to 25 psia Design inlet pressure 1265 ps ia + saturated temperature Design exhaust pressure 165 ps ia + saturated temperature

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-21 c. RCIC orifice sizing Coolant loop orifice Sized with piping arrangement to ensure RCIC-RO-9 (D009) maximum pressure of 75 psia at the lube oil cooler inlet and a minimum pressure of 45 psia at the spray nozzles at the barometric condenser

Minimum flow orifice Sized with piping arrangement to ensure RCIC-RO-5 (D005) minimum flow of 100 gpm with RCIC-V-19 (MO-F019) fully open

Test return orifice Sized with piping arrangement to simulate RCIC-RO-6 (D006) pump discharge pressure required when the RCIC system is injecting design flow with the reactor vessel pressure at 165 psia

Leak-off orifices Sized for 1/8-in. diameter minimum, RCIC-RO-8 and RCIC-RO-10 3/16-in. diameter maximum (D008 and D010)

Minimum flow orifice Sized to maintain a minimum flow of RCIC-RO-11 (D011) 60 gpm thro ugh the RCIC water leg pump (RCIC-P-3) while maintaining a positive pressure in the RCIC system at the highest elevation

d. Valve operation requirements NOTE: Differential pressures listed in the following were obtained from the RCIC system design specification data sheet and are listed for information. Detailed differential pressure requi rements are contained in engineering calculations.

Steam supply valve Open and/or close against full steam RCIC-V-45 (F045) pressure Pump discharge valve Open and/or close against full pump RCIC-V-13 (F013) discharge pre ssure and open in thermal over-pressure conditions in the RCIC

discharge header

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-22 Pump minimum flow bypass Open and/or close against full pump valve RCIC-V-19 (F019) discharge pressure

Steam supply isolation valves Open and/or close against full differential RCIC-V-08/RCIC-V-63 (F008) pressure of 1210 psi Turbine lube oil/cooling Capa ble of maintain ing constant water pressure control downs tream pressure of 75 psia valve RCIC-PCV-15 (F015) through lube oil cooler Pump discharge header relief 1500 ps ig relief setting; less than 1 gpm valve (RCIC-RV-3) required capacity; the maximum allowable discharge is less than 20 gpm

Pump suction relief valve 122 psig relief setting; 20 gpm required RCIC-RV-17 (F017) capacity

Cooling water relief Sized to prevent overpressurization of valve (RCIC-RV-19T) piping valves and equipment in the turbine lube oil coolant loop in the event of failure of pressure control valve RCIC-PCV-15 (F015). Set pressure is 99 psig; required flow is 33.1 gpm

Pump test return valve Qualifie d to open, close, and throttle RCIC-V-22 (F022) against full pump discharge pressure

Pump test return valve Qualified to close (not open) against full RCIC-V-59 (F059) pump discharge pressure

Relief valve barometric Relief valve is capable of retaining condenser vacuum tank 10 in. of mercury vacuum at 140 °F RCIC-RV-33 (F033) ambient, with a set pressure of 6 psig; required flow is 20 gpm Pump suction valve Located as close as practical to the suppression pool primary containment RCIC-V-31 (F031)

Pump suction valve Open and/or close against full suction condensate storage head from the condensate storage tank tank RCIC-V-10 (F010)

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-23 Main pump discharge System test mode bypasses this valve. check valve Its functional capability is demonstrated RCIC-V-65/RCIC-V-66 separately (F065/F066)

Warm-up line Valve will open and/or close against full isolation valve steam pressure

RCIC-V-76 (F076)

Vacuum breaker isolation Valves will open and/or close against valves RCIC-V-110 (F080) tu rbine exhaust pressure and RCIC-V-113 (F086)

e. Rupture disc

Assemblies Utilized for tu rbine casing protection, RCIC-RD-1/RCIC-RD-2 includes a mated vacuum support to (D001/D002) prevent rupture disc reversing under

vacuum conditions

Rupture pressure 150 psig +/- 10 psig Flow capacity 60,000 lb/hr @ 165 psig

f. Condensate storage requirements

Total reserve storage for reactor pr essure valve make up is 135,000 gal.

g. Piping RCIC water temperature

The maximum water temperature range fo r continuous system operation will not exceed 140°F. However, due to poten tial short-term operation at higher temperatures, piping de sign is based on 170°F.

h. Turbine exhaust vertical reaction force Unbalanced pressure due to opening and discharge under the suppression pool water level is 20 psi.

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-11-039 5.4-24 i. Ambient conditions Relative Temperature Humidity Normal plant operations 60F to 100°F 95% Isolation conditions 148°F 100%

j. Water leg pump Design pressure 150 psig Design temperature 212°F Capacity 25 gpm @ 200 ft total head

k. Barometric condenser Design pressure 50 psig Design temperature 650°F

l. Vacuum tank Design pressure 15 psig Design temperature 212°F

m. Condensate pump Design pressure 50 psig Design temperature 650°F Capacity 23 gpm @ 10 in. Hg vac., 70°F 50 psig discharge

n. Turbine and steam supply drain pots Design pressure 1250 psig Design temperature 575°F

o. Turbine governing a nd trip throttle valves Design pressure 1250 psig Design temperature 575°F

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-056 5.4-25 p. Pump suction strainers in the suppression pool The suction strainers have been procured to the following specifications: Primary service rating: ANSI 1501-1

Quality Class I

Seismic Category I

Cleanliness Class B

Applicable Code: Strainer materi als and fabrication meets ASME Section III, Class 2 requi rements. The "N" stamp is not be applied sin ce the strainers cannot be hydrostatically tested. Materials: Strainer body is stainless steel 304 or 316, or engineer approved equal, suitable for submergence in high quality water during a 40-year lifetime. Quantity: 2

Diameter: 13.5 in.

Length: 5.25 in.

Rated flow: 300 gpm (per strainer)

The strainers are cyli ndrical, as shown in Figure 5.4-14 . Strainer hole diameter is 0.09375 in. Strainers are attached to ANSI 150# RF Flanges.

Head loss is limited to 4 ft of water assuming the strainers are 50% clogged and the water

temperature is 220°F. 5.4.6.2.2.3 Overpressure Protection . Referring to Figure 5.4-11, four RCIC pipe lines have a low design pressure and, ther efore, require relief devices or some other basis for addressing overpressure protection.

The design pressure of the other major pipe lin es is equal to the vessel design pressure and subject to the normal overpressure protection syst em. In addition, the RCIC discharge header

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-056 5.4-26 has a relief valve, RCIC-RV-3, to protect against thermal overpressurization when the system is in standby mode, isolated from the reactor. Below are the overpressure protection ba ses for the low pressure piping lines.

a. RCIC pump suction line

A relief valve [RCIC-RV-17 (F017)] is located on the pump suction line in Figure 5.4-11 to accommodate any potential leakage through the isolation valves [RCIC-V-13 (F013) and RCIC-V-66 (F066)]. A high pump suction pressure alarm is provided in the control room.

b. RCIC turbine exhaust line

This line is normally vented to the suppression pool and is not subject to reactor pressure during normal operation. Rupture discs RCIC-RD-1 (D001) and RCIC-RD-2 (D002), as shown in Figure 5.4-11, are installed on this line to prevent exceeding piping design pressure should the exhaust line isolation valve RCIC-V-68 (F068) be closed when the RC IC turbine is operating. The RCIC system will automatically isolate if the rupture discs were to blow open.

c. Portions of the RCIC minimum flow line downstream of RCIC-V-19 (F019)

This line is normally vent ed to the suppression pool and is separated from reactor pressure by the pump discharge isolation valves [RCIC-V-13, RCIC-V-65, and RCIC-V-66 (F013, F065, and F066)], pump discharge check valve RCIC-V-90, and one additional nor mally closed isolation valve in the minimum flow line [RCIC-V-19 (F019)] as shown in Figure 5.4-11 .

d. Portions of the RCIC cooling water line downstr eam of RCIC-PCV-15 (F015)

In the standby condition this line is separated from r eactor pressure by the pump discharge valves [RCIC-V-13, RCIC-V -65, and RCIC-V-66 (F013, F065 and F066)], pump discharge check valve RCIC-V-90, and one additional normally closed shut-off valve in the cooling water line [RCIC-V-46 (F046)] as shown in Figure 5.4-11 . During system operation a reli ef valve [RCIC-RV-19T (F018)] is provided to prevent overpressurizing piping, valves, and equipment in the coolant loop in the event of failure of pressure control valve RCIC-PCV-15 (F015) as shown in Figure 5.4-11 . COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-04-027 5.4-27 5.4.6.2.3 Applicable C odes and Classifications

The RCIC system components within the drywell up to and including the outer isolation valve are designed in accordance with ASME Code Section III, Class 1, Nuclear Power Plant Components. Safety-related portions of the RCIC system are Seismic Category 1.

The RCIC system component classifications a nd those for the condensat e storage system are given in Table 3.2-1 . 5.4.6.2.4 System Reliability Considerations

To ensure that the RCIC will operate when necess ary, the power supply for the system is taken from immediately available energy sources of hi gh reliability. Added assurance is given by the capability for periodic testing during station operation. Evaluation of reliability of the instrumentation for the RCIC shows that no failure of a single initiating sensor either prevents or falsely star ts the system.

To ensure RCIC availability for the operational events noted previously, the following are considered in the system design.

a. The RCIC and HPCS are located in differe nt quadrants of the reactor building.

Piping runs are separated and the water delivered from each system enters the reactor vessel via different nozzles.

b. Prime mover independence is achieved by using a steam turbine to drive the RCIC and an electric motor-driven pump for the HPCS system.

c. The RCIC and HPCS control independence is secured by using different battery systems to provide control power to each system for sy stem operation. Separate detection initiation logic is used for each system.

d. Both systems are designed to meet a ppropriate safety and quality class requirements. Environment in the equipment rooms is maintained by separate auxiliary systems.

e. A design flow functional test of the RCIC is performed during plant operation by taking suction from the CST and discharg ing through the full flow test return line back to the CST.

The discharge valve to the head-spray line remains closed during the test, and reactor operation is undisturbed. All components of the RCIC system are capable of individual functional testing during normal plant operation. Control system design provides automatic return from test to

operating mode if system initiation is required. The three exceptions are as follows: COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-04-027 5.4-28 1. The auto/manual station on the flow controller. This feature is required for operator flexibility during system operation.

2. Steam inboard/outboard isolation valves. Closur e of either or both of these valves requires operator action to properly sequence their opening. An alarm sounds when either of th ese valves leaves the fully open position.

3. Bypassed or other delib erately rendered inoperabl e parts of the system are automatically indicated in the control room.

f. Periodic inspections and maintenance of the turbine-pump unit are conducted in accordance with manufacturer's instructions. Valve position indication and instrumentation alarms are displayed in the control room.

g. Specific operating procedures relieve the possibility of thermal shock or water hammer to the steam line, valve seals, and discs. Key lock switches are provided for positive administrative control of valve position. Operating procedures require throttling open the outboard isolation valve RCIC-V-8 to

remove any condensate tra pped between the isolation valves, warming up the steam line by throttling open the warmup valve RCIC-V-76 located on a pipe line bypassing the inboard isolation va lve, and then opening the inboard isolation valve RCIC-V-63. All the condensate is removed from the steam supply line by a drain pot located at the lowest point. An alarm sounds when any of these valves leaves the fully open position.

h. Emergency procedures address the opera tion of RCIC during a station blackout (SBO) event. The RCIC keepfill pump, RCIC-P-3, is powered by a Class 1E ac source, and will be unavailable during an SBO. Upon loss of ac power, the operator manually initiates RCIC. RCIC may be used during an SBO event by maintaining the RCIC discharge header continuously pressurized. The system can be operated in th is manner without its keepfill function.

5.4.6.2.5 System Operation 5.4.6.2.5.1 Auto matic Operation . Automatic startup or restart (after level 8 shutdown) of the RCIC system due to an initiation signal from reactor low water level requires no operator action. To permit this automa tic operation, Technical Specifications operability requirements ensure that all necessary components are available to perfor m their required functions. In addition, the following are periodically verified:

a. The flow controller has the correct flow setpoint and is in automatic mode; COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-030 5.4-29 b. Each RCIC manual, power-operated, and automatic valv e in the flow path that is not locked, sealed, or otherwise secure d in position, is in the correct position; and

c. The RCIC system piping is filled with water from the pump discharge valve to the injection valve.

The turbine is equipped with a mechanical overspeed trip. The mechanical overspeed trip must be reset out of the control room at the turbine itself. Once the mechanical overspeed trip is reset, the trip throttle valve can be reset.

RCIC System Operation and Shutdown:

During extended periods of opera tion and when the normal water level is again reached, the HPCS system may be manually tripped and the RCIC system flow controller may be adjusted

and switched to manual operation. This prevents unnecessary cycling of the two systems. The RCIC flow to the vessel is controlled by adjus ting flow to the amount necessary to maintain vessel level. Subsequent starts of RCIC will occur automatically if the water leve l decreases to the low level initiation point (Le vel 2) following a high level shutdown (Level 8). Should RCIC flow be inadequate, HPCS flow will automatically initiate.

RCIC flow may be directed away from the vessel by diverting the pump discharge to the CST.

This is accomplished by closi ng injection valve RCIC -V-13 and opening the test return valves (RCIC-V-22 and 59). The system is returned to injection mode by closing RCIC-V-59 or RCIC-V-22 and then opening RCIC-V-13. This mode of operation w ill not be used during events where an unacceptable source term is identified in primary containment. Diverting RCIC flow to the CST is not a safety-related function nor does it affect the ability of RCIC to initiate during plant transients. The system automatically switc hes to injection mode if the water level decreases to the low level initiation point (Level 2).

When RCIC operation is no longer required, the RCIC system is manually tripped and returned to standby conditions.

5.4.6.2.5.2 Test Loop Oper ation. This operating mode (described in Section 5.4.6.2.4 ) is conducted by manual oper ation of the system.

5.4.6.2.5.3 Steam Condensing (Hot Standby) Operation. Th e steam condensing mode of RHR for Columbia Generating Station has been deactivated. However, the major pieces of equipment are installed with the exception of the steam supp ly relief valves and are shown on the RCIC and RHR piping and instrumentation diagrams (P&IDs) ( Figures 5.4-11 and 5.4-15, respectively). Deletion of this mode of operation for RCIC and RHR will not adversely affect either system's capability to bring the reactor to cold shutdown.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-08-000 5.4-30 5.4.6.2.5.4 Manual Actions. The RCIC system w ill automatically initiate and inj ect into the reactor when the reactor water level drops to a low level (L2, -50 in.). No manual actions are required to operate the system. However, control room oper ators can manually initiate the system prior to reaching the low level.

5.4.6.2.5.5 Reactor Core Isolati on Cooling Discharge Line Fill System . See Section 6.3.2.2.5. The description in this section is also applicable to the RCIC line fill system. 5.4.6.3 Performance Evaluation

The RCIC system makeup capacity is sufficient to avoid th e need for ECCS for normal shutdowns and shutdowns resulting from anticipated operational occurrences.

5.4.6.4 Preoperational Testing

The preoperational and initial startup test program for the RC IC system is presented in Chapter 14 . Regulatory Guide 1.68 complia nce is described in Section 1.8. 5.4.6.5 Safety Interfaces

The balance-of-plant/GE nuclear steam supply system safety inte rfaces for the RCIC system are (a) preferred water supply from the CST, (b) all associated wire, ca ble, piping, sensors, and valves that lie outside the nuclear steam supply system scope of supply, a nd (c) air supply for testable check and so lenoid-actuated valve(s).

5.4.7 RESIDUAL HEAT REMOVAL SYSTEM

5.4.7.1 Design Bases

The RHR system is comprised of three inde pendent loops. Each loop contains its own motor-driven pump, piping, valv es, instrumentation, and contro ls. Each loop has a suction source from the suppression pool an d is capable of disc harging water to the reactor vessel via a separate nozzle, or back to th e suppression pool via a se parate suppressi on pool return line. In addition, the A and B loops have heat exchange rs which are cooled by standby service water. Loops A and B can also take suction from the RRC suction and can discharge into the reactor recirculation discharge or to the suppression pool and drywell spray spargers. Spool-piece

interties are available to permit the RHR heat exchangers to be used to supplement the cooling capacity of the fuel pool coo ling (FPC) system (see Section 9.1.3 for details). A spool piece intertie was also used to provi de a preoperational flus hing path for the low-pressure core spray (LPCS). The A and B loops also have connections to the RCIC steam line. However, these are not used because the steam conde nsing mode has been eliminated.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009 5.4-31 5.4.7.1.1 Functional Design Basis

The RHR system is designed to restore and mainta in the coolant inventory in the reactor vessel and to provide primary system decay heat removal followi ng reactor shutdown for both normal and postaccident conditions. The primary desi gn operating modes associated with performing these functions are briefl y described as follows:

a. Low-pressure coolant injection (LPC I) mode - The RHR sy stem automatically initiates into this mode a nd pumps suppression pool water into separate lines and core flooder nozzles for injection into the core region of the reactor vessel following a LOCA. The system's LPCI mode operates in c onjunction with the other ECCS to provide ad equate core cooling fo r all design basis LOCA conditions.

The functional design bases for the LPCI mode is to pump a total of 7450 gpm of water per loop using the separate pump loops from the suppression pool into the core region of the vessel when there is a 26 psi differential between reactor pressure and the pressure of the suppression pool air volume. Injection flow commences at 225 psid vessel pressure above drywell pressure.

The initiating signals are ve ssel level 1, 32 in. above the active core or drywell pressure equal to 2.0 psig. The pumps will attain rated speed in 27 sec and injection valves fully open in 46 sec.

These original LPCI mode performance capabilities bound the power uprate conditions and ensure adequate core c ooling can be provided following a LOCA at uprated power conditions;

b. Suppression pool cooling (SPC) and containment spra y cooling (CSC) modes - The RHR system's SPC and CSC mode s provide heat removal from the suppression pool and containment by pumping suppression pool water through the system's heat exchangers and discharg ing the water either directly back to the suppression pool (i.e., in the SPC m ode) or discharging the water to the wetwell and drywell spray sp argers (i.e., in the CSC mode) where the water is then returned, by drainage, back to the suppression pool. These modes of operation are designed to provide cooling to maintain containment and suppression pool temperatures and pre ssures following ma jor transients. Suppression pool cooling is manually initiated by the ope rator; however, at least one RHR loop is placed in the SPC mode to maintain suppression pool temperature <

110°F. The drywell spray func tion removes radioactive fission products from the containment atmos phere during a LOCA and is manually initiated within 15 minutes after the event occurs; COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-32 c. Shutdown cooling mode - The RHR sy stem's normal shutdo wn cooling mode removes reactor core decay and sensible heat from the primary reactor system to permit refueling and servicing. This heat removal function is initiated manually after the reactor pressure has been reduced to less than 48 psig (295°F) by discharge of steam to the main condenser. This mode of operation provides the capability to cool down the reactor under controlled conditions with minimal availability impact. Refer to Section 5.4.7.3.1 for shutdown cooling time to reach 212°F;

d. Alternate shutdown cooling mode - The RHR system's alternate shutdown cooling mode is utilized during normal plant operation and design basis events when the normal shutdown c ooling mode is not availabl e to remove reactor core decay and sensible heat. This heat removal function is safety related, initiated manually and pumps suppressi on pool water into the co re and allows the water to return to the suppression pool through the SRVs. The design objective of this mode (as established by Re gulatory Guide 1.139) is to reach cold shutdown within 36 hrs and to meet the requirements of GDC 34;

e. Fuel pool cooling mode - During normal plant shutdown, when the reactor vessel head has been remove d, the RHR system is designed to be capable of being aligned to assist th e FPC and cleanup system in maintaining the fuel pool temperature within acceptable limits. In this mode the system is designed to cool water drawn from the fuel pool by passing it through an RHR system heat

exchanger and then discharge th e water back to the fuel pool;

f. Minimum flow bypass mode - The RHR system minimum flow bypass mode is designed to provide cooling for the RHR pumps during a small break LOCA that does not result in rapid reactor ve ssel depressurization to below the RHR system shutoff discharge pr essure. This mode cool s the pumps by providing a pump flow return line to the suppre ssion pool that allows sufficient pump cooling flow to return to the pool until flow in the main discharge line is sufficient to provide adequa te pump cooling. When fl ow in the main discharge lines is sufficient for cooling of the pumps, motor-operated valves in the

minimum flow bypass line to the suppressi on pool automatically close so that all of the system's flow is directed into the main discharge lines;

g. Standby mode - During normal power operation the RHR system is required to be available for the LPCI mode in the event a LOCA occurs. The system is normally maintained in the standby mode. In this mode the system is aligned with the pumps' suction from the suppre ssion pool and all othe r valves aligned so that only the injection valves are required to open and the RHR pumps started for LPCI flow to be delivered to the reactor fo llowing depressurization.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-33 Until adequate flow is esta blished, the RHR pumps are cooled automatically by flow through the minimum flow valves;

h. Reactor steam condensing mode - The reactor steam condens ing mode has been deactivated and will no longer be utilized for CGS. No credit has been taken for the steam condensing mode in any safety analysis; and

i. The potential for exceeding the 100°F/

hr cooldown limit during the cooldown mode is minimized by precautions and limitations in the appropriate operating procedures.

5.4.7.1.2 Design Basis for Isolation of Residual Heat Removal System from Reactor Coolant System

Interlocks are provided to inhi bit shutdown cooling mode alignment whenever reactor pressure is above the design pressure of the low pressu re portions of the RHR system (approximately 135 psig).

The low pressure portions of the RHR system are isolated from full reactor pressure whenever the primary system pressure is above the RHR system design pr essure. The minimum pressure above which LPCI protection is required is below the design pr essure of the low pressure portions of the RHR system. These interlocks also provide protection of the low pressure portions of the RHR system. These interlocks ca n be reset when pressure has been reduced to approximately 135 psig. The LPCI injection valves are interlocked to prevent opening when reactor pressure is above appr oximately 460 psig, which also pr ovides protection for the low pressure portions of the RHR system. In add ition, automatic isolation may occur for reasons of vessel water inventory retention which is unrelated to piping pressure ratings. See Section 5.2.5 for an explanation of the leak dete ction system and the isolation signals.

The RHR pumps are protected against damage from a closed discharge valve by means of automatic minimum flow valves, which open when the main line flow is low and close when the main line flow is greater than the setpoint specified in the Technical Specifications.

5.4.7.1.3 Design Basis for Pressure Relief Capacity The relief valves in the RHR system are sized for one or both of the following bases:

a. Thermal relief, b. Valve bypass leakage

Relief valves are set to ensure that the design pressure pl us 10% accumulation is not exceeded anywhere in the system being protected. A check valve, RHR-V-209, is installed across

RHR-V-9 to prevent thermal overpressuri zation between RHR-V-8 and RHR-V-9. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-34 The relief valves protecting the RHR system are listed below (see Figure 5.4-15 ): Relief Valve Nominal Setpoint (psig) Required Capacity (gpm) Piping Location Design Pressure (psig) RHR-RV-88A 205 1 RHR pump suction 220 (loop A) RHR-RV-88B 205 1 from suppression 220 (loop B) RHR-RV-88C 110 1 pool 125 (loop C) RHR-RV-5 183 1 RHR pump suction from recirculation pipe 220 RHR-RV-25A 487 1 RHR discharge 500

RHR-RV-25B 488 1 RHR discharge 500

RHR-RV-25C 493 1 RHR discharge 500 RHR-RV-30 103 1 RHR flush line to radwaste 125 RHR-RV-36

• All RHR relief valves are purchased to ASME S ection III, Class 2, requi rements to match the requirements of the piping they are protecting. As such, the setpoi nt tolerance is plus or minus 3% for setpoints above 70 psi per ASME Section III, Paragraph NC-7600.

Pressure buildups in isolated lines will be slow and discharges from relief valves on these lines will be small. Water hammer and other hydrodyna mic loads are not considered a potential problem in RHR relief valve piping.

Redundant interlocks prevent ope ning valves to the low-pressu re suction piping when the reactor pressure is above the shutdown range. These same interlocks initiate valve closure on increasing reactor pressure.

A pressure interlock prevents connecting the discharge piping to the primary system whenever the primary pressure is greater than the design value. In add ition a high-pressure check valve will close to prevent reverse fl ow if the pressure should increase. Relief valves in the discharge piping are sized to account for leakage past the check valve. The RHR cooling system is connected to hi gher pressure piping at (a) shutdown cooling suction, (b) shutdown cooling return, (c) LPCI injection, and (d) head spray. The vulnerability to overpressurization of each location is discussed in the following paragraphs:

• RHR-RV-36 has been permanently removed from Columbia Generating Station. It has been replaced with a blind-flanged "Testable Pipe Spool Assembly," RHR-TPSA-1.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-35 The shutdown cooling suction pipi ng has two gate valves (RHR-V -8 and RHR-V-9) in series which have independent pressure interlocks to prevent opening at high reactor pressure. No

single active failure or operator error will result in overpressuri zation of the lower pressure piping. With the RHR pumps normally lin ed up to the suppression pool (RHR-V-6A and RHR-V-6B closed), the shutdown cooling suction line is protected from thermal expansion or from leakage past RHR-V-8 by RHR-RV-5. A bypass around RHR-V-6A may also be used to route leakage past RHR-V-8 and RHR-V-9 to the suppression pool. With all the RHR suction

valves closed, the suction piping is protected from thermal expansion or leakage past the discharge check valves by RHR-RV-88A, RHR-RV-88B, and RHR-RV-88C. When the bypass around RHR-V-6A is not in service, it will be isolated usi ng a single valve. This will allow the installed relief valves discussed above to protect the bypass piping.

The shutdown cooling return line has swing check valves (RHR-V-50A and RHR-V-50B) to protect it from higher vessel pressures. Additionally, a gate valve (RHR-V-53A and RHR-V-53B) is located in series and has a pressure interlock to prevent opening at high reactor pressures. No single active fa ilure or operator error will result in overpressurization of the lower pressure piping.

Each LPCI injection line has a swing check valve (RHR-V-41A, RHR-V-41B, and RHR-V-41C) to protect it from higher vessel pressures. Additionally, a gate valve (RHR-V-42A, RHR-V-42B, and RHR-V-42C) is locate d in series and has pressure interlocks to prevent opening at high reactor vessel pressure. No single active failu re or operator error will result in overpressurization of the lower pressure piping.

The head spray piping ha s three swing check valv es in series [two belonging to the RCIC system and one (RHR-V-19) belonging to the RHR system], to protect it from higher vessel pressures. Two of the swing check valves ha ve air operators but ar e only capable of opening the testable check va lve if the differential pressure is less than 5.0 psid. Additionally, a globe valve (RHR-V-23) is located in series and has a pressure interlock to prevent opening at high reactor pressures. No single active failure or operator error will result in the overpressurization of the lower pressure piping.

Overpressurization protection of the RHR discharge piping for therma l expansion or from leakage past the head spray, shutdown injection, and LPCI isolation va lves is provided by RHR-RV-25A, RHR-RV-25B, and RHR-RV-25C.

The RHR drain system to radwaste is protected from thermal expansion or from leakage past the isolation valves RHR-V-71A, RHR-V-71B, RHR-V-71C, RHR-V-72A, RHR-V-72B, and RHR-V-72C by RHR-RV-30.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-36 5.4.7.1.4 Design Basis With Resp ect to General Design Criterion 5 The RHR system for this unit doe s not share equipment or struct ures with any other nuclear unit.

5.4.7.1.5 Design Basis for Reliability and Operability

The design basis for the shutdown cooling modes of the RHR system is that these modes are controlled by the operator from the control r oom. The operations performed outside of the control room using the normal shutdown is manual operation of a local flushing water admission valve, which is the means of ensuring that the suc tion line of the shutdown portions of the RHR system is filled and vented. In addition, the 0.75-in. bypass around RHR-V-6A would be isolated if necessary.

Two modes of operation provide the shutdown cooling function for the RHR system. One mode, the normal Shutdown Cooling Mode, is the preferred operational mode. Although preferred, this mode of RHR does not meet the redundancy and single fa ilure requirements of IEEE 279 and 10 CFR 50 Appendix A, GDC 34. As a result, a second shutdown cooling mode, the Alternate Shutdown Cooling Mode, is provided and is the shutdown cooling mode credited to meet the requirements of IEEE 279 a nd GDC 34. This mode is safety related, Quality Class 1, Seismic Cate gory 1, redundant and single failure proof. Since the normal Shutdown Cooling Mode of RHR is preferre d for CGS, the components required for the operation of this mode are maintained as safety related, Quality Class 1.

For the normal shutdown cooling mode, two separate shutdown cooling loops are provided. The reactor coolant temperature can be brought to 212°F in less than 36 hr with only one loop in operation. With the exception of the shutdown suction including the reactor recirculation loop suction and discharge valves, and shutdown return, the entir e RHR system is safety grade and redundant, is part of the ECCS and containment cooling syst ems, and is designed with the flooding protection, piping protection, power separation, etc., requi red of such systems. See

Section 6.3 for an explanation of the design bases for ECCS systems. Shutdown cooling suction and discharge valves are required to be powered from both offsite and standby emergency power for purposes of isolation and shutdown following a loss of offsite power. In the event that the outboard shutdown cooling suction supply valve (RHR-V-8) fails to open from the control room, an operator ma y be sent to open the valve by hand.

If the attempt to open the outboard valve proves unsuccessful, or the inboard shutdown cooling suction supply valve (RHR-V-9) fails to open, the operator will establish the alternate shutdown cooling mode path as described in the notes to Figure 15.2-10, Activity C1 or C2.

For the alternate shutdown cooli ng mode, if vessel depressuri zation were to be achieved by manual actuation of relief valves, three valves would need to be actuated to pass sufficient steam flow to depressurize the vessel.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-37 Low-pressure liquid flow test results are presented in NED E-24988-P. This test program adequately demonstrated the ability to use SR Vs in the alternate shutdown cooling mode.

Following reactor depressurization (i.e., 100°F/hr), an alternate shutdown coolant flow rate of 2600 gpm would be required to bring the reactor to a shutdown condition. This flow capacity can be achieved by using one AD S valve. However, three valves are always available.

Calculations demonstrate that in the alternate shutdown cooling mode, with one RHR pump in operation, the total system resist ance head is 550 ft using one SR V valve. At this calculated head, the pump capacity is 4000 gpm and the reactor pressure is 160 psig.

The air supply for the ADS valves is discussed in Sections 5.2.2, 6.2.2, and 7.3.1. 5.4.7.1.6 Design Basis for Prot ection from Physical Damage

The RHR system is designe d to the requirements of Table 3.2-1. With the exception of the common shutdown cooling line, redundant com ponents of the RHR system are physically located in different quadrants of the reactor building, and ar e supplied from independent and redundant electrical divisions. Further discussion on protecti on from physical damage is provided in Section 6.3. 5.4.7.2 Systems Design

5.4.7.2.1 System Diagrams

All of the components of the RHR system are shown in Figure 5.4-15 . A description of the controls and instrumentati on is presented in Section 7.3.1.1.1 . A process diagram and pro cess data are shown in Figures 5.4-16 and 5.4-17. All of the sizing modes of the system are shown in the process data. The functional control diagram for the RHR system is shown in Figure 7.3-10 . Interlocks are provided (a) to prevent draining vessel water to the suppression pool, (b) to prevent opening vessel suction va lves above the suction line de sign pressure, or above the discharge line design pressure with the pum p operating at shutoff head, (c) to prevent inadvertent opening of drywell spray valves, and (d) to prevent pump start when suction valve(s) are not open. This interlock is defeated for the RHR FPC assist mode (see Section 9.1.3).

The RHR system may be used to supplement the cooling capacity of the FPC system. This mode requires the installation of spool pieces and the opening of normally locked closed valves (see Section 9.1.3.2 for details).

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-38 The normal shutdown cooling mode of RHR loop B can be aligned to return a portion of the cooling flow back into the reactor ve ssel via the RCIC head spray nozzle.

The LPCS system may be cross tied with the RHR system to prov ide a flow path from the CST to the LPCS system via RHR. This preoperational alignment provided clean water to the LPCS system during flushing and provided a flowpath to the vesse l for the core spray sparger test. This spoolpiece is not expected to be used again during the lifetime of the plant. The administrative controls used for these spoolpieces, interlocks , and valves are procedurally regulated to ensure pr oper system function. 5.4.7.2.2 Equipment and Component Description

a. System main pumps The RHR main system pumps are mo tor-driven deepwell pumps with mechanical seals. The pumps are sized on the basis of the LPCI mode (modes A1 and A2, see Figure 5.4-17

). Design pressure for the pump suction structure is 220 psig with a temperatur e range from 40°F to 360°F. Design pressure for the pump discharge structur e is 500 psig. The bases for the design temperature and pressure are maximum shutdown cut-in pressures and temperature, minimum ambient temperature, and maximum shutoff head. The pump housing is carbon st eel and the shaft is stainless steel. System configuration (elevation, piping design, etc.) ensures that minimum pump NPSH

requirements are met with margin. Figures 5.4-18 through 5.4-20 are the actual pump performance curves.

The RHR pumps are designed for the life of the plant (40 years) and tested for operability assurance and performance as follows:

1. In-shop tests, including: (a) hydrosta tic tests of pressu re retaining parts at 1.5 times the design pressure, (b) performance tests to determine the total developed head at zero flow and design flow, and (c) NPSH requirements.

2. After the pumps were installed in the plant, they underwent (a) the system hydro test, (b) fu nctional tests, (c) peri odic testing to verify operability in accordance with the Inservice Testing (IST) Program Plan, and (d) about 1 month of operation each year for a refueling shutdown (shutdown operation time has been re duced coincident with reduced outage times).

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-39 3. In addition, the pumps are designed for a postulated single operation of 3 to 6 months for one accident during the 40 year life of the plant.

A listing of GE operating e xperience of Ingersoll-Rand RHR pumps is provided in Tables 5.4-3 and 5.4-4. b. Heat exchangers The RHR system heat exchangers are sized on the basis of the duty for the shutdown cooling mode (mode E of the Process Data). All other uses of these exchangers require less cooling surface. Flow rates are 7450 gpm (rated) on the sh ell side and 7400 gpm (rated) on the tube side (service water side). Rated inlet temperat ure is 95°F tube side. Design temperature range of both shell a nd tube sides are 40°F to 480°F. The tube side water temperature may be as low as 32°F. The low temperature condition is acceptable, base d on compliance with the AS ME III, Class 2, code. Design pressure is 500 psig on both side

s. Fouling allowances are 0.0005 shell side and 0.002 tube side.

The construction materials are carbon steel for the pressure vessel with stainless steel tubes and stainless steel clad tube sheet.

c. Valves All of the directional valves in the system are conventi onal gate, globe, and check valves designed for nuclear service.

The injection valv es, reactor coolant isolation valves, and pump minimum flow valves are high speed valves, as operation for LPCI injection or vessel isolation requires. Valve pressure ratings are specified as necessary to provide the control or isolation function: i.e., all vessel isolation valves are rated as Class 1 nuclear va lves rated at the same pressure as the primary system. The pump minimum flow valves (RHR-FCV -64) open automatically at main line flows less than approximately 800 gpm. This allows flow to return to the suppression pool through the minimum flow bypass line, which branches off the main line upstream of the flow element. The minimum flow valve closes at main line flows greater than approximately 900 gpm and forces the entire pump discharge flow through the main line. The minimum flow valve controls meet IEEE-279 requirements. To prevent loss of vessel inventory to the suppression pool when operating shutdown cooling or RHR/FP C assist mode, the mini mum flow valve is not

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-12-036 5.4-40 permitted to open. Administrative controls ensure that the valve is returned to normal status following the conclusion of shutdown cooling.

d. Restricting orifices The metering orifices in the discharge lines do not serve as restricting orifices.

The piping for each mode of RHR operation has been investigated to ensure that

the resistance is low enough to allow the rated flows given in Figure 5.4-17 yet high enough to prevent pump runout. Restricting orifices are necessary in the system test lines to prevent excessive runout during SP C and test modes and in the main discharge line to prevent exces sive runout for LPCI A & C systems. In addition, restriction orifices are installed ahead of the RHR-V-53A and RHR-V-53B valves to prevent excessive pump runout or valve cavitation during the

shutdown cooling mode. Figure 5.4-15 indicates the loca tion of restricting orifices. Additionally, two orifices are installed in the FPC system to minimize cavitation and limit flow when RHR is used to assist FPC.

e. ECCS portions of the RHR system The ECCS portions of the RHR system include those sectio ns described in Figure 5.4-16

. The route includes suppression pool suction strainers, suction piping, RHR pumps, discharge piping, injection valv es, and drywell piping into the vessel nozzles and core region of the reactor vessel. The SPC components include pool suction strainers, suction piping, pumps, heat exchangers, and po ol return lines. Containment spray components are the sa me as SPC except that the spray headers replace the pool return lines.

5.4.7.2.3 Controls and Instrumentation

Controls and instrumentation for the RHR system are described in Section 7.3. The RHR system relief valve capacities and settings are listed in Section 5.4.7.1.3 . 5.4.7.2.4 Applicable C odes and Classifications

See Section 3.2. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-41 5.4.7.2.5 Reliability Considerations The RHR system has included the re dundancy requireme nts of Section 5.4.7.1.5 . Two redundant loops have been provided to re move residual heat. With the exception of the common shutdown cooling line and the shutdown return valves (RHR-V-53A and RHR-V-53B) which are powered from the same division power source, all mechanical and electrical components are separate. Either loop is cap able of cooling down the reactor within a reasonable length of time.

5.4.7.2.6 Manual Action

RHR (shutdown cooling mode)

In the shutdown cooling mode of operation, when reactor vessel pressure is 48 psig or less, a service water pump is started a nd cooling water flow establishe d through a heat exchanger. The RHR pump suction valve RHR-V-4A and/or RHR-V-4B is then closed and shutdown cooling isolation valves RH R-V-9 and RHR-V-8 opened. RHR pump suction valve RHR-V-6A and/or RHR-V-6B is then opened. Pump suction piping is prewarmed and provided a nominal flush by opening valves to radwaste. These effluent valv es to radwaste are then closed and the RHR pump is started. The cooldown rate is contro lled by adjusting the heat exchanger outlet valve and heat exchanger bypass valve to ach ieve the desired temperature of the water returning to the r eactor vessel while maintaining th e total flow at approximately 7450 gpm.

If prewarming valves were acci dentally left open following in itiation of shutdown cooling, reactor pressure vessel (RPV) coolant inventory would drain to radwaste. If loss of inventory remained undetected and makeup did not occur, isolation valves RHR-V-8 and RHR-V-9 would automatically close at the RPV scram leve l specified in the Tec hnical Specifications; depressurization or loss of water from the RHR system causes a low pressure alarm in the RHR discharge piping.

If the bypass around RHR-V-6A were inadvertently left open following the initiation of shutdown cooling using RHR loop B, the RP V coolant inventory would drain to the

suppression pool at a flow rate of 1 gpm or less. If this loss of inventory remained undetected and makeup did not occur, RHR-V-8 and RHR-V-9 would auto matically close at the RPV scram level.

The manual actions required for the most limiting failure are discussed in Section 5.4.7.1.5 . 5.4.7.3 Performance Evaluation

Thermal performance of the RHR heat exchangers is based on the capability to remove enough sensible and decay heat from th e reactor system to reduce the bulk reactor coolant temperature COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4-42 to 125°F within 25 hours after control rod in sertion, with two RHR loops in operation. Because cooldown is usually a controlled operation, maximum service water temperature less 10°F is used as the service water inlet temper ature. These are nominal design conditions; if the service water temperature is higher, the exchanger capabilities are reduced and the cooldown time may be longer or vice versa. 5.4.7.3.1 Shutdown Cooling W ith All Components Available

No typical curve is included here to show vessel cooldown temperatures versus time due to the infinite variety of such curves due to (a) clea n steam systems that use the main condenser as the heat sink when nuclear steam pressure is insufficien t to maintain steam air ejector performance, (b) the fouling of the heat exchangers, (c) opera tor use of one or two cooling loops, (d) coolant water temperature, and (e) sy stem flushing time. Si nce the exch angers are designed for the fouled condition with relatively high service water temper ature, the units have excess capability to cool when first used at high vessel temperatures. Total flow mix temperature is controlled to avoid exceeding 100°F/hr cooldown rate. See Figure 5.4-21 for minimum shutdown cooling time to reach 212°F.

5.4.7.3.2 Shutdown Cooling With Most Limiting Failure

Shutdown cooling under cond itions of the most limiting failure is discussed in Section 5.4.7.1.5. The capability of the heat exchanger for any time period is balanced against residual heat, pump heat, and sensible heat. The excess over re sidual heat and pump heat is used to reduce the sensible heat.

5.4.7.4 Preoperational Testing

The preoperational test program and startup test program were used to generate data to verify the operational capabilities of equipment in the system, such as ea ch instrument, setpoint, logic element, pump, heat exchanger, valve, and limit switch. In addition these programs verified the capabilities of the system to provide the flows, pressure s, cooldown rate s, and reaction times required to perform all syst em functions as spec ified for the system or component in the System Data Sheets and Process Data. Logic elements were tested electrically; valves, pumps, controllers, relief valves were tested mechanically; finally the system was tested for total system performance against the design requireme nts as specified above using both the offsite power and standby emergency power. Preliminar y heat exchanger performance was evaluated by operating in the pool cooling mode, but a ve ssel cooldown was used fo r the final check due to the small temperature differences available with pool cooling (see Section 14.2). COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December2005 5.4-43 5.4.8 REACTOR WATER CLEANUP SYSTEM The reactor water clean up (RWCU) system is an auxiliary system, a small part of which is part of the RCPB up to and includi ng the outermost containment is olation valve. The other portions of the system are not part of th e RCPB and are isolat ed from the reactor.

5.4.8.1 Design Bases

5.4.8.1.1 Safety Design Bases The RCPB portion of the RWCU system meets the requirements of Regulatory Guides 1.26 and 1.29 to

a. Prevent excessive loss of reactor coolant,

b. Prevent the release of radioactive material from the reactor,

c. Isolate the cleanup syst em from the RCPB, and

d. Prevents loss of liquid reactivity control material from the reactor vessel during standby liquid control (S LC) system operation.

5.4.8.1.2 Power Gene ration Design Bases

The RWCU system

a. Removes solid and dissolved impurities from reactor coolant such that the water purity meets Regulatory Guide 1.56,

b. Discharges excess reactor water during startup, shutdown, and hot standby conditions,

c. Minimizes temperature gradients in the recirculation pi ping and vessel during periods when the main recircul ation pumps are unavailable,

d. Minimizes cleanup sy stem heat loss, and

e. Enables the major portion of the RWCU system to be serviced during reactor operation.

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.4-44 5.4.8.2 System Description The RWCU system (see Figures 5.4-22 and 5.4-23) continuously purifies reactor water during all modes of reactor operation. The system take s suction from the inle t of each reactor main recirculation pump and from the reactor pressure vessel bottom head. Processed water is returned to the reactor pressure vessel, to the main condenser, or radwaste.

The cleanup system can be opera ted at any time during planned operations, or it may be shut down. The cleanup system is classified as a primary power generation system. The cleanup system is not an engineered safety system.

Major equipment of the RWCU sy stem is located in the reacto r building. This equipment includes the pumps and the regenerative and nonregenerative heat exchangers. Filter-demineralizers and suppor ting equipment are located in the radwaste building. The entire system is connected by associated valves and piping; controls and instrumentation provide proper system operation. Design data for the major pieces of equipment are presented in Table 5.4-5 . Reactor water is cooled in the regenerative and nonregenerativ e heat exchangers, filtered, demineralized, and returned to the reactor pr essure vessel through the shell side of the regenerative heat exchanger.

The system pump is capable of producing a nom inal flow of 181,300 lbm/hr. Two filter demineralizer units are used to process this quantity of water. The system can operate at reduced flow rates with one filter demineralizer unit.

The temperature of water processed through the filter-demineral izers is limited by the resin operating temperature. Therefore, the reactor water must be cooled before being processed in the filter-demineralizers. The regenerative heat exchanger transfers heat from the tube side (hot process) to the shell side (cold process). The shell side flow returns to the reactor. The nonregenerative heat exchanger c ools the process further by tran sferring heat to the reactor building closed cooling water system.

The filter-demineralizers (see Figure 5.4-24 ) are pressure precoat type filters using ion exchange resins. Spent resins are not regenerable and are sluiced from the filter-demineralizers to a backwash receiving tank from which they are transferred to the radwaste system for processing and disposal . To prevent resins from entering the RRC in the event of complete failure of a filter-demineralizer resin septum, a strainer is installed on each filter-demineralizer. Each strainer and filter-demineralizer vessel has a control room alarm that is energized by high differential pressure. Further increase in diffe rential pressure will isolate the filter-demineralizer. The backwash and precoat cycle for a filter-demineralizer is automatic to prevent operational errors such as inadvertent ope nings of valves that would initiate a backwash or contaminate reactor water with resins. The filter-demineralizer piping

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.4-45 configuration is arranged to ensure that transfers are complete and crud traps are avoided. A bypass line is provided around the filter-dem ineralizers. On low flow or loss of flow in the system, flow is maintained through each filter-demineralizer by its own holding pump. Sample points are pr ovided in the common influent header and in each effluent line of the filter-demineralizers for continuous indi cation and recording of system conductivity. High conductivity is annunciated in the control room. The influent sample point is also used as the normal source of reactor coolant grab samples. Sample analysis also indicates the effectiveness of the filter-demineralizers. The suction line of the RCPB portion of the RWCU system contains two motor-operated isolation valves that automatically close in response to signals from the RPV low water level and the leak detection system. The outboard isolation valve, RWCU-V-4, automatically closes in response to signals from actuation of th e SLC system and high nonregenerative heat exchanger outlet water temperature. These actions prevent (a) loss of reactor coolant, (b) release of radioactive material from the reactor, (c) removal of liquid reactivity control material, and (d) thermal damage to ion-exchange resins. The RCPB isolation valves may be remote manually operated to isolate the system equipment for maintenance or servicing.

A remote manual-operated gate valve on the return line to the reactor provides long-term leakage control. Instantaneous reverse flow isolation is provided by check valves in the RWCU piping.

Operation of the RWCU system is controlled from the main control room. Resin-changing operations, which include backwashing and precoating, are controlled from the radwaste control room in the radwaste building.

A functional control diagram is provided in Figure 7.3-1 . 5.4.8.3 System Evaluation

The RWCU system in conjunction with the condensate treatmen t system and FPC and cleanup system maintains reactor water quality during all reactor operating m odes (normal, standby, startup, shutdown, and refueling). The RWCU components provide a system with the capability to support reactor operations at power levels up to 3629 MWt.

The component pressure and temperat ure design conditions are shown in Table 5.4-5 . The process containing components (p iping, valves, vesse ls, heat exchangers, pumps) are designed to the requirements of Section 3.2. The control requirements for the RCPB isolation valves are designed to the requirements of Table 7.3-5. The nonregenerative h eat exchanger is sized to maintain the process temperature required for the cleanup demineralizer resin when the cooling capacity of the regenerative heat exchanger is reduced at times when flow is partially bypassed to the main condenser or radwaste.

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 LDCN-10-010 5.4-46 5.4.8.4 Demineralizer Resins

Regulatory Guide 1.56 complian ce is described in Section 1.8. 5.4.8.5 Reactor Water Cleanup Water Chemistry

5.4.8.5.1 Analy tical Methods

Chemical analyses methods used for determinati on of conductivity, pH, a nd chloride content of primary coolant are as follows: Conductivity measured in accordance to ASTM-D-1125 pH measured in accord ance to ASTM-D-1293

Chloride determined by ion chromat ography in accordance with the vendor's operating manual

5.4.8.5.2 Relationship of Filter-Demineralizer Condition to Water Chemistry

The filter-demineralizer condition during norm al power operation is related to inlet conductivity and water volume proce ssed through the unit. The in let conductivity is related to impurity concentration through the equivalent c onductance of the constitu ents of the process fluid. System flow rates are measured and reco rded to determine quantity of water processed. Periodically, an On-Line NobleChem application will be performe d, which injects platinum into the reactor coolant, resu lting in a microscopic layer of the noble metal to be deposited onto the reactor internals.

Conductivity instrumentation is calibrated against laboratory flow cel ls in accordance with ASTM-D-1125. The alarm setpoints for the conductivity instrument ation at the inlet and outlet of the filter-demineralizers are set to indicate marginal performance or breakthrough of the filter-demineralizers.

The quantity of the principle ion(s) likely to cause demineralizer breakthrough are not calculated using conductivity as di scussed in position 4.C of Regulatory Guide 1.56. Instead, actual ion sample data is taken and used to determine ion levels at the outlet of the filter-demineralizer. When sample da ta indicates resin breakthrough or the allowable pressure drop is exceeded, the filter-demin eralizer is regenerated.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 LDCN-04-002 5.4-47 5.4.9 MAIN STEAM LINES AND FEEDWATER PIPING

5.4.9.1 Safety Design Bases

To satisfy the safety bases, the main steam and feedwate r lines have been designed

a. To accommodate operational stresses, such as internal pressures and SSE loads, without a failure that could lead to the release of radi oactivity in excess of the guideline values in pub lished regulations, and

b. With suitable accesses to permit IST and inspections.

5.4.9.2 Power Gene ration Design Bases

To satisfy the design bases

a. The main steam lines have been designed to conduct steam from the reactor vessel over the full range of re actor power operation, and

b. The feedwater lines have been designed to conduct water to the reactor vessel over the full range of reactor power operation.

5.4.9.3 Description

The main steam piping is described in Section 10.3. The main steam and feedwater piping is shown in Figure 10.3-2 . The feedwater piping consists of two 24-in. O.D. lines which penetrate the containment and drywell and branch into three 12-in. lines each, which connect to the r eactor vessel. Each 24-in. line includes three containm ent isolation valves consisting of one check valve inside the drywell and one motor-operated gate valve and one check valve outside the containment. The design pressure and temperature of the feedwa ter piping between the re actor and maintenance valve is 1300 psig and 575°F. The Seismic Category I design requirements are placed on the feedwater piping from the reactor through the out board isolation valve and connected piping up to and including the first isolati on valve in the connected piping.

The materials used in the piping are in acco rdance with the applicable design code and supplementary requirement s described in Section 3.2. The feedwater system is furt her described in Sections 7.7.1, 7.7.2, and 10.4.7. COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-48 5.4.9.4 Safety Evaluation Differential pressure on reactor internals under the assumed acc ident condition of a ruptured steam line is limited by the use of flow restrictor s and by the use of four main steam lines. All main steam and feedwater pipi ng is designed in accordance with the requirements defined in Section 3.2. 5.4.9.5 Inspection and Testing Inspection and testing of the main steam lines and feedwater piping is performed in accordance with the ISI Program Plan to ensure compliance w ith applicable codes. 5.4.10 PRESSURIZER

Not Applicable to BWRs.

5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM

Not Applicable to BWRs.

5.4.12 VALVES

5.4.12.1 Safety Design Bases

Line valves such as gate, globe, and check valves are located in the fluid systems to perform a mechanical function. Valves are components of the system pressure boundary and, having moving parts, are designed to operate efficiently to maintain the integrity of this boundary.

The valves operate under the in ternal pressure/temperature lo ading as well as the external loading experienced during the various system transient operating conditions. The design criteria, the design loading, and acceptability criteria are as required in Section 3.9.3 for ASME Class 1, 2, and 3 valves. Complia nces with ASME Code s are discussed in Section 5.2.1.

5.4.12.2 Description

Line valves furnished are manufactured standard types, designe d and constructed in accordance with the requirements of ASME Section III for Class 1, 2, and 3 valves. All materials, exclusive of seals, packing and wearing compone nts, are designed to en dure the 40-year plant life under the environmental conditi ons applicable to the particul ar system when appropriate maintenance is peri odically performed.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-49 Power operators have been si zed to operate successfully und er the maximum differential pressure determined in the design speci fication or design basis calculations. 5.4.12.3 Safety Evaluation

Line valves are shop tested by the manufacturer for performability. Pressure retaining parts are subject to the testing and ex amination requirements of Secti on III of the ASME Code. To minimize internal and external leakage past seating surfaces, maximum allowable leakage rates are stated in the design specifica tions for both back seat as well as the main seat for gate and globe valves.

Valve construction materials are compatible with the maximum anticipated radiation dosage for the service life of the valves.

5.4.12.4 Inspection and Testing

Valves serving as containment isolation valves and which must remain closed or open during normal plant operation may be partially exercised during this period to assure their operability at the time of an emergency or faulted conditions . Other valves, serving as a system block or throttling valves, may be exer cised when appropriate.

Motors used with valve actuators are furn ished in accordance with applicable industry standards. Each motor actuator has been assembled, factory te sted or tested in-situ, and adjusted on the valve for proper operation, position and torque switch setting, position transmitter function (where applicable), and speed requirements. A selected set of motor-

operated valves with active safety functions (Generic Letter 89-10 Program and Generic Letter 96-05 Program) have additionally been tested to demonstrate adequate stem thrust (or torque) capability to open (or clos e) the valve within the specified time at specified maximum expected differential pressure. Modifications have been made to several gate valves to eliminate the possibility for internal pressure locking forces wh ich could prevent the actuator from unseating the valve (G eneric Letter 95-07 Program).

Tests verified no mechanical damage to valve components during full st roking of the valve. Suppliers were required to furnish assurance of acceptability of the equipment for the intended service based on any combination of

a. Test stand data, b. Prior field performance,

c. Prototype testing, and

d. Engineering analysis.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-50 Preoperational and operational testing performed on the installed valves consists of total circuit check out and performance tests to verify de sign basis capability including speed requirements at specified differential pressure.

5.4.13 SAFETY AND RELIEF VALVES

A listing of the safety and re lief valves is provided in Table 5.4-6 . 5.4.13.1 Safety Design Bases

Overpressure protection is provi ded at isolatable portions of systems in accordance with the rules set forth in the ASME Code, Secti on III for Class 1, 2, and 3 components.

5.4.13.2 Description

Pressure relief valves are desi gned and constructed in accordance with the same code class as that of the line valves in the system.

The design criteria, design loading, and de sign procedure are described in Section 3.9.3. 5.4.13.3 Safety Evaluation

The use of pressure relieving devices will ensure that overpressure will not exceed 10% above the design pressure of the system . The number of relieving devices on a system or portion of a system have been determined on an individual component basis.

5.4.13.4 Inspection and Testing

The valves are inspected and tested in accordance with ASME Section XI, if required.

Other than the main steam relief valves, no prov isions are to be made for inline testing of pressure relief valves, other than set pressure and leakage. Certified set pressures and relieving capacities are stampe d on the body of the valves by the manufacturer and further examinations would necessitate removal of the component. For subsequent set pressure changes, the valve body will be stamped or a st amped tag will be attached indicating the new pressure.

5.4.14 COMPONENT AND PIPING SUPPORTS

Support elements are provided for those compon ents included in the RC PB and the connected systems.

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4-51 5.4.14.1 Safety Design Bases Design loading combinations, design procedures, and acceptability criteria are as described in Section 3.9.3. Flexibility calculations and seismic anal ysis for Class 1, 2, and 3 component and piping supports within the ASME boundary of jurisdiction conform with the appropriate requirements of ASME Secti on III, Subsection NF. Outside the ASME boundary steel structures conform to the AISC manual of Steel Construction.

Spacing and size of pipe suppor t elements were based on the piping analysis performed in accordance with ASME Section III a nd further described in Section 3.7. Standard manufacturer hanger types were used and fabricated of mate rials per ASME Section III, Subsection NF.

5.4.14.2 Description

The use and location or rigid-t ype supports, variable or constant spring-type supports, and anchors or guides are determined from the results of static and dynamic analyses of the associated piping systems. The normal and transient (including seismic) support point loads generated by the piping analyses are combined as prescribed by Sections 3.9.3 and 3.7, and then utilized as the design basis loadings for each affected pipe support.

Typically, components support elements are manufacturers' standard items which are purchased with certified load capacity data reports. Nonstandard support structures and pressure boundary attachments are qualified by detailed structural analyses in compliance with applicable load combinations and governing design codes.

As described by Sections 5.4.14.1 and 5.4.14.2, each component suppor t system has been rigorously evaluated with all due consideration for extreme load ing conditions and satisfaction of conservative design allowable stresses. This demonstration of structural adequacy combined with a comprehensive testing a nd inspection program (see Section 5.4.14.3) constitutes the safety evaluation basis for th ese passive support elements.

5.4.14.3 Inspection and Testing

After completion of the installa tion and balancing of a support system, all hanger elements were visually examined to ensu re that they were in correct adjustment to their cold setting position. On initial hot startup operations, ther mal growth was observe d and it was confirmed that all spring-type hangers a nd snubbers were functioning properly between their hot and cold setting positions. In addition, during power ascension testing critical systems were instrumented and monitored for vibration response under normal a nd plant transient conditions. The results of these tests showed all systems to be functioning as predicted by design analyses and thus all systems were accepted as operable and in compliance with the governing ASME Code. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-06-054 5.4-52 5.4.15 HIGH-PRESSURE CORE SPRAY SYSTEM

See Section 6.3 for a description of the HPCS system.

5.4.16 LOW-PRESSURE CORE SPRAY SYSTEM

See Section 6.3 for a description of the LPCS system. 5.4.17 STANDBY LIQUID CONTROL SYSTEM

See Section 9.3.5 for a description of the SLC system.

5.4.18 REFERENCES

5.4-1 Ianni, P. W., "Effect iveness of Core Standby Cooling Systems for General Electric Boiling Water React ors," APED-5458 , March 1968.

5.4-2 "Design and Performance of General Electric Boiling Water Reactor Main Steam Line Isolation Valves," APED-5750, General Electric Co., Atomic Power Equipment Depa rtment, March 1969.

5.4-3 "Power Uprate with Extended Load Line Limit Safety Analysis for WNP-2," NEDC-32141P, General Electric Company.

5.4-4 "Generic Evaluations of General Electric Boiling Wa ter Reactor Power Uprate - Volume I," NEDC-31984P, Ge neral Electric Company.

5.4-5 "Reactor Core Isolation Cooling System (RCIC)," Design Basis Document, Section 315.

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-98-113 5.4-53 Table 5.4-1 Reactor Coolant Pr essure Boundary Pump

and Valve Descriptio na Location Active /Inactive Valve Reference Figure Valve Description RHR vessel in Active Active Active Active Active Active

Inactive Inactive Inactive RHR-V-41A

RHR-V-41B RHR-V-41C (E12F041A, B, C) RHR-V-42A

RHR-V-42B

RHR-V-42C

(E12F042A, B, C) RHR-V-111A

RHR-V-111B

RHR-V-111C

(E12F111A, B, C) 5.4-15 5.4-15 5.4-15 5.4-15 5.4-15 5.4-15

5.4-15 5.4-15 5.4-15 RHR/recirculation

line in Active Active

Active Active

Inactive Inactive

Inactive Inactive RHR-V-50A

RHR-V-50B

(E12F050A, B) RHR-V-53A

RHR-V-53B

(E12F053A, B) RHR-V-112A

RHR-V-112B

(E12F112A ,B) RHR-V-123A

RHR-V-123B

(E12F099A, B) 5.4-15 5.4-15

5.4-15 5.4-15

5.4-15 5.4-15

5.4-15 5.4-15 Head spray Active Active RHR-V-19 (E12F019) RHR-V-23 (E12F023) 5.4-15 5.4-15 RHR shutdown

cooling suction Active Active Inactive RHR-V-8 (E12F008) RHR-V-9 (E12F009) RHR-V-113 (E12F113) 5.4-15 5.4-15 5.4-15 RCIC vessel out Active Active Active Active RCIC-V-8 (E51F008)

RCIC-V-63 (E51F063)

RCIC-V-64 (E51F064)

RCIC-V-76 (E51F0076) 5.4-11 5.4-11 5.4-11 5.4-11 COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-98-113 5.4-54 Table 5.4-1

Reactor Coolant Pr essure Boundary Pump

and Valve Descriptio na (Continued) Location Active /Inactive Valve Reference Figure (Nuclear boiler) Reactor vessel head

Inactive Inactive

MS-V-1 (B22F001)

MS-V-2 (B22F002)

10.3-2 10.3-2 Feedwater in Active Active

Inactive Inactive

Active Active

Active Active RFW-V-10A

RFW-V-10B (B22F010A, B)

RFW-V-11A

RFW-V-11B (B22F011A, B)

RFW-V-32A

RFW-V-32B (B22F032A, B)

RFW-V-65A

RFW-V-65B (B22F065A, B) 10.3-2 10.3-2

10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 Safety relief Active Active Active Active Active Active Active Active

Active Active Active Active Active Active

Active Active MS-RV-2A MS-RV-3A

MS-RV-2D

MS-RV-2C

MS-RV-1B

MS-RV-2B

MS-RV-3C

MS-RV-3B

(B22F013A -H) MS-RV-1A

MS-RV-1D

MS-RV-1C

MS-RV-4C

MS-RV-5C (B22F013J-N) MS-RV-4D

(B22F013P)

MS-RV-4B MS-RV-4A 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2

10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2

10.3-2 10.3-2 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-55 Table 5.4-1 Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued) Location Active/Inactive Valve Reference Figure Active Active (B22F013R-S)

MS-RV-5B

MS-RV-3D

(B22F013U-V)

10.3-2 10.3-2 Reactor water

cleanup system Inactive RWCU-V-103 (G33F103) 5.4-22 Line suction Active Active Inactive Inactive Inactive Inactive RWCU-V-1 (G33F001)

RWCU-V-4 (G33F004) RWCU-V-100 (G33F100)

RWCU-V-101

(G33F101)

RWCU-V-102

(G33F102)

RWCU-V-106

(G33F106) 5.4-22 5.4-22 5.4-22 5.4-22

5.4-22

5.4-22 Line discharge Active RWCU-V-40 (G33F040) 5.4-22 Drain to condenser Active Active MS-V-16 (B22F016)

MS-V-19 (B22F019) 10.3-2 10.3-2 MSIV Active Active Active Active Active Active Active Active MS-V-22A

MS-V-22B

MS-V-22C

MS-V-22D (B22F022)

MS-V-28A

MS-V-28B

MS-V-28C MS-V-28D (B22F028) 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-05-009, 06-000 5.4-56 Table 5.4-1

Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued) Location Active/Inactive Valve Reference Figure Drain to condenser

(Recirculation) Active Active Active Active MS-V-67A

MS-V-67B

MS-V-67C

MS-V-67D (B22F067) 10.3-2 10.3-2 10.3-2 10.3-2 Recirculation pump

suction Inactive Inactive RRC-V-23A RRC-V-23B (B35F023) 5.4-7 5.4-7 Flow control (pump

discharge) Inactiveb Inactiveb Inactive Inactive RRC-V-60A

RRC-V-60B (B35F060)

RRC-V-67A

RRC-V-67B

(B35F067) 5.4-7 5.4-7

5.4-7 5.4-7 RCIC vessel head in Active Active Active RCIC-V-13 (E51F013) RCIC-V-65 (E51F065)

RCIC-V-66 (E51F066) 5.4-11 5.4-11 5.4-11 HPCS in Active Active Inactive HPCS-V-4 (E22F005)

HPCS-V-5 (E22F004) HPCS-V-38 (E22F038) 6.3-4 6.3-4 6.3-4 LPCS in Active Active Inactive LPCS-V-5 (E21F005) LPCS-V-6 (E21F006)

LPCS-V-51 (E21F051) 6.3-4 6.3-4 6.3-4 Standby liquid

control in Active Active Active Active Inactive SLC-V-4A

SLC-V-4B

SLC-V-6 SLC-V-7 SLC-V-8 9.3-14 9.3-14 9.3-14 9.3-14 9.3-14 Pump description Recirculation pump Inactive Inactive RRC-P-1A RRC-P-1B (B35C001) 5.4-7 5.4-7 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-57 Table 5.4-1 Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued) a In addition to the process valves listed herein, there are instrument test conditions, drain valves, and sampling valves less than 1 in. nominal size within the RCPB. See associated system flow diagram figures.

b Mechanically blocked in the full open position.

NOTE: Active components are those whose operability is relied on to perform a safety function during the transients or accidents.

Inactive components are those whose operab ility (e.g., valve opening or closure, pump operation or trip) is not relied on to perform the system's safety function during the transients or accidents. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 LDCN-07-011 5.4-58 Table 5.4-2

Reactor Recirculation System Design Characteristics

Description External loops 2 Pump sizes (nominal O.D.) Pump suction, in. 24 Pump discharge, in. 24 Discharge manifold, in. 16 Recirculation inlet lines, in. 12 Design pressure (psig)/design temperature ( °F) Suction piping and valve up to and including pump suction nozzle 1250/575 Pump, discharge valves, and piping between 1650/575 Piping after discharge blocking valve up to vessel 1550/575 Vessel bottom drain 1275/575 Operation at pump related conditions Recirculation pump Flow, gpm 47,200 Flow, lb/hr 17.85 x 10 6 Total developed head, ft 805

Suction pressure (static), psia 1025 Required NPSH, ft 115 Water temperature (maximum), °F 533 Pump brake hp (minimum) 8340 Flow velocity at pump suction (approximate), ft/sec 41.5 Pump motor Voltage rating 6600 Speed, rpm 1780 Motor rating, hp 8900

Phase 3 Frequency 60

Motor rotor inertia (lb-ft

2) 21,500 (RRC-M-P/1B) 20,600 (RRC-M-P/1A)

Jet pumps Number 20

Total jet pump flow, lb/hr 108.5 x 10 6 Total I.D., in. 6.4

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-59 Table 5.4-2

Reactor Recirculation System Desi gn Characteristics (Continued) Description Diffuser I.D., in. 19.0 Nozzle I.D. (five each), in. 1.3 Diffuser ex it velocity, f t/sec 16.2 Jet pump head, ft 88.19 Flow control valve a Type Ball

Material Austenitic stainless steel

Valve wide open CV (minimum), gpm/psi 7000 Valve size diameter, in. 24 Recirculation block valve Type Gate valve Actuator Motor

Material Austenitic stainless steel

Valve size diameter, in. 24 Recirculation pu mp flow measurement Type Elbow taps Rated flow (gpm) 47,200 Flow element location Pump suction line Range 20-115% rated pump flow Accuracy (% rated pressure drop) 9% Repeatability (% rate d pressure drop) 4% a Mechanically blocked in the full open position. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-60 Table 5.4-3

Operating Experience of Ingersoll-Rand

Emergency Core Cooling Systems Pump sa,b Plant Pump Time (hr) Hatch 2 RHR 2A 864 2B 1112 2C 629 2D 569 LPCS 2A 13.5 2B 11.8 Chinshan 1 RHR 100 Core spray 30 Chinshan 2 RHR 75 Core spray 20 a The italicized information is historical and was provided to support the application for an operating license.

bNo problems have been reported on these pum ps. Pump design principles applied by Ingersoll-Rand to these units are not unique. Assu rance of a predictable functional reliability is also provided by a history of design, production, and applic ation of pumps for similar pumping requirements in other nuc lear and nonnuclear applications. COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-61 Table 5.4-4

Operating Experience of Similar Ingersoll-Rand Pumps for BWR Projects

Under Reviewa,b Year Size Range (g pm) Number of P umps 1963 <4000 12 1964 <3000 24 1965 <5000 32 1966 <4500 39 1967 <5000 8000 39 3 1968 <6500 9000 11000 25 6 9 1969 <6500 8000-9000 39 9 1970 <6500 8000 12,000 33 14 6 1971 <6500 9000 10,000-12,000 53 3 12 1972 <6500 8000 10,000-12,000 44 18 18 1973 <6500 8000 10,000-13,800 41 8 20 1974 <6500 8000 10,000-13,800 32 2 30 1975 <7500 8500 10,000-13,800 76 18 50 1976 8500 9 a The italicized information is historical and was provided to support the application for an operating license. b The vertical pumps used for ECCS functions at CGS are sized at 1200 to 8100 gpm. They are multistaged axial pumps. Included here is a partial list of the application history for similar pumps made by the same vendor. Although the operating experience in nuclear applications is just beginning, the postoperating experience in nonnuclear applications with these vertical pumps is very extensive. It indicates that the CGS ECCS pumps can be expected to operate as required. In reviewing this table, the generic pump design should be recalled because larger capacity pumps are configured from stages that comprise the smaller capacity pumps. Design refinements are evident in the capacity growth of these stages, whether in single, double, or multiple axial stackups.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-62 Table 5.4-5 Reactor Water Cleanup System

Equipment Design Data Main Cleanup Recirculation Pumps Number 2 Capacity (each) 100% (@90 bhp) Design te mperature, F 575 Design pressure, psig 1420 Discharge head at shutoff, ft 575 Minimum available NPSH, ft 16 Heat Exchangers Regenerative Nonregenerative Number 1 (3 shells) 1 (2 shells) Shell design pressure, psig 1420 150 Shell design temperature, F 575 370 Tube design press ure, psig 1420 1420 Tube design temperature, F 575 575 Filter-De mineralizers Type Pressure precoat Number 2 Design temperature, F 150 Design pressure, psig 1450

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 LDCN-00-056 5.4-63 Table 5.4-6 Safety and Relief Valves for Piping Systems

Connected to the React or Coolant Pressure Boundary Main steam line safety/relief valves MS-RV-1A (B22F013J-N) MS-RV-1B (B22F013A -H) MS-RV-1C (B22F013J-N)

MS-RV-1D (B22F013J-N) MS-RV-2A (B22F013A -H) MS-RV-2B (B22F013A -H) MS-RV-2C (B22F013A -H) MS-RV-2D (B22F013A -H) MS-RV-3A (B22F013A -H) MS-RV-3B (B22F013A -H) MS-RV-3C (B22F013A -H) MS-RV-3D (B22F013U-V)

MS-RV-4A (B22F013R -S) MS-RV-4B (B22F013R -S) MS-RV-4C (B22F013J-N)

MS-RV-4D (B22F013P)

MS-RV-5B (B22F013U-V)

MS-RV-5C (B22F013J-N) RCIC system discharge line RCIC-RV-3 RCIC system suction l ine RCIC-RV-17 (E51F017) RCIC lube oil cooler supply line RCIC-RV-19T RCIC vacuum tank RCIC-RV-33 (E51F033) a Shutdown cooling supp ly line RHR-RV-5 (E12F005) Shutdown cooling retu rn line RHR-RV-25A RHR-RV-25B (F12F025A, B) Suppression pool supply for RHR RHR-RV-88A RHR-RV-88B RHR-RV-88C

(E12F088A, B, C) RHR flush line RHR-RV-30 (E12F030) RHR heat exchanger (shell side) RHR-RV-1A RHR-RV-1B RWCU regenerative heat exc hanger (shell side) RWCU-RV-1a COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 5.4-64 Table 5.4-6 Safety and Relief Valves for Piping Systems Connected to the Reactor Coolan t Pressure Bounda ry (Continued) RWCU regenerative heat exchanger (tube side) RWCU-RV-3 a RWCU blowdown to radwaste system or condenser RWCU-RV-36 (G33F036) a HPCS suction line HPCS-RV-14 (E22F014) HPCS discharge line HPCS-RV-35 (E22F035) LPCS discharge line LPCS-RV-18 (E21F018) LPCS suction line LPCS-RV-31 (E21F031) SLC pump discharge line SLC-RV-29A SLC-RV-29B (C41F029A, B) a These relief valves are instal led in a B31.1 system; not subject to Section XI testing and inspection.

Driving Flow Recirculation PumpJet PumpSimplified SchematicPictorial View Recirculation Outlet Recirculation InletDischarge Shutoff ValveFlow Control Valve (Note 1)Suction Shutoff ValveNote 1: FCVs Are Mechanically Blocked Full Open. SuctionFlowCoreRecirculation System Evaluation and Isometric 960690.07 5.4-1FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report 110% Speed 105% Speed 100% Speed System Resistance 10,00020,00030,00040,00050,00060,000Flow - GPM Dynamic Head - Ft. 1,4001,2001,000800600400 2000RRC Pump Dynamic Head-Flow Curve 960690.05 5.4-2FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report 020040060080010001200140016001800 25% Flow - 535F Water25% Flow - Cold Water 100% Flow - 535F Water100% Flow - Cold WaterBreakaway Torque is 1200 Ft. Lbs. Pump Speed - RPM Pump Torque - Ft. Lbs. 36,00032,00028,00024,000 20,000 16,000 12,0008,000 4,0000RRC Pump Speed - Torque Curve 960690.06 5.4-3FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.59Recirculation Pump Head, NPSH, Flow and Efficiency Curves 5.4-4400200010,0005,000 090807060504030201001200 1000800600 400010.00020,00030,00040,00050,00060,00070,000 NPSH at C imp.Efficiency % HeadBHP at 0.755 SP. GR. Total Dynamic Head (Ft) BHPNPSH (Ft)Efficiency % Gallons Per Minute LColumbia Generating StationFinal Safety Analysis Report Operating Principle of Jet Pump 960690.58 5.4-5SuctionFlowDriving FlowSuctionFlowPDrivingFlowPPressureDriving Flow FlowSuctionDriving Nozzle Throator Mixing SectionDiffuserFigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.60Core Flooding Capability of Recirculation System 5.4-6SteamSeparation Distribution PlenumWater Level After Break in Recirculation LoopNormalWaterLevelSteamSeparators Active Core Columbia Generating StationFinal Safety Analysis Report Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-7.211M530-2Reactor Recirculation System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-7.210M530-2Reactor Recirculation System - P&IDRev.FigureDraw. No. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.61Main Steam Line Flow Restrictor Location 5.4-8Reactor Vessel Steam Flow Restrictor DrainsMain Steam LineIsolation Valves PrimaryContainmentTestConnection Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.84Main Steam Line Isolation Valve 5.4-9Air Cylinder (Closing Piston Inside) MSIV SpeedControl Valves Hydraulic Dash PotActuator Support

And Spring Guide

ShaftClosing Spring Spring Seat Member StemStem PackingLeak OffConnection (Plugged) Bonnet Bolts BonnetBalancing OrificeMain Valve

SeatBodyPilotPilot Seat AccumMain Disk Columbia Generating StationFinal Safety Analysis Report Flow RCIC Pump Performance Curve (Constant Flow) 960690.55 5.4-10NPSH-ft at 625 GPM EFF% at 625 GPM HEAD at 625 GPMBHP at SP. GR 1.0 at 625 GPM 320028002400 2000160012008004000BHP Required NPSH-Required 30201006004002000800Eff.%9080706050 40 30201001500200025003000350040004500 Speed Revolutions Per MinuteWitness Test Performance Bingham-Willamette Co.

Portland, Oregon FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report5.4-1198M519RCIC System - P&IDRev.FigureDraw. No. Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-121002E51-04,4,1RCIC System Process DiagramRev.FigureDraw. No. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.86 RCIC Pump Performance Curve 5.4-1312001400 1600 1800 2000010 20 30 40506070 8090Eff. %12005001000BHP02550NPSH-ft100Gallons Per MinuteTest Speed RG. 3591-3585 RPM HeadEff%BHP at SP. GR 1.0 NPSH at C Imp. L100080060040020000Whitness Test Performance Bingham-Willamette Co.

Portland, Oregon. Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.87Typical Strainer 5.4-14Notes:1. Flow stated above is per penetration with two (2) units described above

required per penetration.

2. Units are designed, manufactured and inspected in accordance with ASME

Section III, Class 2 (not stamped) 1974 Ed. with Addenda thru Winter 1976.

3. Design temp: 220FMeasurements for Strainers at Penetration X-33

Rated Flow: 600 gal/min Columbia Generating StationFinal Safety Analysis Report Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-15.1115M521-1Residual Heat Removal System - P&IDRev.FigureDraw. No.~~~~~~~~~~~~~~~~~~~~~~~~~~ Columbia Generating StationFinal Safety Analysis Report 5.4-15.2114M521-2Residual Heat Removal System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai LDCN-14-020 Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 05.4-15.4 5M521-4Residual Heat Removal System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-161002E12-04,1,1Residual Heat Removal System Process DiagramRev.FigureDraw. No. Amendment 62December 2013 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-17.1802E12-04,22,1Residual Heat Removal System Process DataRev.FigureDraw. No.

Draw. No. Rev.Figure FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.960690.89 RHR (LPCI) Pump Characteristics(S/N 0473113) P-2A 5.4-18BHPEfficiency HeadNPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 01020 30 40 50 60 70 80 90012 3 4 5 6 7 80102030400510Brake Horsepower x 100 NPSH in FeetEfficiency, % Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet x 100 960690.90 Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev. 1FigureAmendment 62 December 2013 5.4-19Form No. 960690FH LDCN-12-036 RHR (LPCI) Pump Characteristics (S/N 0801MP004399-1) P-2BEfficiency BHPHeadNPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 10020304050607080901000 12345 67801020 30 400510Brake Horsepower NPSH in FeetTotal Head in Feet x100Efficiency, % 960690.91 Columbia Generating Station Final Safety Analysis Report RHR (LPCI) Pump Characteristics(S/N 0473112) P-2CDraw. No.Rev.FigureAmendment 58 December 2005 5.4-20Form No. 960690FH LDCN-05-000 BHPEfficiency HeadNPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 1020 30 40 50 60 70 80901234 5 6 78010 2030400510Brake Horsepower x 100 NPSH in FeetTotal Head in Feet x 100Efficiency, % 0 FigureAmendment 55 May 2001Form No. 960690Draw. No.Rev.960690.88Vessel Coolant Temperature Versus Time(Two Heat Exchangers Available) 5.4-21100F/hrAssumed FlushTime100F/hr212F600500 4003002001000012345678Hours After Control Rods InsertedVessel TemperatureVersus TimeTwo Exchangers Available Columbia Generating StationFinal Safety Analysis Report Vessel Water Temperature (°F) Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-22.1115M523-1Reactor Water Cleanup System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-22.28M523-2Reactor Water Cleanup System - P&IDRev.FigureDraw. No. Amendment 63December 2015 Columbia Generating StationFinal Safety Analysis Report 5.4-22.3M523-3Reactor Water Cleanup System - P&IDRev. 10FigureDraw. No. Form No. 960690ai

Draw. No.

Rev. Figure Amendment 55 May 2001FigureForm No. 960690Draw. No.Rev.960690.92Vessel Coolant Temperature Versus Time(One Heat Exchanger Available) 5.4-25Hours After Control Rods Inserted012345678 0100200 300 400 500600100F/hrAssumed FlushTime212FColumbia Generating StationFinal Safety Analysis Report Vessel Water Temperature (°F) COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS

Section Page LDCN-13-052 6-i 6.1 ENGINEERED SAFETY FEATURE MATERIALS................................ 6.1-2 6.1.1 METALLIC MATERIALS ............................................................ 6.1-2 6.1.1.1 Materials Selec tion and Fabri cation ................................................ 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 Cool ants .................................................................. 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 Suppr ession Containm ent ................................................. 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 Summary Evaluation ............................................................. 6.2-5 6.2.1.1.3.2 Containment Design Parameters ............................................... 6.2-5 6.2.1.1.3.3 Accident Response Analys is .................................................... 6.2-6 6.2.1.1.3.3.1 Recirculation Line Rupture .................................................. 6.2-7 6.2.1.1.3.3.1.1 Assumptions for Reactor Bl owdown ..................................... 6.2-7 6.2.1.1.3.3.1.2 Assumptions for Containment Pressurization .......................... 6.2-9a 6.2.1.1.3.3.1.3 Assumpti ons for Long-Term Cooling .................................... 6.2-9a 6.2.1.1.3.3.1.4 Initia l 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 Standby A ccident 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 Contai nment Response ..................................................... 6.2-16 6.2.1.1.3.3.5.3 Recovery Operations ........................................................ 6.2-17 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-10-004, 15-011 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-Pr essure Core Spray ......................................................... 6.3-5 6.3.1.2.2 Low-Pressu re Core Sp ray ......................................................... 6.3-5 6.3.1.2.3 Low-Pressure Coolant Injection .................................................. 6.3-5 6.3.1.2.4 Automa tic Depressurizati on System ............................................. 6.3-6 6.3.2 SYSTEM DESIGN ...................................................................... 6.3-6 6.3.2.1 Schematic Piping and Instrumenta tion Diagrams ................................ 6.3-6 6.3.2.2 Equipment and Component Descrip tions .......................................... 6.3-6 6.3.2.2.1 High-Pressure Core Spray System ............................................... 6.3-6 6.3.2.2.2 Automa tic Depressurizati on System ............................................. 6.3-9 6.3.2.2.3 Low-Pressure Core Spray System ............................................... 6.3-9 6.3.2.2.4 Low-Pressure Cool ant 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 Cooling System Suc tion Strainers .......................... 6.3-14 6.3.2.3 Applicable Codes and Classifications .............................................. 6.3-18 6.3.2.4 Materials Specifica tions 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 ........................................ 6.3-22 6.3.3.5 Use of Dual Function Components for Emergency Core Cooling System .. 6.3-23 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 .......................................... 6.3-24 6.3.3.6.2 Loss-of-Coolant Accident Analysis Procedures and Input Variables ...... 6.3-25 6.3.3.6.2.1 LOCA Analysis Methodology, GE Hitachi Nuclear Energy ............. 6.3-26 6.3.3.6.2.2 DELETED ......................................................................... 6.3-26 6.3.3.6.2.3 LOCA Analysis Input Variables ............................................... 6.3-26 6.3.3.7 Break Spectrum Calculations ........................................................ 6.3-27 6.3.3.7.1 Break Spectrum Calculation, GE Hitachi Nuclear Energy .................. 6.3-27 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

TABLE OF CONTENTS (Continued)

Section Page LDCN-10-004, 15-011 6-vii 6.3.3.7.2 D ELETED. .......................................................................... 6.3-27 6.3.3.8 Loss-of-Coolant Acci dent Analysis Conclusions ................................. 6.3-28 6.3.4 TESTS AND IN SPECTIONS ......................................................... 6.3-28 6.3.4.1 Emergency Core Cooling System Performance Tests .......................... 6.3-28 6.3.4.2 Reliability Tests and Inspections .................................................... 6.3-29 6.3.4.2.1 High-Pressu re Core Spray Testing ............................................... 6.3-29 6.3.4.2.2 Automatic Depressurization System Testing ................................... 6.3-29 6.3.4.2.3 Low-Pressure Co re Spray Testing ............................................... 6.3-30 6.3.4.2.4 Low-Pressure Cool ant Injection Te sting ........................................ 6.3-30 6.3.5 INSTRUMENTATION REQUIREMENTS ........................................ 6.3-30 6.

3.6 REFERENCES

........................................................................... 6.3-31 

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 En velope ..................................... 6.4-2 6.4.2.2 Ventilation Sy stem Design ........................................................... 6.4-2 6.4.2.3 Leakti ghtness ........................................................................... 6.4-2 6.4.2.4 Interaction With Other Zones and Pressure Containing Equipment .......... 6.4-2 6.4.2.5 Shielding Design ....................................................................... 6.4-3 6.4.3 SYSTEM OPERATIO NAL 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 Ch lorine .............................................................................. 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 COLUMBIA GENERATING STATION Amendment 60  FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF TABLES (Continued)

Number Title Page LDCN-10-004, 15-011 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 DELETED

6.3-2a Plant Operational Parameters ................................................. 6.3-38

6.3-2b Fuel Parameters ................................................................. 6.3-39

6.3-2c ECCS Parameters ............................................................... 6.3-40

6.3-3 Single Failure Considered in ECCS Performance Evaluation ........... 6.3-44

6.3-4 DELETED

6.3-4a Event Scenario for 100% DBA Recirculation Suc tion Line Break HPCS DG Failure (App endix K) ............................................ 6.3-45 6.3-4b Event Scenario for 0.07 ft 2 Recirculation Suction Line Break HPCS DG Failure (App endix K) ............................................ 6.3-46 6.3-5 ECCS Performance An alysis Results ........................................ 6.3-47

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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES

Number Title 6-xii 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xiii 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xiv 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 Pressure 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 Arrange ment 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xv 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 Penetrations X-46 and X-101

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

6.2-52 Isolation Valve Arra ngement 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES

LIST OF FIGURES (Continued)

Number Title 6-xvi 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

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT 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 800F by means other than welding or th ermal cutting are either resolution COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment58 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 hours post-accident. This action is disc ussed in the dose consequences analysis in Section 15.6.5. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.1-1 Engineered Safety Features Systems and Related Systems Component Materials (Continued) Component Form Material Specification (A/SA) a LDCN-14-018 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

Forging Carbon steel 105 or 105 Grade 2 Disc Casting Carbon steel 216 Grade WCB Casting Alloy steel 217 Grade WC6 Forging Carbon steel 105 or 105 Grade 2 Stem Bar Stainless steel 479 Type 410 Bar Stainless steel 461 Grade 630 Studs Bar Alloy steel 193 Grade B7 Nuts Bar Alloy steel 194 Grade 7

Bar Carbon steel 194 Grade 2H 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 Grade 630 Forging Stainless steel 182 Grade F6a Stud Bar Alloy steel 540 Grade B23 Bar Alloy steel 193 Grade B7 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.1-1 Engineered Safety Features Systems and Related Systems Component Ma terials (Continued) Component Form Material Specification (A/SA) a LDCN-14-018 6.1-9 Isolation valves (Continued) Nuts Bar Alloy 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 Bar Alloy steel 194 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 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

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 LDCN-99-000 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 COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-03-003 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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.

In addition to the power uprate analysis (Reference 6.2-35), an additional containment analysis was performed (Reference 6.2-42) to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS). Tables 6.2-2 through 6.2-6 detail this analysis. The power uprate analysis remains bounding. Additionally, Reference 6.2-42 documents an analysis to address General Electric (GE) Safety Communication (SC) 06-01. GE SC 06-01 indicated that long-term low-pressure injection with all pumps operating and one RHR heat exchanger inoperable ma y impact suppression pool temperature. The analysis c oncludes that, when only one RHR heat exchanger is operable, two LPCI pumps and the LPCS pump must be secure

d. The timing for this action is detailed in Reference 6.2-42. This action is required to not exceed the bounding suppression pool temperature of 204.5°F.

6.2.1.1.3.3 Accident Response Analysis. The containment f unctional 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-7 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 uprat e to 3486 MWth (References 6.2-32, 6.2-33, and 6.2-35), only the recirculation line rupture (Case C), the bounding event fo r containment response, was reanalyzed. The contai nment response analyses are not cycle specific nor are they part of the analyses performed to support core reload analyses. For further discussion, see Sections 6.2.1.1.3.3.4 and 6.2.1.1.3.3.5 . For the containment analysis performed to eval uate reduced ECCS flow rates (RHR/LPCI and LPCS), the recirculation line rupture (Cases A, B, and C) were re-analyzed. For further discussion, see Section 6.2.1.1.3.2 . 6.2.1.1.3.3.1 Recirculation 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 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 re sponse 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 containment analysis perfor med to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS), the re actor is operating at 3556 MWt.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-8 This power corresponds to 102% of 3486 MWt. ANS 5.1-1979+2 with GE Service Information Letter (SIL) 636 is used to determine decay heat release.

4. For the nonlimiting events which we re not reanalyzed for power uprate, the standby service water (SW) te mperature is assumed to be 95F, which exceeds the maximum expected temperature. For power uprate, a less conservative value of 90F was assumed. For the containment analysis performed to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS), 85°F is assumed for the first 10 hours and 90°F thereafter.

5. The suppression pool mass is at the low water level.

6. 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 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 depressuriza tion period. The resulting high-energy COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-9 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 550F is released to the vessel fluid along with the stored energy in the vessel and internals as vessel fluid temperatures decrease below approximately 550F 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-energy water into the drywe ll. For the containment analysis performed to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS), MSIV closure was assumed to st art at 0 seconds after the accident.

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.

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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-9a 6.2.1.1.3.3.1.2 Assumptions fo r 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 Assumptions 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;

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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.

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 even ts 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, 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-14 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 330F. 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 recirculation 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 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-15 6.2.1.1.3.3.3 Hot Standby Accide nt Analysis. This section is not applicable to BWR-5. 6.2.1.1.3.3.4 Intermediate Size Breaks. The failure of a recirc ulation 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 submer gence 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 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. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-16 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 Containment 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 lead to a high drywell pressure COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-040 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 C onsideration. The energy balan ce 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 simultaneous operation of both containment spray loops afte r large and small-break LOCA could be a limiting transient for the containmen t negative pressure. However this event is based on more than one single failure or operator error and neglects the consideration for adequate core cooling by using both RHR loops. Using the single-failure criterion and considering the need for adequate core cooli ng following a large-break LOCA, 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 vacuum breaker to open. This scenario is nonlimiting with respect to floor uplift or negative pressure. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-040 6.2-19 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 negative pressure after large and small-line-break LOCA made the following conservative assumptions:

a. Maximum spray flow of 8200 gpm (combined drywell and wetwell flow),

b. 100% spray efficiency,

c. 50F 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.

g. Reactor Power is 3702 MWth.

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 . 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) .

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 ft2, 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 117F, 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, COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 6.2-25 6.2.1.1.8.3 Post-LOCA. The un it 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 and MELLLA 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 singl e 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 th e corresponding paramete rs with power uprate and MELLLA (Reference 6.2-32 and 3.6-24). Therefore, the ba sis for the subcompart ment pressurization loads is not affected by power uprate. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004 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/ft2-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 and 6.2-42. The result of the case of a 60-node model of the shield wall annulus for pressure transient calculation was confirmed by the NRC, and the analysis was considered acceptable for the shield wall base design and th e design of the shield wall above the base, as stated in NRC letters (References 6.2-12 and 6.2-13). For the MELLLA evaluati on a 400-node model of the shield wall was analyzed and the results were bounded by the original 60-node model. (Reference 3.6-24). 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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;

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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 56F 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 the re actor power level specified in Table 6.2-4, 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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 accide nt period. These assu mptions conservatively bound the heat sink temperature to which the containment heat is rejected. In addition, the RHR heat exchanger is assumed to be in a fully fouled cond ition at the time the accident occurs. This conservatively minimizes the heat exchanger heat removal capacity. The resultant suppression pool temperature transient is described in Section 6.2.1 and is shown in Figure 6.2-12 . Even with the degraded conditions outlined above, the maximum uprate temperature is 204.5F, which is less than the original 220°F. The results of the containment analysis performed to evalua te reduced ECCS flow rates (RHR/LPCI and LPCS) are bounded by the power uprate analysis. 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 the RHR heat exchanger. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-35a GE SC 06-01 addresses the unlikely event of an inoperable RHR heat exch anger with all ECCS pumps running post-accident. This event was evaluated in Reference 6.2-42 and found that if all four low pressure pumps (LPCS, 3-LPCI) were injecting post-accident the suppression pool bounding temperature may be exceeded. The timi ng for this action is de tailed in Reference 6.2-42. In the event of an inoperable RHR heat exchanger, operating pro cedures ensure that the three low pressure pumps not providing ope rational heat exchanger flow will be secured before suppression pool temperature limits are exceeded. It can be concluded that the conservative evaluation demonstrates that the RHR system in the suppression pool cooling mode limits the pos t-DBA containment te mperature transient. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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).

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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; COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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, COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-066 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 Conclusion on Cr iterion 56. To ensure protecti on against 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 requirement s, the pressure reta ining 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 Evaluation Against Criterion 57. Lines forming a closed system outside the primary reactor containment must have one isolation valve outside if the system boundary penetrates the containment. All closed system s outside primary containment at Columbia have at least one isolation valve if they penetrate primary containment which provides isolation capabilities in accordance with Criterion 57. 6.2.4.3.2.4 Evaluation Against Regulatory Guide 1.11, Revisi on 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 . COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 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 less than 2000F. At this temperature virtua lly 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 . COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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).

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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)," dated 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 Letter, JW Clifford (NRC) to JV Parrish (Washington Public Power Supply System), "Issuance of Amendment for the Washington Public Power Supply System Project No. 2 (TAC NOS. M87 076 and M88625)," da ted May 2, 1995.

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. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052, 10-004, 15-011 6.2-68 6.2-36 Deleted.

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."

6.2-42 GE Hitachi Nuclear Energy, "Tec hnical Specification Change Support for RHR/LPCI and LPCS Flow Rate Long -Term LOCA Containment Response and ECCS/Non-LOCA Evaluations," NEDC -33813P, Class III (Proprietary), Revision 2, September 2013.

6.2-43 ARTS/MELLLA Task T0401A (CVI-1133-00,20) "Subcompa rtment (Annulus) Pressurization Loads-Mass and Energy Releases."

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-69 Table 6.2-1

Containment Design Parameters

Drywell Suppression Chamber A. Drywell and Suppression Chamber

1. Internal design pr essure, 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 ft3 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 1.995 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)

LDCN-13-052 6.2-70 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 Reduced ECCS Flow Case C A. Drywell Spray System

1. Number of pumps 2 2 1 N/A N/A 2. Number of lines 2 2 1 N/A N/A 3. Number of headers/line 1 1 1 N/A N/A 4. Spray flow rate, gpm/pump 7450 6713b,d 6713b N/A N/A 5. Spray thermal efficiency, % 100 100 100 N/A N/A B. Suppression Pool Spray

1. Number of pumps 2 2 1 N/A N/A 2. Number of lines 2 2 1 N/A N/A 3. Number of headers/line 1 1 1 N/A N/A 4. Spray flow rate, gpm/pump 450 353b 353b N/A N/A 5. Spray thermal efficiency, % 100 100 100 N/A N/A C. Containment Cooling System

1. Number of pumps 2 2 1 1a 1 2. Pump capacity, gpm/pump 7900 7067b 7067b 7067b 6713 LDCN-13-052 6.2-71 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-2 Engineered Safety Systems Information for Containment Response Analyses (Continued)

Value Used in Containment Analysis Full Capacity Case A Case B Case C Reduced ECCS Flow Case C

3. Heat Exchangers RHR system inverted U tube, single pass shell, multi pass tubes, vertical mounting

a. Number 2 2 1 1a 1 b. Heat transfer area, ft 2/Unit 7641 7641 7641 7641 7641 c. Overall heat transfer coefficient, Btu/hr ft 2 F 195(fouled) 400(clean) 195 195 195 195 d. Standby service water flow rate per exchanger, gpm 7400 7400 7400 N/A N/A e. RHR heat exchanger K value Btu/sec-°F 414(fouled) 849(clean)

N/A N/A 289 f f. Design service water temperature minimum, °F maximum, °F 32°F 85°F 95b 95b 90 f g. Containment heat removal capability per loop, using 85°F service water and 165°F pool

temperature; Btu/hr 83.23 x 10 6 LDCN-13-066, 13-052 6.2-71a COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-2 Engineered Safety Systems Information for Containment Response Analyses (Continued ) Value Used in Containment Analysis Full Capacity Case A Case B Case C Reduced ECCS Flow Case C D. ECCS Systems

1. High pressure core spray (HPCS)

a. Number of pumps 1 1 1 1a 1 b. Number of lines 1 1 1 1a 1 c. Flow rate, gpm 6350 6250 6250 6250a 6250 2. Low pressure core spray (LPCS)

a. Number of pumps 1 1 0 0a 0 b. Number of lines 1 1 0 0a 0 c. Flow rate, gpm 6350 6250 0 0a 0 3. Low-pressure coolant injection (LPCI)

a. Number of pumps 3 1e 1 1a 1 b. Number of lines 3 1e 1 1a 1 c. Flow rate, gpm 1 pump 7450c 7067b 7067b 7067a,b 6713 LDCN-13-052 6.2-71b COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-2 Engineered Safety Systems Information for Containment Response Analyses (Continued)

Value Used in Containment Analysis Full Capacity Case A Case B Case C Reduced ECCS Flow Case C

4. Residual heat removal (RHR)

a. Pump flow rate: shell side 7450 0 0 0 0 tube-side 7400 0 0 0 0 b. Source of cooling water Standby service water E. Automatic Depressurization System

1. Total number of safety/relief valves 18a 2. Number actuated on ADS 7a a No change due to uprate. Reference 6.2-35 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. f SW temperature is 85°F for 10 hours then 90°F thereafter; RHR heat exchanger K value varies from 284.5 to 288.8 Btu/sec-°F with suppression pool temperature.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-72 Table 6.2-3

Accident Assumptions and Initial Conditions for Recirculation Line Break

A. Effective accident break area (total), ft 2 3.106/3.189 d B. Components of ef fective break area: 1. Recirculation line suction nozzle area, ft 2 2.508a 2. RWCU cross tie line ft 2 0.078a 3. Jet pump nozzles, ft 2 0.520a C. Break area/vent area ratio 0.0105/0.0103 d D. Primary system energy distribution b 1. Steam and liquid energy, 10 6 Btu 414/361d 2. Sensible energy, 10 6 Btu a. Reactor vessel 106.1/220 d b. Reactor internals (less core) 58.6e c. Primary system piping 34.6e d. Fuel (c) E. Assumptions used in pressure transient analysis 1. Feedwater flow coastdown time 39.6 2. MSIV closure time (sec) 3.5/3.0 d 3. Scram time (sec) <1a 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 Second value represents conserva tive value used in analysis. e Reactor vessel sensible ener gy includes reactor internals (l ess core) and primary system piping. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-73 Table 6.2-4

Initial Conditions Employed in Containment Response Analyses

Original Rated Power Cases Uprated Power Reduced ECCS Flow A. Reactor coolant system (at 105% of rated steam flow and at normal liquid levels)

1. Reactor power level, MWt 3462 3702 3556 2. Average coolant pressure, psig 1020 1020 1020 Peak coolant pressure, psia 1055 1055 1055 3. Average coolant temperature, °F 547 551 551 4. Mass of reactor coolant system liquid, lb 676,700 634,300 634,300 5. Mass of reactor coolant system steam, lb 24,900 24,740 24,740 6. Volume of water in vessel, a ft3 12,743 13,282 13,282 7. Volume of steam in vessel, b ft3 10,167 10,397 10,397 8. Volume of water in recirculation loops, ft 3 670 (a) (a) 9a. Volume of water in feedwater line, c ft3 543 9b. Mass of water in feedwater line, lb 693,034 693,034 10. Volume of wate r in miscellaneous lines,c ft3 121 (a) (a) 11. Total reactor coolant volume, ft 3 23,580 23,679 23,679 12. Stored water

a. Condensate storage tanks, gal (min) 135,000 N/A N/A b. Fuel storage pool, gal 350,000 N/A N/A COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-74 Table 6.2-4

Initial Conditions Employed in Containment Respons e Analyses (Continued) Original Rated Power Cases Uprated Power Reduced ECCS Flow Drywell/ Suppression Chamber Drywell/ Suppression Chamber Drywell/ Suppression Chamber B. Containment

1. Pressure, psig 0.7/0.7 2.0/2.0 2.0/2.0 2. Inside temperature, °F 135/90 135/90 150/90 3. Outside temperature, °F NA/NA NA/NA NA/NA 4. Relative humidity, % 50/100 50/100 20/100 5. Service water temperature, °F 95/95 90/90 (d)/(d) 6. Water volume, ft 3 NA/ 107,850 NA/ 107,850 NA/ 107,850 7. Vent submergence, ft NA/12 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 85°F for 10 hours then 90°F thereafter

LDCN-13-052 6.2-75 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Original Rated Power Uprated Power Reduced ECCS Flow Accident Parameters Recirculation Line Break a Steam Line Breakb Recirculation Line Break Recirculation Line Break

1. Peak drywell pressure, psig 34.69 34.0 37.4 c,d 35.3c 2. Peak drywell diaphragm floor differential pressure, psid 19.39 19.1 21.7 (f) 3. Time (S) of Peak Pressures, Sec. 19.0 12.0 11.9 (g)

4. Peak drywell temperature, °F 280.2 328 283 c 281c 5. Peak suppression chamber pressure, psig 27.3 31.3 30.3 6. Time of peak suppression chamber pressure, sec. 55 55 139 (g)

7. Peak suppression pool temperature during blowdown, °F (~100 sec.) 140 140 146 148.3

8. Peak suppression pool temperature, long term, °F 220 220 204.5 203.8

9. Calculated drywell margin, %

e 22.9 24.5 16.9 (f)

10. Calculated suppression chamber margin,

%e 38.6 38.0 30.4 24.6 11. Calculated deck differential pressure margin, % 22.44 23.6 13.2 (f)

12. Energy released to containment at time of peak pressure, 10 6 Btu 260 204 174 (f)

13. Energy absorbed by passive heat sinks at time of peak pressure, 10 6 Btu 0 0 0 0 Table 6.2-5 Summary of Accident Re sults for Containment Response to Limiting Line Breaks

LDCN-13-052 6.2-75a COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-5 Summary of Accident Results for Containment Response to Limiting Li ne Breaks (Continued) 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 testin g was conservatively c hosen to be 38 psig. e (Design Pressure - Maximum Calculated Pressure) Design Pressure f Parameter determined in short-term containment analysis (Reference 6.2-35) and not updated based on the long term analysis presented in Reference 6.2-42. g Values are proprietary. See Reference 6.2-42.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-052 6.2-76a Table 6.2-6 Loss-of-Coolant Accident Long-Term Primary Containment Response (Continued) 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) C Reduced ECCS Flow 3556 MWt Before 600 seconds After 600 seconds 2/0 1/0 2 2 0 0 6250 6250 13,426/0 6713/0 203.8 15.9 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 106 107 x 10 6 107 x 10 6 40 x 106/66.6 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 106 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 106 629 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 ---- ----

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 ---- ----

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 102 0.0381 0.03436 103 0.0223 0.01956 104 0.0119 0.01012 105 0.00668 0.00546 106 0.00267 3 x 106 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. COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 106 ft3; 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 . COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015

LDCN-15-038 6.2-84a Table 6.2-14 Containment Penetrations Subject to Type B Tests (continued) Penetration Number Type Service Comments II. Personnel And Equipment Access Penetrations (continued) X-3 CEP-V-2A Inboard flange X-53 CSP-V-2 Inboard flange X-66 CSP-V-4 CSP-V-5 Inboard flanges X-67 CSP-V-4A CSP-V-6 Inboard flanges X-119 CSP-V-9 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 2011LDCN-10-028 6.2-86CIA 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-036 6.2-90 Rad 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 globe 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 globe 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-036 6.2-91 PASS DW atm 80b 6.2-57 56 B PSR-V-X80-1 SO globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe 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 globe O ac Spring -- RM C C O C 1 No -- No W Vlv RW Yes 5 50, 56, 64, 48a RCC 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 globe O 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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 COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORTDecember 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

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 LDCN-09-007 6.2-97 Table 6.2-16

Primary Containment Isol ation Valves (Continued)

ISOLATION SIGNAL CODES a Signal Description Ab Reactor vessel low-low water level (Trip level 2) Cb High radiation - main steam line Db Line break - main steam line (ste am line tunnel high temperature, high differential temperature or steam line high flow) Eb Reactor water cleanup system high diffe rential flow or hi gh blowdown flow Fb High drywell pressure Gb Low condenser vacuum Jb Line break in RWCU system - area high temperature or high differential temperature Kb 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] Lb 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) Mb Line break in RHR shutdown cooling (high suction flow) Pb Low main steam line pressure at turbine inlet (RUN mode only) Rb RHR equipment area high temperature or high differential temperature RM Remote manual switch located in main control room U High reactor vessel pressure

Vc 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

Zb 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. COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 positive closingSO Solenoid operated Location I inside containment O outside containment Power to Open/Close AC ac electrical power DC dc electrical powerEF excess flowpp process fluid overpressurization pro 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 steamW water Termination Zone CS condensate storage tan kRR reactor buildingRW radwaste buildingSB service buildingTB turbine building COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 lobe, 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 Electric, 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-040 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 50 Pool temperature, F N/A 50 3. Relative humidity, % 100 100 Spray temperature is equivalent to suppression pool temperature.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-14-040 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 1a 1a 0.57 0.55 1.38 0.61 1.88 1.11 (3) DBA 7 7 2 3 1a 2 0.55 0.67 0.71 0.81 1.21 1.31 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 (ft3) 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 (ft2) Inertia (L/A, ft-1) Form Loss Coefficient Friction Factor f KF* KR** 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. KF* = KForward KR** = KReverse

• Original rated power.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 (ft2) Inertia (L/A, ft-1) Form Loss Coefficient Friction Factor f KF* KR** 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. KF* = KForward KR** = KReverse

• Original rated power.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 seca - 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 hrb - 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.

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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) q1 = 33,161 (t pcw-tair), for tair< tpcw q1 = 0, for t air > tpcw tpcw = 105°F constant tair, r = reactor building air temperature Normal equipment decay heat Electrical equipment (combined) q2 = 1475 (150e -T-tair), for tair < 150e-T q2 = 0, for t air > 150e-T Max. eq. surface

Temperature = 150°F

for T < 0 Piping (combined) q3 = 664 (182e -T -tair ), for t air < 182 e-T q3 = 0, for t air > 182e-T Max. eq. surface Surface temp= 182°F for t < 0 Emergency equipment Emergency lighting (t > 0 sec) q4 = 203,700 Standby gas treatment system (T > 34 sec) q5 = 8800 Emergency core cooli ng system (T > 30 sec) q6 = 4476 (t cw - tair), for tair < tcw q6 = 0, for t air > tcw T,hr tcw,* oF 0 95 2 180 50 143 100 132

• cw = cooling water COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT 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 q7 = 299.2 (t pw-tair)4/3 tpw= pool water temp. oF Pool evaporation heat q8 = 1385.19 (t pw - tair)1/3 (Wps- Wair)p tpw = pool water temp. °F Wps = humidity ratio Saturated moist air Evaluated at t pw of wet surface (1bw/1ba) Wps = humidity ratio of moisture air (1bw/1ba)p = heat of vaporization (1bw/1ba) Infiltration air heat-up q9 = -0.24945 (t air - 100)> Structural steel heat-up q10 = - 11400 (t air - tsteel)4/3 tsteel = steel temp (°F) Total Q = q 1 + q2 + q3 + q4 + q5 + q6 + q7 +q8+ q9 +q10 Qq110101 Typical 24 in. Downcomer Vent with Jet Deflector 900547.40 6.2-1FigureAmendment 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" W121'-2"4"El. 501'-0" Saddle Clamps Downcomer Open End1'-1/4"1 1/4"1/2"Columbia Generating StationFinal Safety Analysis Report Diagram of the Recirculation Line Break Location 900547.36 6.2-2FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.CABRecirculation ReactorVesselPoint Of Critical Flow A. Recirculation Line B. Cleanup Line C. Combined Area of All Jet Pump Nozzles Associated with the

Broken Loop Recirculation LoopPumpTo Reactor Water

Cleanup System Columbia Generating StationFinal Safety Analysis Report Pressure Response for Recirculation Line Break(Initial Containment Pressure 2 psig) 900547.37 6.2-3FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.7550 250010203040Drywell PressureWetwell PressureTime (Seconds) Pressure (Pisa) Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Temperature Response for Recirculation LineBreak (Initial Containment Pressure 2 psig) 960222.02 6.2-401020304050150250350Time (Seconds)Drywell Temperature Temperature (degrees F)Wetwell Temperature Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev. Drywell Floor P Response for Recirculation Line Break (Initial Containment Pressure 2 psig) 960222.03 6.2-50102030400153045Time (Seconds) Pressure Difference (psid) Drywell-Wetwell Columbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Containment Vent System Flow Rate for Recirculation (Initial Containment Pressure 2 psig) 960222.04 6.2-60102030400123x104Time (Seconds) Vent Flow Rate (lb/seconds) AirVaporLiquidColumbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Containment Pressure Response Cases A, B, and C - Original Rated Power 960222.67 6.2-7Time (Seconds) Containment Pressure (psig) 40200102103104105106a) 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 3010cbaColumbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Drywell Temperature Response Cases A, B, and C - Original Rated Power 960222.26 6.2-8a) 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 abc400300200 1000101102103104105Time (Seconds) 106Columbia Generating Station Final Safety Analysis Report Drywell Temperature (°F) FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Suppression Pool Temperature Response, Long-Term Response - Original Rated Power 960222.27 6.2-9ab.c4003002001000101103104105106Time (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) FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Containment Pressure Response - Case C Uprated Power 960222.05 6.2-100204060Pressure (psia) Time (Seconds) Drywell Pressure Wetwell Pressure Drywell Pressure Wetwell Pressure 101102103104105Columbia Generating Station Final Safety Analysis Report FigureAmendment 57 December 2003 Form No. 960690 Draw. No. Rev.Drywell Temperature Response - Case C Uprated Power 960222.06 6.2-11101100200300400Time (Seconds) Drywell Airspace Temperature Temperature (Degrees F) 102103104105Columbia Generating Station Final Safety Analysis Report LDCN-02-000 FigureForm No. 960690 Draw. No. Rev.Suppression Pool Temperature Response - Case C Uprated Power 960222.07 6.2-120100200300Time (Seconds) Temperature (Degrees F) Suppression Pool Temperature 101102103104105Columbia Generating Station Final Safety Analysis Report Amendment 57 December 2003 LDCN-02-000 FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Residual Heat Removal Rate 960222.15 6.2-13050100Time (hour) 12525750248101216182022242628303234363840424448 61501752002 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) FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Effective Blowdown Area Main Steam Line Break 960222.28 6.2-1443 2 1 0Time (Seconds) Flow Area (Ft 2)10030050060040020005Columbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Bounding Pressure Response - Main Steam Line Break Original Rated Power 960222.30 6.2-15Pressure (psig) Wetwell30201000.1110102103Time (Seconds) Drywell40Columbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Bounding Temperature Response - Main Steam Line Break Original Rated Power 960222.29 6.2-16Wetwell30020010000.1110102103Time (Seconds) Temperature (°F) DrywellColumbia Generating Station Final Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Pressure Response - Recirculation Line Break (0.1 ft2) Original Rated Power 960222.31 6.2-17Pressure (psig)Wetwell30201000.1110102103Time (Seconds) Drywell40Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Temperature Response - Recirculation Line Break (0.1 ft2) Original Rated Power 960222.32 6.2-18Temperature (Degrees F)Wetwell300200 10000.1110102103Time (Seconds) Drywell400Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Schematic of ECCS Loop 900547.39 6.2-19ReactorVesselSuppression Pool MWshsmDohDmsoRHR HeatExchanger hc, meccsqHxPump= 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 mDohDmsomeccsqHxhcMWshsqDqeColumbia Generating StationFinal Safety Analysis Report Allowable Leakage Capacity (A/ K ft 2)FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Allowable Leakage Capacity 960222.39 6.2-20( )ADBA2ADBA0.400.35 0.30 0.25 0.20 0.15 0.10 0.0500.41.02.03.04.0Primary System Break Area (ft 2)AKSColumbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Containment Transient for Maximum Allowable Bypass Capacity A x = 0.050 960222.38 6.2-21100100010,000500400300200100070(45)60(35)50(25)40(15)30(15)20Time (seconds) abdca 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. Timeduringwhichdrywellspraysmust beactivated (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 FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Containment Transient for A/ K = 0.0045 ft 2960222.37 6.2-22100100010,000500400 300200 10007060 504030 20Time (seconds) Pressure (psia)Containment Vessel Design Pressure abdca 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 20.5"Venting Through Bulkhead Plate 920843.15 6.2-24FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.21.25"AllDrawingsnot toScaleBlindFlange20.5"FanVentPathVentPathVentilation Supply Duct Azimuth195, 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 0315255195180Vent135751514.29'1.36'Columbia Generating StationFinal Safety Analysis Report Absolute Pressure in Upper Head Region andLower Region from 6 in. RCIC Line Break920843.11 6.2-25FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.28242016128 40Absolute 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) 00.51.01.52.0Time, 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 6.2-26FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.706050403020100Absolute 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) 00.51.01.52.0Time, Seconds Absolute Pressure, psia Columbia Generating StationFinal Safety Analysis Report Downward Pressure Differential Across BulkheadPlate from 6 In. Line Break 920843.13 6.2-27FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.1412108 642000.51.01.52.0Time, 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 6.2-28FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.1412108 642000.51.01.52.0Time, Seconds Differential Pressure, psiUpward Pressure Differential Across Bulkhead Plate from a 24 Inch Recirculation Line Break Columbia Generating StationFinal Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Recirculation Break Blowdown Flow Rates Liquid Flow - Short-Term Original Rated Power 960222.10 6.2-29020401201400102035Time (Seconds) Vessel Liquid Blowdown Flow Rate (lb/sec x 1E3) 60801003025515Columbia Generating Station Final Safety Analysis Report FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Recirculation Break Blowdown Flow Rates Steam Flow - Short-Term Original Rated Power 960222.11 6.2-300204012014001.02.03.5Time (Seconds) Vessel Steam Blowdown Flow Rate (lb/sec x 1E3) 60801003.02.50.51.5Columbia Generating Station Final Safety Analysis Report Main Steam Line Break Blowdown Flow Rates FigureAmendment 53November 1998 Form No. 960690 Draw. No. Rev.960222.36 6.2-31051015202530354045505560 01 2 3 4Liquid Flow Steam Flow Time (Seconds) Vessel Flow Rates (lb/sec x 10 4)Columbia Generating Station Final Safety Analysis Report Post-LOCA Time (sec) 6.2-34920843.17Long-Term Post-LOCA Secondary ContainmentTemperature Transient Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 59 December 2007 Form No. 960690FH LDCN-05-009 150140130120100908070102103104105106107101ECCS Pump Rooms Bulk Reactor Bldg Refuel Floor110Temperature (F) 6.2-35920843.16Short-Term Post-LOCA Secondary ContainmentPressure Transient Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 59 December 2007 Form No. 960690FH LDCN-05-009 14.7414.7214.70 14.6814.6614.6414.6214.6014.5814.5614.541ECCS Pump Rooms Atmospheric PressureBulk Reactor Bldg Refuel FloorPost-LOCA Time (sec) 102103104105106101Pressure (psia) Notes on Type C Testing 920843.20 6.2-36FigureForm 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 6.2-37FigureForm 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 AOAOMOMOMOCSP-V-1CSP-V-3CSP-V-2 CSP-V-4For X-66 Only See Fig. 6.2-52 X-53 (Drywell)X-66 (Wetwell) PurgeSupplyTCN2 SupplyCSP-V-97 CSP-V-98CSP-V-96 CSP-V-93SOSORFW-V-65BRFW-V-32BRWCU-V-40RFW-V-65ARFW-V-32A X-17BRFW-V-10B TCX-17ARFW-V-10A TCTCTCColumbia 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 6.2-38FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 1 on Figure 6.2-36 RRC Pump Seal PurgeContainment Instrument Air MONote: See Note 1 on Figure 6.2-36 MOCIA-V-30ACIA-V-30BCIA-V-20CIA-V-31A CIA-V-31BCIA-V-21TCTCX-89BX-91 X-56DrywellRRC-V-16A,B TCTCRRC-V-13A,B X-43A,BDrywellColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-117, X-118 and X-77Aa 920843.21 6.2-39Note: See Note 1 on Figure 6.2-36 Note: See Note 5 on Figure 6.2-36 X-77AaRRC-V-19TCTCSample PointRRC-V-20WetwellMOStructural SectionTCTCX-117X-118RHR-RV-1A,BRHR-RV-30(X-118 Only) MOMOMORHR-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.FigureForm No. 960690FH LDCN-08-028 RCC Sample Line RHR Steam Lines LCDeactivated 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 6.2-40FigureAmendment 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-21TCX-45Notes: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 AOMORCIC-V-13RCIC-V-65 X-2RCIC-V-66 TCMORCIC-V-63 LCMORCIC-V-8To MS Line MORCIC-V-76RCIC-V-742 LCSamplePointTCTCMORHR-V-23RPVTCDrywellColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-49, X-63, X-26 and X-22 950021.13 6.2-41FigureForm No. 960690FH LDCN-08-028Draw. No.Rev.MONote: See Note 4 on Figure. 6.2-36 MS Drain Line MOMOMOMS-V-19MS-V-16X-22TCX-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 TCX-49X-63X-26WetwellHPCS-RV-14 LPCS-RV-18RHR-RV-25CHPCS-RV-35 LPCS-RV-31RHR-RV-88C RHR Loop C OnlyHPCS-V-23LPCS-V-12RHR-V-21Columbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 6.2-42920843.08 Isolation Valve Arrangement for Penetrations X-11A and X-11B Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 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,BMORHR-V-17A,B TC Isolation Valve Arrangement for PenetrationsX-65, X-25A and X-25B 920843.09 6.2-43FigureForm No. 960690FH LDCN-08-028Draw. No.Rev.Note: See Note 2 on Figure 6.2-36RHR Wetwell SprayWetwellRCIC Pump Min. Flow MONote: See Note 5 on Figure 6.2-36RCIC-V-19 TCX-65MORHR-V-27A, B X-25AX-25BTCLoop A OnlyTCColumbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 Isolation Valve Arrangement for Penetration X-100 920843.10 6.2-44FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.WetwellSuppression Pool Cleanup Suction Line MONote: See Note 4 on Figure 6.2-36FPC-V-154 TCX-100MOFPC-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 6.2-45FigureAmendment 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 RPVX-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 AOAOCEP-V-1A CEP-V-3AAOAOCEP-V-2B CEP-V-4BCEP-V-1B CEP-V-3BTCForm 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 6.2-46MONote: See Note 1 on Figure 6.2-36 for X-23 And X-24 X-20X-14MORHR-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-20OnlyAOEDR-V-20AOX-23WetwellTCAOFDR-V-4AOX-24WetwellFDR-V-15L.O.FDR-V-3EDR-V-19TCTCNote: See Notes 1 (X-20 Only), and 4 (X-14 Only) on Figure 6.2-36 TCTCTCDrywellColumbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 58 December 2005 Form No. 960690FH LDCN-05-007 EDR-V-18L.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 6.2-47FigureForm 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 RPVMORHR-V-42 (A,B,C)HPCS-V-4LPCS-V-5RHR-V-41 (A,B,C)HPCS-V-5LPCS-V-6X-12A,B,C X-6 X-8TCTCPrimary Containment "Drywell" TCDW-V-156LCDW-V-157LCNote: 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 6.2-48FigureAmendment 57December 2003 Form No. 960690Draw. No.Rev.MORHR-V-53A,B Note: See Note 2 on Fig. 6.2-36 TCRHR SHUTDOWN COOLING RETURN X198B Only X-19A,BTCTCTCAODrywellRHR-V-50A,BRHR-V-123A,B E*SLC-V-4BNote: See Note 2 on Fig. 6.2-36 SLC SYSTEM INJECTION LINE X-13TCDrywellTCHPCS-V-76 RPVSLC-V-7E*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 6.2-49FigureForm 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)WetwellNote: See Note 5 on Fig. 6.2-36 X-33 X-31X-35X-32X-36X-34X-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 TCColumbia Generating StationFinal Safety Analysis Report Amendment 61 December 2011 Isolation Valve Arrangement for Penetrations X-46 and X-101 920843.26 6.2-50FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Note: See Note 4 on Figure 6.2-36 RCC Return Line X-46Suppression Pool Cleanup Return Line MOFPC-V-149 X-101TCTCNote: See Note 4 on Figure 6.2-36 MORCC-V-40RCC-V-219RCC-V-220RCC-V-221 MOFPC-V-156 MORCC-V-21Columbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-47 and X-48 950021.14 6.2-51FigureAmendment 61 December 2011 Form No. 960690FH LDCN-08-028Draw. No.Rev.MONote: See Note 5 on Figure 6.2-36 RHR Combined Return Line to Suppression Pool MOX-47, X48RHR-V-120 FDRSystem(X-47 Only) 2" Blind FlangeRHR-RV-88A,B MOSeeFigure 6.2-56 See Figure 6.2-39 Structural ConnectionRHR-RV-25A,BRHR-RV-5(X-48 Only)RHR-V-121 LCLCLCRHR-V-11A,BRHR-V-24A,B LORHR-V-172A,B X47 OnlyRHR-FCV-64 A,BValve Disk RemoveRHR-V-46A,BRHR-V-18A,B LOColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-66, X-67, X-119, X-64 920843.27 6.2-52FigureForm 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 AOX-64TCTCTCNote: See Note 5 on Figure 6.2-36 AOX-66X-67 X-119WetwellRCIC-V-28WetwellX-119 OnlyFor X-66 Only See 6.2-37For X-67 Only See 6.2-45CSP-V-5 CSP-V-6 CSP-V-9CSP-V-7 CSP-V-8CSP-V-10Columbia 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 6.2-53Amendment 56December 2001 FigureForm 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 N2/Air Supply for Testing Wetwell to Drywell Vacuum Breakers TCNote: See Note 8 on Figure 6.2-36WetwellDrywellLCNONCLCLCX-82ECAS-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 TestersLCLDCN-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 6.2-54FigureAmendment 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 TCNote: See Note 1 on Figure 6.2-36 DrywellPI-VX-250 PI-VX-256 SOPI-VX-251

PI-VX-257 SOX-85C X-29CX-85A X-29API-VX-253

PI-VX-259 SOPI-EFC-72F PI-EFC-73E X-72FX-73EColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for Penetrations X-5 and X-93 920843.30 6.2-55FigureAmendment 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-5X-93MORCC-V-5MODrywellSA-V-109Pipe CapColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-4 and X-116 920843.31 6.2-56FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.RCIC Turbine Exhaust andTurbine Exhaust Vacuum Breaker Note: See Note 4 on Figure 6.2-36WetwellX-116X-4RCIC-V-68 MOWetwellMOMOSee Fig 6.2-51RCIC-V-40 TCTCColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-73F, X-77Ac, X-77Ad, X-80B 920843.32 16.2-57FigureAmendment 63December 2015 Form No. 960690 LDCN-15-036Draw. 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 SODrywellX-73FX-80BPSR-V-X73-1 PSR-V-X80-1 SOPSR-V-X77A2 PSR-V-X77A4 SOX-77AcX-77AdPSR-V-X77A1 PSR-V-X77A3 SOX-77Ac Jet Pump #10 Sample Line X-77Ad Jet Pump #20 Sample Line TCTCColumbia Generating StationFinal Safety Analysis Report Isolation Valve Arrangement for PenetrationsX-82D, X-82F, X-83A, X-84F, X-88 920843.33 16.2-58FigureDraw. No.Rev.Note: See Note 1 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 1 on Figure 6.2-36WetwellX-83AX-84FX-82FPSR-V-X82-1 PSR-V-X88-1 SOX-82DX-88PSR-V-X82-2 PSR-V-X88-2 SOX-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 SOTC(X-88 Only)Wetwell(X-88 Only) Columbia Generating StationFinal Safety Analysis Report Amendment 63December 2015 Form No. 960690 LDCN-15-036 Isolation Valve Arrangement for Penetrations X-94 and X-95 920843.34 6.2-59FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.X-94X-95MWR-V-124 MWR-V-125 X Decon Solution Supply Header X Decon Solution Return Header DrywellT.C.Columbia Generating StationFinal Safety Analysis Report FigureAmendment 54 April 2000 Form No. 960690Draw. No.Rev.960222.68 6.2-60Columbia Generating StationFinal Safety Analysis Report DELETED(SHEETS 1 THROUGH 4) Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.FigureAmendment 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)200100030102103104105106107Service Water Temperature = 95FMinimum ECCS COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 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 evalua tion. Subsection 6.3.1 discusses the design bases. Subsection 6.3.2 describes the systems. Subsection 6.3.3 discusses the system res ponses 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. 6.3.1 DESIGN BASES AND 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) break 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.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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,

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-010, 03-003 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 system consists 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

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 LDCN-02-010, 03-003 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 the reactor vessel press ure is less than the value in 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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,

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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 204.5F and bounding flowrates for the time of peak pool temperature. This is the bounding configuration for minimizing available NPSH. The analysis which established the 204.5F 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;

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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 90F. Standby servi ce water, which cools the RHR heat exchanger, is also at 90F. 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 90F to 204.5F, 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 204.5F 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 204.5F 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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 hours) 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 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), Maximum Extended Load Line Limit Analysis (MELLLA), 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 accident (DBA) event. The NSSS vendor analyses are described in References 6.3-1, 6.3-2, 6.3-4, 6.3-5, and 6.3-7. 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 References 6.3-15 and 6.3-5. The GNF2 analysis confirms the small break of 0.07 ft 2 in the recirculation suction line as still limiting, with top peaked axial power shape and fa ilure of the HPCS diesel generator assumed. The GNF2 analysis is described in Reference 6.3-16. A summary description of the re load design basis LOCA analysis methods is provided in this section. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-21 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. 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 level 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.

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 . Criterion 4, Cool able Geometry "Calculated changes in core geometry shall be such that th e core remains amenable to cooling." Conformance to Criterion 4 is demonstrat ed by conformance 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." COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-22 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.

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 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.

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 operating parameters, fuel parameters and ECCS initiation parameters used in the LOCA analysis are provided in Tables 6.3-2a, 6.3-2b and 6.3-2c, respectively. The representative COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-23 sequences of events are presented in Tables 6.3-4a and 6.3-4b. 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.

6.3.3.5 Use of Dual Function Components 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.3-24 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 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 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-25 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 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 Anal ysis Procedures a nd Input Variables

The GE Hitachi Nuclear Energy ECCS-LOC A licensing evaluation methodologies are described in References 6.3-7 through 6.3-14. The GE14 analysis is documented in Reference 6.3-5 and 6.3-15, consistent with References 6.3-1 and 6.3-2. The GNF2 analysis is documented in Reference 6.3-16, consistent with References 6.3-1, 6.3-2 and 6.3-5. These vendor methodologies cover the time from the even t until the reactor has been reflooded. The NSSS vendor, GE, performed the long term ECCS evaluation, as described in Reference 6.3-7. The evaluation documents that the ECCS satisfy the requi rements describe d in Section 6.3.3.2. As documented in Reference 6.3-1, the reactor power uprate and the new fuel did not impact the conclusions reached in Reference 6.3-7. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-26 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, TASC, PRIME, and SAFER (References 6.3-7 through 6.3-14). Together, these models evaluate the short-term and long-term reactor vessel blowdown response to a pipe rupture, the subsequent co re 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 TASC model for calculating blowdown heat transfer and fuel dryout time. The TASC model completes the transient short-term thermal-hydraulic calculation for large recirculation line breaks. "TASC" is used to predict the time and locat ion 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 PRIME model provides the parameters to in itialize the fuel stored energy and fuel rod fission gas inventory at the ons et of a postulated LOCA for input to SAFER. PRIME also establishes the transient pelle t-cladding gap conductance for i nput to both SAFER and 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 Deleted. 6.3.3.6.2.3 LOCA Anal ysis Input Variables The significant input variables used by the LOCA codes are listed in Table 6.3-1, Table 6.3-2a and Table 6.3-2b. The limiting calculation was perfor med at 3629 MWt (104. 1% power) and 108.5 Mlb/hr (100% core flow), References 6.3-5 and 6.3-16. Alternate operating modes of SLO, increased core flow (ICF), reduced core flow (MELLLA) and reduced feedwater temperature (FFWTR/FWHOOS) have been confirmed as non-limiting. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-27 6.3.3.7 Break Spectrum Calculations

Break spectrum analyses have been performed to establish the limiting break for the CGS boiling water reactor BWR5 reactor system. Pr evious analyses by GE, the NSSS vendor have shown that a large pipe break in the recirculation line on the suc tion side of the recirculation pump is the most limiting break for a BWR5. The GE analysis incl udes breaks in both recirculation and non-recirculation piping. Figure 6.3-9 shows the original plant break spectrum analysis for initial core fuel. For reload fuel, the break spectrum is determined and documented in Reference 6.3-5 (MELLLA), 6.3-15 (GE14) and 6.3-16 (GNF2), consistent with the original plant break spectrum analysis in References 6.3-1 and 6.3-7. 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. 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 Calculati on, 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 0.07 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 are also performed with the limiting single failure. The 100%, 80%, and 60 % DBA cases also satisfy the Appendix K requirement for using th e Moody Slip Flow Model with three discharge coefficients of 1.0, 0.8, and 0.6, respectively. The limiting A ppendix K case for large break is the 100% DBA with top-peaked axial power shape and HPCS DG failure. The overall limiting LOCA is the small recirculation suct ion line break of 0.07 ft 2 for Appendix K assumptions with top peaked axial power shape and HPCS DG failure.

The analysis also considers the non-recirculati on line breaks (CS line, LPCI line and etc.) as well as alternate operating modes (MELLLA, IC F, FFWTR/FWHOOS and SLO) References 6.3-5, 6.3-15 and 6.3-16 documents all the analysis results.

6.3.3.7.2 Deleted.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-28 6.3.3.8 Loss-of-Coolant Accide nt Analysis Conclusions

The ECCS will perform the required design functions and comply with 10 CFR 50.46 acceptance criteria.

The limiting large break for two loop operation is the recircula tion suction line break of DBA with HPCS diesel generator failure at 104.1% rated power (3629 MWt)/100% rated flow conditions with a mid peaked axial power shape (References 6.3-5, 6.3-15 and 6.3-16). The overall limiting LOCA is the small reci rculation suction line break of 0.07 ft 2 for Appendix K and nominal assumptio ns, respectively, with high pr essure core spray diesel generator failure at 104.1% ra ted power (3629 MWt)/100% rated flow conditions and a top peaked axial power shape (References 6.3-5, 6.3-15 and 6.3-16). 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 (References 6.3-5, 6.3-15 and 6.3-16). Extended operation in the MELLLA domain is not analyzed for SLO. 6.3.4 TESTS AND INSPECTIONS

6.3.4.1 Emergency Core Cooli ng 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. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.3-29 6.3.4.2 Reliability Te sts 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 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. COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.3-30 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.

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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-31 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 GE Hitachi Nuclear Energy Report 0000-0105-1741-R0, "E nergy Northwest Columbia Generating Station ARTS /MELLLA Task T0407: ECCS-LOCA Evaluations," October 2009.

6.3-6 Deleted.

6.3-7 General Electric Company, "General Electric Company Analytical Model for Loss-of-Coolant Analysis in Accordance with 10CFR50 Appendix K," NEDO-20566-A, September 1986.

6.3-8 "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-23785-1-PA, Revision 1, October 1984.

6.3-9 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 2, SAFER - Long Term I nventory Model for BWR Loss-of-Coolant Analysis," NEDE-2378 5-1-PA, Revision 1, October 1984.

6.3-10 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 3, SAFER/GESTR- Appli cation Methodology," NEDE-23785-1-PA, Revisi on 1, October 1984.

• psid - differential pressure be tween RPV and pump suction source.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-32 6.3-11 "The GESTR-LOCA and SAFER Models for the Evaluation of the Loss-of-Coolant Accident. Vol. 3, Supplement 1, Additional Information for Upper Bound PCT Calculation," NEDE-23785P-A, Revision 1, March 2002.

6.3-12 "TASC-03A A Computer Program for Transient Analysis of a Single Channel," NEDC-32084P-A, Revisi on 2, July 2002.

6.3-13 "Compilation of Improvements to GENE's SAFER ECCS-LOCA Evaluation Model," NEDC-32950P, Re vision 1, July 2007.

6.3-14 "The PRIME Model for Analysis of Fuel Rod Thermal-Mechanical Performance," Part 1 - Technical Bases - NEDC-33256P-A, Part 2 - Qualification - NEDC-33257P-A, and Part 3 Application Methodology - NEDC-33258P-A, Revision 1, September 2010.

6.3-15 "Columbia Generati ng Station GE14 ECCS-LOCA Evaluation," GE Hitachi Nuclear Energy, 0000-0090-6853-R0, February 2009.

6.3-16 "Columbia Generati ng Station GNF2 ECCS-LOC A Evaluation," 001N0373-R2, February 2015.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-066 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) 8100 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-10-004, 15-011 6.3-38 Table 6.3-2a Plant Operational Parameters Parameter Nominal Assumption Appendix K Assumption Rated Case Core Thermal Power (MW) 3629 3702 Rated Case Core Flow (Mlbm/hr) 108.5 108.5 MELLLA Case Core Thermal Power (MW) 3629 3702 MELLLA Case Core Flow (Mlbm/hr) 93.04 93.04 ELLLA SLO Case Core Thermal Power (MW) 2684.2 2737.9 ELLLA 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) Feedwater temperature: Nominal - 65°F or 355°F, whichever is lower.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-39 Table 6.3-2b Fuel Parameters Parameter GE14 GNF2 PLHGR (kW/ft) - LOCA Analysis Limit - Appendix K

- Nominal 13.40 13.40 x 1.02 

12.80 14.40 14.40 x 1.02 13.75 MAPLHGR (kW/ft) - LOCA Analysis Limit - Appendix K - Nominal 12.82 12.82 x 1.02 12.24 13.78 13.78 x1.02 13.15 Peak Pellet Exposure (MWd/MTU) 16,000 14600 Initial Operating MCPR - LOCA Analysis Limit

- Appendix K 
- Nominal 1.25 1.25 ÷ 1.02 

1.25 + 0.02 1.25 1.25 x1.02 1.25 + 1.02 Fueled Rods per Assembly 92 92 COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-40 Table 6.3-2c ECCS Parameters 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 which injection valve may open psig 336 f. Maximum delay time from pump start until pump is at rated speed sec 26 g. Maximum injection valve stroke time-opening sec 26 h. Delay time to process initiation signal sec 5

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-41 Table 6.3-2c ECCS Parameters (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 which injection valve may open psig 336 f. Maximum delay time from pump start until pump is at rated speed sec 7 g. Maximum injection valve stroke time-opening sec 22 h. Delay time to process initiation signal sec 5

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-42 Table 6.3-2c ECCS Parameters (Continued) High Pressure Core Spray (HPCS) System Variable Units Analysis Value a. Vessel Pressure at which flow may commence psid (vessel to source) 1160 b. Minimum rated flow a nd 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-43 Table 6.3-2c ECCS Parameters (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 below 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 5 e. 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-44 Table 6.3-3 Single Failure Considered in ECCS Performance Evaluation 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.

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-45 Table 6.3-4a Event Scenario for 100% DBA Re circulation Suc tion Line Break HPCS DG Failure (Appendix K) Event GNF2 GE14 Time (sec) Time (sec) Break Occurs 0.00 0.0 Scram Initiated and Occurs 0.01 0.01 Level 1 Trip 4.88 4.97 Feedwater Flow Reaches Zero 4.00 5.00 First Peak PCT Occurs 6.90 5.50 Jet Pump Suction Uncovers 5.94 5.98 Main Steamline Flow Stops 6.66 6.14 Suction Line Uncovers 8.76 8.54 Lower Plenum Flashes 9.61 9.15 LPCS/LPCI IV Pressure Permissive Reached 30.53 30.45 LPCS Injection Occurs 57.53 57.45 LPCI Injection Occurs 61.53 61.45 Second Peak PCT Occurs 142.50 148.18

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-46 Table 6.3-4b Event Scenario for 0.07 ft 2 Recirculation Suction Line Break HPCS DG Failure (Appendix K) Event GNF2 GE14 Time (sec) Time (sec) Break Occurs 0.00 0.0 Scram Initiated and Occurs 0.01 0.01 Feedwater Flow Reaches Zero 4.00 5.00 Level 1 Trip 107.23 114.50 SRVs Open 170.02 178.47 Jet Pump Suction Uncovers 212.86 221.47 ADS Valves Open 232.23 239.50 Main Steamline Flow Stops 240.12 246.99 Lower Plenum Flashes 242.98 248.61 Suction Line Uncovers 366.89 369.46 LPCS/LPCI IV Pressure Permissive Reached 384.79 394.23 LPCS Injection Occurs 411.79 421.23 LPCI Injection Occurs 415.79 425.23 Peak PCT Occurs 445.67 450.81

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-15-011 6.3-47 Table 6.3-5 ECCS Performance Analysis Results Parameter GE14 Value GNF2 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) 106.2% rated power (3702 MWt) 78.5% rated power (2737.9 MWt) Core flow 100% rated flow (108.5 Mlb/hr) 57% rated flow (61.845 Mlb/hr) 100% rated flow (108.5 Mlb/hr) 57% rated flow (61.845 Mlb/hr) Limiting break 0.07 ft2 Recirculation suction line, HPCS DG failure 100% DBA Recirculation suction line, HPCS DG failure 0.07 ft2 Recirculation suction line, HPCS DG failure 100% DBA Recirculation suction line, HPCS DG failure Peak cladding temperature

(Appendix K) 1647°F 1210°F 1637°F 1316°F Licensing basis peak

cladding temperature 1710°F 1700°F Maximum cladding

oxidation 1% 1% Total core hydrogen

generation 0.1% 0.1%

FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Head Versus Low-Pressure Core Spray Flow used in LOCA Analysis 960222.13 6.3-1010002000600070000100200Flow (gpm)300040005000 30025050150Columbia Generating Station Final Safety Analysis Report Pressure Vessel Head Over Drywell (psid) FigureAmendment 53 November 1998 Form No. 960690 Draw. No. Rev.Head Versus Low-Pressure Coolant Injection Flow used in LOCA Analysis 960222.14 6.3-2010002000600070000100200Flow (gpm)300040005000 25050150Columbia Generating Station Final Safety Analysis Report Pressure Vessel Head Over Drywell (psid) Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 06.3-3.1702E22-04,7,1High-Pressure Core Spray - Process DiagramRev.FigureDraw. No.

Amendment 63December 2015 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 6.3-4103M520High-Pressure Core Spray and Low-Pressure Core Spray Flow DiagramsRev.FigureDraw. No. FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Head Versus High-Pressure Core Spray Flow used in LOC A Analysis960222.12 6.3-5010002000600070000400800Flow (gpm) Pressure Vessel Head Over Drywell (psid)300040005000 12001000200600Columbia Generating StationFinal Safety Analysis Report Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 6.3-6802E21-04,4,1Low-Pressure Core Spray - Process DiagramRev.FigureDraw. No. Typical 48 in. Diameter Strainer 920843.07 6.3-7FigureAmendment 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 6.3-8FigureAmendment 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 FigureAmendment 53November 1998 Form No. 960690Draw. No.Rev.Peak Cladding Temperature and Maximum LocalOxidation Versus Break Area - Hanford Original Rated Power 960222.23 6.3-9Suction 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 0100020000.010.11.0Break Area (Square Feet) Peak Cladding Temperature (°Fahrenheit) 01020Maximum Local Oxidation (%) Columbia Generating StationFinal Safety Analysis Report COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-044 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 hours 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 LDCN-13-044 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. In the event of a hazardous radio activity release, the operators may respond by closing the appropriate remote intake isolation valves. Portable breathing 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/m3 2-minute toxicity limit specified in Reference 6.4-4. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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). COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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 COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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).

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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;

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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.

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT 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. COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT 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 30C 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

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT 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 200F. The Preservice Inspection Program Plan (Reference 5.2-6) addresses 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.

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT 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.}}