ML21349B380

Attachment 5: Columbia Generating Station FSAR, Amendment 66, Part 4 of 10

ML21349B380
Person / Time
Site:	Columbia
Issue date:	12/15/2021
From:	Energy Northwest
To:	Office of Nuclear Reactor Regulation
Shared Package
ML21349B351	List: GO2-21-131, Attachment 5: Columbia Generating Station FSAR, Amendment 66, Part 9 of 10 ML21349B338 ML21349B352 ML21349B353 ML21349B354 ML21349B367 ML21349B368 ML21349B380 ML21349B384 ML21349B385 ML21349B387 ML21349B388
References
GO2-21-131
Download: ML21349B380 (640)

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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 4.1

SUMMARY

DESCRIPTION ............................................................ 4.1-1 4.1.1 REACTOR VESSEL .................................................................... 4.1-1 4.1.2 REACTOR INTERNAL 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 Configuration ................................................................. 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 CONTROL 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 Structure) .............................. 4.1-10 4.1.4.1.1.1 Program 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 Extent of Application............................................................. 4.1-10 4.1.4.1.2 SNAP (MULTISHELL) ............................................................. 4.1-10 4.1.4.1.2.1 Program 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 Extent of Application............................................................. 4.1-11 4.1.4.1.3 GASP.................................................................................. 4.1-11 4.1.4.1.3.1 Program 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 Extent of Application............................................................. 4.1-11 4.1.4.1.4 NOHEAT ............................................................................. 4.1-11 4.1.4.1.4.1 Program Description............................................................. 4.1-11 LDCN-02-022, 03-003 4-i

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 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 Extent of Application............................................................. 4.1-12 4.1.4.1.5 FINITE................................................................................ 4.1-12 4.1.4.1.5.1 Program 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 Program 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 Extent of Application............................................................. 4.1-13 4.1.4.1.7 SHELL 5.............................................................................. 4.1-13 4.1.4.1.7.1 Program 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 Extent of Application............................................................. 4.1-14 4.1.4.1.8 HEATER .............................................................................. 4.1-14 4.1.4.1.8.1 Program 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 Extent of Application............................................................. 4.1-14 4.1.4.1.9 FAP-71 (Fatigue Analysis Program)............................................. 4.1-14 4.1.4.1.9.1 Program 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 CREEP/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 Extent 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 LDCN-02-000, 02-022, 03-003 4-ii

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 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, Hydriding, and Corrosion Limits .................................. 4.2-1 4.2.1.1.5 Dimensional Change Limits ....................................................... 4.2-1 4.2.1.1.6 Internal Gas 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 Hydriding Limits .................................................................... 4.2-2 4.2.1.2.2 Cladding Collapse Limits .......................................................... 4.2-2 4.2.1.2.3 Fretting Wear Limits ............................................................... 4.2-2 4.2.1.2.4 Overheating of Cladding Limits .................................................. 4.2-2 4.2.1.2.5 Overheating of Pellet Limits ...................................................... 4.2-2 4.2.1.2.6 Excessive Fuel Enthalpy Limits .................................................. 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 Expulsion of Fuel Limits ................................................ 4.2-3 4.2.1.3.3 Generalized Cladding Melt Limits ............................................... 4.2-3 4.2.1.3.4 Fuel Rod Ballooning Limits ....................................................... 4.2-3 4.2.1.3.5 Structural Deformation Limits .................................................... 4.2-3 4.

2.2 DESCRIPTION

AND DESIGN DRAWINGS ..................................... 4.2-3 4.2.2.1 Control Rods ........................................................................... 4.2-3 4.2.2.2 Velocity Limiter ....................................................................... 4.2-5 LDCN-10-029 4-iii

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 4.2.3 DESIGN EVALUATION .............................................................. 4.2-6 4.2.3.1 Fuel System Damage Evaluation ................................................... 4.2-6 4.2.3.1.1 Stress/Strain Evaluation............................................................ 4.2-6 4.2.3.1.2 Fatigue Evaluation .................................................................. 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 Load 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 Hydriding Evaluation .............................................................. 4.2-7 4.2.3.2.2 Cladding Collapse Evaluation .................................................... 4.2-7 4.2.3.2.3 Fretting Wear Evaluation .......................................................... 4.2-7 4.2.3.2.4 Overheating 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 Bursting Evaluation ................................................................. 4.2-8 4.2.3.2.9 Mechanical Fracturing Evaluation ............................................... 4.2-8 4.2.3.3 Fuel Coolability 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 Cladding Melt Evaluation .......................................... 4.2-8 4.2.3.3.4 Fuel Rod Ballooning Evaluation ................................................. 4.2-8 4.2.3.3.5 Structural Deformation Evaluation .............................................. 4.2-9 4.2.4 TESTING, INSPECTION, AND SURVEILLANCE PLANS .................. 4.2-9 4.2.4.1 Fuel Testing, Inspection, and Surveillance ....................................... 4.2-9 4.2.4.2 Online Fuel System Monitoring .................................................... 4.2-9 4.2.4.3 Post-Irradiation Surveillance ........................................................ 4.2-9 4.2.4.4 Channel Management 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 LDCN-10-029                                       4-iv

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 4.3.1.2 Overpower Bases ...................................................................... 4.3-1 4.

3.2 DESCRIPTION

.......................................................................... 4.3-1 4.3.2.1 Nuclear Design Description ......................................................... 4.3-1 4.3.2.2 Power Distribution .................................................................... 4.3-1 4.3.2.2.1 Power Distribution Calculations.................................................. 4.3-1 4.3.2.2.2 Power Distribution Measurements ............................................... 4.3-1 4.3.2.2.3 Power Distribution Accuracy ..................................................... 4.3-1 4.3.2.2.4 Power Distribution 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 Reactor During Refueling ........................................... 4.3-3 4.3.2.7 Stability ................................................................................. 4.3-3 4.3.2.7.1 Xenon Transients ................................................................... 4.3-3 4.3.2.7.2 Thermal Hydraulic Stability ...................................................... 4.3-3 4.3.2.8 Vessel Irradiations..................................................................... 4.3-3 4.3.3 ANALYTICAL METHODS ........................................................... 4.3-4 4.3.4 CHANGES ................................................................................ 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 Steady-State Conditions ........................................ 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 LDCN-15-011 4-v

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 4.4.2.4 Void Fraction Distribution ........................................................... 4.4-2 4.4.2.5 Core Coolant Flow Distribution and Orificing 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 THERMAL AND HYDRAULIC DESIGN OF THE REACTOR COOLANT SYSTEM ........................................ 4.4-4 4.4.3.1 Plant Configuration 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 System Geometric Data ....................................... 4.4-4 4.4.3.2 Operating Restrictions on Pumps ................................................... 4.4-4 4.4.3.3 Power-Flow Operating Map ......................................................... 4.4-5 4.4.3.3.1 Limits for Normal Operation ..................................................... 4.4-5 4.4.3.3.2 Regions of the Power-Flow Map ................................................. 4.4-5 4.4.3.3.3 Design Features for Power-Flow Control ...................................... 4.4-5 4.4.3.4 Temperature-Power Operating Map ............................................... 4.4-7 4.4.3.5 Load-Following Characteristics ..................................................... 4.4-7 4.4.3.6 Thermal and Hydraulic Characteristics Summary Table ....................... 4.4-7 4.4.4 EVALUATION .......................................................................... 4.4-7 4.4.4.1 Bypass Flow ............................................................................ 4.4-7 4.4.4.2 Thermal Hydraulic Stability Analysis.............................................. 4.4-7 4.4.5 TESTING AND VERIFICATION ................................................... 4.4-8 4.4.6 INSTRUMENTATION 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, Inspections and Tests ................................................... 4.5-3 LDCN-15-011, 10-004                               4-vi

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 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 INTERNAL MATERIALS ............................................. 4.5-5 4.5.2.1 Material Specifications ............................................................... 4.5-5 4.5.2.2 Controls on Welding .................................................................. 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 Drive System Design ................................................. 4.6-1 4.6.1.1.1 Design Bases ......................................................................... 4.6-1 4.6.1.1.1.1 Safety Design Bases.............................................................. 4.6-1 4.6.1.1.1.2 Power Generation Design Basis ............................................... 4.6-1 4.6.1.1.2 Description ........................................................................... 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 Drive Piston..................................................................... 4.6-3 4.6.1.1.2.2.2 Index Tube ...................................................................... 4.6-3 4.6.1.1.2.2.3 Collet Assembly ................................................................ 4.6-3 4.6.1.1.2.2.4 Piston Tube ..................................................................... 4.6-4 4.6.1.1.2.2.5 Stop Piston ...................................................................... 4.6-4 4.6.1.1.2.2.6 Flange and 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 Index Tube ...................................................................... 4.6-6 4.6.1.1.2.3.2 Coupling 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 Drive Hydraulic System ........................................ 4.6-7 4.6.1.1.2.4.1 Hydraulic Requirements ...................................................... 4.6-7 4.6.1.1.2.4.2 System Description ............................................................ 4.6-8 4-vii

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 4.6.1.1.2.4.2.1 Supply Pump ................................................................. 4.6-8 4.6.1.1.2.4.2.2 Accumulator 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 Withdraw 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 Scram Inlet Valve ........................................................... 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 Scram 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 Instrumentation ................................................................... 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 Description ........................................................................... 4.6-15 4.6.2 EVALUATION OF THE CONTROL 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 Dimensional 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 for 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 4-viii

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 4.6.2.2.1 Evaluation 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-Under Line Break .................................................. 4.6-20 4.6.2.2.2.2.2 Pressure-Over 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 Housing 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 Valve Plug Blows Out ............................................ 4.6-24 4.6.2.2.2.8 Drive/Cooling 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 Hydraulic Control Unit Valve 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 Support 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 Development Tests ............................................................... 4.6-28 4.6.3.1.1.2 Factory Quality Control Tests.................................................. 4.6-28 4.6.3.1.1.3 Operational Tests ................................................................. 4.6-29 4.6.3.1.1.4 Acceptance Tests ................................................................. 4.6-30 4.6.3.1.1.5 Surveillance Tests ................................................................ 4.6-30 4.6.3.1.1.6 Functional 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 Common Mode Failures ......................................... 4.6-32 4.6.4.2 Accidents Taking Credit for Multiple Reactivity Systems ..................... 4.6-33 4-ix

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR TABLE OF CONTENTS (Continued) Section Page 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 Rod Insertion Redundancy............................................... 4.6-34 4.

6.7 REFERENCES

........................................................................... 4.6-34 4-x

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 Chapter 4 REACTOR LIST OF TABLES Number Title Page 4.2-1 Control Rod Parameters ........................................................... 4.2-15 4.3-1 Summary of Neutron Fluence Results .......................................... 4.3-7 4.3-2 Deleted 4.3-3 Neutronic Design Values .......................................................... 4.3-9 4.4-1 Thermal and Hydraulic Design Characteristics of the Reactor Core ......................................................................... 4.4-11 4.4-2 Deleted 4.4-3 Reactor Coolant System Geometric Data ...................................... 4.4-13 4.4-4 Lengths and Sizes of Safety Injection Lines ................................... 4.4-14 4.4-5 Deleted LDCN-21-015 4-xi

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR LIST OF FIGURES Number Title 4.1-1 Steam Separator 4.1-2 Steam Dryer Panel 4.1-3 Columbia Generating Station 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 Rod 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 Control 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 Control Rod Drive (Breakdown) 4.6-5 Control Rod Drive Hydraulic System (Sheets 1 and 2) 4.6-6 Control Rod Drive System Process Diagram (Sheets 1 through 3) 4-xii

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Chapter 4 REACTOR LIST OF FIGURES (Continued) Number Title 4.6-7 Control Rod Drive Hydraulic Control Unit 4.6-8 Control Rod Drive Housing Support 4-xiii

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 document (Reference 4.1-4), the cycle-specific design report (Reference 4.1-2) and the Fuel Bundle Information 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 control rod drives. Figure 5.3-5 shows the arrangement of reactor assembly components. A summary of the important design and performance characteristics 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 description 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 (including the shroud, top guide and core plate), the shroud head and steam separator assembly, the steam dryer assembly, the feedwater spargers, the core spray spargers, and the jet pumps. Except for the Zircaloy and NSF (Niobium-Sn-Fe) 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 core spray lines, spargers, and the feedwater sparger. The removal of the steam dryers, shroud head and steam separators, fuel assemblies, in-core assemblies, control rods, orificed fuel supports, and control rod guide tubes can be accomplished on a routine basis. LDCN-21-015 4.1-1

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 based on conservative application of stress limits, operating experience, and experimental test results. The moderate pressure levels characteristics of a direct cycle reactor (approximately 1035 psia) result in moderate cladding temperatures and stress levels;

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

c. The basic thermal and mechanical criteria applied in the design have been proven by irradiation of statistically significant quantities of fuel. The design heat transfer rates and linear heat generation rates are 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 negative moderator density coefficient of reactivity, the BWR has a number of inherent advantages. These are the uses of coolant flow for load following, the inherent self-flattening of the radial power distribution, the ease of control, the spatial xenon stability, and the ability to override xenon to follow load.

LDCN-15-011 4.1-2

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 Boiling water reactors do not usually have instability 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 detect and suppress system to ensure hydrodynamic stability while operating in regions 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 cruciform control rods consist of B4C 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 (three 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 service during refueling. In-core instrumentation is further 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-4 and NSF channels provide a fixed flow path for the boiling coolant, serve as a guiding surface for the control rods, and protect the fuel during handling operations;

g. The mechanical reactivity control permits 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 LDCN-16-005 4.1-3

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021

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 containing 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 mechanical 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 assemblies are GNF2 (Reference 4.1-4). 4.1.2.1.3.1 Fuel Rod. A fuel rod consists of UO2 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 (Reference 4.1-4). 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 volume within the fuel tube to accommodate differential expansion between fuel and clad. Overall fuel rod design is conservative in its accommodation of the mechanisms affecting fuel in a BWR environment. 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.

LDCN-21-015 4.1-4

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 The fuel bundles are designed to meet all the criteria for core performance and to provide ease of handling. Selected fuel rods in each bundle differ from the others in uranium enrichment. This arrangement produces more uniform power production across the fuel bundle and thus allows a significant reduction in the amount of heat transfer surface required to satisfy the design thermal limitations. The GNF reload bundle contains 92 fuel rods and 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 control rod guide tubes. Each guide tube, with its fuel support piece, bears the weight of four assemblies and is supported by a control rod drive penetration nozzle in the bottom head of the reactor vessel. The core plate provides lateral support and guidance at the top of each control rod guide tube. The top guide, mounted inside the shroud, provides 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 refueling, and convenient drive maintenance. 4.1.2.2 Shroud The shroud is a cylindrical, stainless-steel structure which surrounds the core and provides a barrier to separate the upward flow through the core from the 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 steam separators. The upper cylindrical 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 introduce the coolant to the inlet plenum. To prevent direct flow from the inlet to the outlet nozzles 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 for injection of cooling LDCN-15-011 4.1-5

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 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 flange and dome onto which is welded 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 cylinder 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 axial flow type steam separators have no moving parts and are made of stainless steel. In each separator, the steam-water mixture rising from the standpipe 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 separators for easy access during refueling. 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 operations 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 mounted in the reactor vessel above the shroud head and forms the top and sides of the wet steam plenum. Vertical guide rods on the inside of the vessel provide alignment for the dryer assembly 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 steam 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. 4.1-6

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1.3 REACTIVITY CONTROL SYSTEMS 4.1.3.1 Operation The control rods perform dual functions of power distribution shaping 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 significant power flattening. These groups of control elements, used for power flattening, experience 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 reactivity 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 drives 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 stainless steel tubes (19 tubes in each wing of the cruciform) filled with vibration 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 extending 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. Rollers, housed in the handle, 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 approximately at the midspan of D each cruciform wing. The control rods can be positioned at 6-in. steps and have a nominal withdrawal and insertion speed of 3 in./sec. The foregoing description of the control rods applies to the design of the original control rods. There have been two different replacement control rods used, Duralife 215 and Marathon LDCN-02-022 4.1-7

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 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 the original control rod assemblies and are compatible with the existing nuclear steam supply system hardware. The Duralife 215 control rods differ from the previous control rods in that a hafnium absorber plate is used at the top of each cruciform section, hafnium absorber rods 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. I There are 21 absorber rods in each wing, of which 18 are stainless-steel tubes containing boron carbide and three are 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 top 6-in.-high hafnium plate. IThe increased volume of neutron absorber material increases the relative reactivity worth in the cold condition and increases the nuclear lifetime. The Marathon control rod blades are an improved 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 increased absorber volume. 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 absorber tubes each act as an individual pressure chamber for the retention of helium. The region between each pair of square tubes is filled with helium 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 segmented tie rod, which also reduces weight. The square tubes are circular inside and are loaded with either B4C or hafnium. The B4C 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 B4C to swell before making contact with the absorber tubes thereby 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 absorber 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 B4C burnup. The velocity limiter, shown in Figure 4.2-2, is a device which is an integral 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. LDCN-02-022 4.1-8

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 Control rods are cooled by the core leakage (bypass) flow. The core leakage flow is made of recirculation flow that leaks through the several 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 support piece and core plate,

e. The area between core plate and shroud,

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

g. Various leakage paths around the control rod guide tubes, and

h. Control rod drive cooling water.

4.1.3.3 Supplementary Reactivity Control Supplemental reactivity control is achieved with burnable poison. The supplementary burnable poison is gadolinia (Gd2O3) mixed with UO2 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 internal 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 LDCN-08-035 4.1-9

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 The following italicized detailed descriptions of these programs are historical and were provided to support the application for an operating license. 4.1.4.1.1 MASS (Mechanical Analysis 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 Analysis) program originally developed by L. Beitch in the early 1960s. The program is based on the principle of the finite element 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 loads 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 Division is using a past revision of MASS. This revision is identified as revision 0 in the computer production library. The program operates on the Honeywell 6000 computer. 4.1.4.1.1.3 History of Use. Since its development in the early 1960s, the program has been successfully applied to a wide 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 Turbine Division of GE have also applied the program to a wide range 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 the loads, deformations, and stresses of axisymmetric shells of revolution (cylinders, cones, discs, toroids, and rings) for axisymmetric thermal boundary and surface load conditions. Thin shell theory is inherent in the solution of E. Peissners differential equations for each shells influence coefficients. Surface loading capability includes pressure, average temperature, and liner through wall 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 maintained by the GE Jet Engine Division at Evandale, Ohio, is being used on the Honeywell 6000 computer in GE/NED. 4.1-10

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1.4.1.2.3 History 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 accommodate 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. Because 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 program for the stress analysis of axisymmetric or plane two-dimensional geometries. The element representations can be either quadrilateral or triangular. Axisymmetric or plane structural loads can be input at nodal points. Displacements, temperatures, pressure loads, and axial inertia can be accommodated. Effective plastic stress and strain distributions can be calculated using a bilinear stress-strain relationship by means of an iterative 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 History 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 arbitrary time- and temperature-dependent boundary conditions. This program utilizes the finite element method. Included in the analysis are the three basic forms of heat transfer, conduction, radiation, and convection, as well as internal heat generation. In addition, cooling 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. 4.1-11

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1.4.1.4.2 Program Version and Computer. The current version of the program is an improvement of the program originally developed 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 History 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 satisfactorily 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 analyses and minimizes human error. 4.1.4.1.5 FINITE 4.1.4.1.5.1 Program Description. FINITE is a general-purpose 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 developer 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 History of Use. Since its completion in 1969, the program has been widely used in the Gas Turbine and the Jet Engine Departments 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-axisymmetric BWR internals. 4.1.4.1.6 DYSEA 4.1.4.1.6.1 Program Description. The DYSEA (Dynamic and Seismic Analysis) program is a GE proprietary program developed specifically for seismic and dynamic analysis of RPV and internals/building system. It calculates the dynamic response of linear structural system by either temporal modal superposition or response spectrum method. Fluid-structure interaction effect in the RPV is taken into account by way of hydrodynamic mass. 4.1-12

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Program DYSEA was based on program SAPIV 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 Newmarks -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 was added to handle the hydrodynamic mass effect due to fluid-structure interaction 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 developed in the Summer of 1976. It has been adopted as a standard 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 DYSEA has been used in all dynamic and seismic analysis since its development. Results from test problems were found to be in close agreement with those 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 elastic material properties, boundary constraints, and mechanical thermal and displacement loading conditions. The basic element is a triangle whose membrane displacement 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 displacements and stresses are in a local (tangent) surface coordinate system. Due to the approximation of element membrane displacements 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 discontinuous surface) problems where in-plane rotation can be significant. 4.1.4.1.7.2 Program Version and Computer. A copy of the source 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. 4.1-13

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 4.1.4.1.7.3 History of Use. SHELL 5 is a program developed by Gulf General Atomic Incorporated (Reference 4.1-14) in 1969. The program has been 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. Satisfactory results were obtained. 4.1.4.1.8 HEATER 4.1.4.1.8.1 Program Description. HEATER is a computer program used in the hydraulic design of feedwater spargers and their associated delivery header and piping. The program utilizes test data obtained by GE using full scale mockups of feedwater spargers combined with a series of models which represents the complex mixing processes obtained in the upper plenum, downcomer, and lower plenum. Mass and energy balances throughout the nuclear steam supply system are modeled 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 History of Use. The program was developed by various individuals in GE/NED beginning in 1970. The present version of the program has 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 BWR plant, in the evaluation of design modifications, and the evaluation of unusual operational conditions. 4.1.4.1.9 FAP-71 (Fatigue 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 Nuclear Vessel Code structural design calculations. Specifically, FAP-71 is used in determining the primary plus secondary stress range and number of allowable fatigue cycles at points of interest. For structural locations at which the 3Sm (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 states 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. 4.1-14

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 conjunction 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 program 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 hereditary integrals. The material creep properties are built into the program and they represent annealed 304 stainless steel. Any other creep 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 Program 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 testing 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 were performed to verify that design criteria are met (see References 4.1-1 and 4.1-4). 4.1.4.3 Reactor Systems Dynamics The analysis techniques used in reactor systems dynamics are described in Sections 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. LDCN-21-015 4.1-15

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 Fluence Calculations See Section 4.3.2.8. 4.1.4.6 Thermal Hydraulic Calculations The digital computer program uses a parallel flow path model to perform the steady-state BWR reactor core thermal-hydraulic analysis. 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 flow 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 Standard Application for Reactor Fuel, NEDE-24011-P-A, and Supplement for United States, NEDE-24011-P-A-US (most recent approved version referenced in COLR). 4.1-2 Supplemental Reload Licensing Report for Columbia (most 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 version referenced in COLR). 4.1-5 Deleted. 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. LDCN-21-015 4.1-16

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 Digital Computer Program For the Finite Element Analysis of Solids With Non-Linear Material Properties, Aerojet General Technical, Memo No. 23, Aerojet General, July 1965. 4.1-11 I. Farhoomand and E. L. Wilson, Non-Linear Heat Transfer Analysis of Axisymmetric Solids, SESM Report SESM71-6, University of California at Berkeley, Berkeley, California, 1971. 4.1-12 J. E. McConnelee, Finite-Users Manual, General 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-Plast Computer Program, GEAP-10546, AEC Research and Development Report, January 1972. LDCN-15-011 4.1-17

Amendment 53 November 1998 Wet Steam Returning Water Water Level Returning Water Steam Water Mixture Turning Vanes (Inlet Nozzle) Standpipe Core Discharge Plenum Steam Separator Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.95 Rev. Figure 4.1-1 Form No. 960690

Amendment 53 November 1998 Steam Flow 0 Jo Co Oo Oo Oo Oo Oo Oo Oo Steam Flow Steam Dryer Panel Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.98 Rev. Figure 4.1-2 Form No. 960690

Amendment 61 December 2011 DELETED Columbia Generating Station Final Safety Analysis Report Draw. No. 910402.33 I Rev. I Figure 4.1-3 Form No. 960690 LDCN-10-029

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 4.2 FUEL SYSTEM DESIGN See Appendix A, Section A.4.2 of Reference 4.2-1. 4.2.1 DESIGN BASES General Electric BWR fuel assembly and channel design bases, analytical methods, and evaluation results are described 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 subsection 2.2.1.4.1.2 of Reference 4.2-1. 4.2.1.1.5 Dimensional 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 LDCN-15-011 4.2-1

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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-Cladding 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 and 2.2.3.4 of Reference 4.2-1. LDCN-15-011 4.2-2

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 Expulsion 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

AND DESIGN DRAWINGS See Reference 4.2-2. 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 counterbalance 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 (B4C) 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. LDCN-21-015 4.2-3

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 The main structural member of a control rod is made of type 304 stainless steel and consists of a top handle, an original bottom casting with a velocity limiter and control 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 castings to form a rigid housing to contain the boron-carbide-filled absorber rods. Rollers at the top and bottom of the control rod guide the control rod as it is inserted and withdrawn from the core. The control rods are cooled by the core bypass flow. The U-shaped sheaths are perforated to allow the coolant to circulate freely about the absorber tubes. Operating experience has shown that control rods constructed as described above are not susceptible to dimensional distortions. The boron-carbide (B4C) powder in the absorber tubes is compacted to about 70% of its theoretical density. The boron-carbide 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 into 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 sinter in service, the steel balls will keep the resulting void spaces distributed over the length 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 control rod design is made of stainless steel and consists of a top handle, a tie rod, a bottom control rod drive 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 tubes 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 blades are attached to the structure with full fusion corner welds to the handle, tie rod, and velocity limiter to form a rigid housing. Inconel X750 rollers at the top and bottom of the control rod guide the control rod as it is inserted and withdrawn from the core. These rollers rotate on PH 13-8 Mo pins. The sheaths are perforated and the hafnium absorber plate has coolant 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. 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 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. 4.2-4

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 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 wings 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 B4C or hafnium. The combination of absorbers and absorber 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 B4C 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 insertion 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 during 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 surface 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 element 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 slows the descent of the control rod assembly to less than 5 ft/sec. 4.2-5

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 4.2.3 DESIGN EVALUATION See Appendix A, subsection 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 achieved burnup. For GNF fuel see section 2.2.1.1.3 of Reference 4.2-1. 4.2.3.1.2 Fatigue 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 Dimensional Change Evaluation See Reference 4.2-6, subsection 2.2.1.5.3 of Reference 4.2-1. 4.2.3.1.6 Internal Gas Pressure Evaluation See Section 3.2.6 of reference 4.2-2. The internal pressure is used in conjunction 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. LDCN-21-015 4.2-6

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 I See Appendix A, subsection A.4.3.2 of Reference 4.2-1. Energy Northwest calculates the fluence of each control blade using an appropriate conversion 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 control blade worth due to a combination of boron-10 depletion and boron loss resulting from cracking 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 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 3.6 of Reference 4.2-2. 4.2.3.2.5 Overheating of Pellet Limits See Section 3.2.9 of Reference 4.2-2. 4.2.3.2.6 Excessive Fuel Enthalpy Evaluation See Section 15.4.9 Section 3.12 of Reference 4.2-2. LDCN-21-015 4.2-7

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 4.2.3.2.7 Pellet-Cladding Interaction Evaluation Calculated results do not exceed the 1% cladding strain or MCPR99.9%; thus fuel pellet melting does not occur. These are the most applicable general design criteria for pellet cladding interaction (PCI) phenomena. While PCI-induced fuel failures remain a commercially undesirable problem, 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 maneuvering guidelines have been developed that have further reduced fuel failures due to the PCI mechanism. 4.2.3.2.8 Bursting Evaluation See 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 FSAR Section 4.2.3.2.8 and subsection 2.2.3.1 of Reference 4.2-1. 4.2.3.3.2 Violent Expulsion of Fuel Evaluation See FSAR Section 15.4.9 and Section 3.12 of Reference 4.2-2. 4.2.3.3.3 Generalized Cladding Melt Evaluation See FSAR Section 4.2.3.2.8 and Section 3.11.2 of Reference 4.2-2. 4.2.3.3.4 Fuel Rod Ballooning Evaluation See FSAR Section 4.2.3.2.8 and Section 3.11.1 of Reference 4.2-2. LDCN-21-015 4.2-8

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 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, Inspection, and Surveillance See Appendix A, subsection 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 fission product releases from failed fuel 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 releases 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 after the gases leave the 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, developed to provide verification of the reliable performance of the CGS fuel design, will consist of the following inspections and measurements:

a. Visual inspection of the peripheral rods will be performed on discharged fuel, that has given indication of gross cladding defects or anomalies during plant operation, after each refueling outage. The examination will be capable of detecting and characterizing generic gross cladding defects or anomalies; and

b. If anomalous behavior of the fuel cladding, 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.

4.2-9

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 Implementation

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

b. Fuel performance history and related plant operational 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 during plant operation will be selected for visual inspection. The visual examination of the peripheral rods will include observations for cladding defects, fretting, rod bowing, missing components, corrosion, crud deposition, and geometric distortions. The defects or anomalies on the cladding surface area examined will be either videotaped 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 observed, the fuel with the defects and the applicable operational data will be investigated and further appropriate 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 inspection activities. Under normal conditions, the report will contain visual examination summaries confirming the reliable performance of the fuel assemblies. In the event that significant anomalies or unusual defects are observed, the report will contain the description and related data of onsite receiving inspection and operational conditions. Evaluation and studies to identify causes for any encountered anomalies or defects will be assessed and the results will be reported to the NRC as they become available.

4.2.4.4 Channel Management Program Fuel channels are subject to bulge, bow, and elongation when irradiated in reactors. Excessive deformations (bow and bulge) could produce traversing in-core probe asymmetries and control blade frictional resistance. LDCN-08-038 4.2-10

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 All new reload fuel will be loaded 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 Related 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 longer reuses channels, the qualification of channel reuse has been discontinued. In addition to the above channel 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 testing 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 Company, General Electric Standard Application for Reactor Fuel (NEDE-24011-P-A), and Supplement for United States (NEDE-24011-P-A-US) (most recent approved version referenced in COLR). 4.2-2 GNF2 Advantage Generic compliance with NEDE-24011-P-A (GESTAR II), NEDC-33270P, (most recent version referenced in COLR). 4.2-3 Deleted. 4.2-4 Deleted. 4.2-5 Deleted. 4.2-6 General Electric Company, BWR Fuel Channel Mechanical Design and Deflection, NEDE-21354-P, September 1976. 4.2-7 General Electric Company, Control Blade Lifetime with Potential B4C Loss, NEDO-24226 and Supplement 1. LDCN-21-015 4.2-11

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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, Manager, 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, Manager, Regulatory Programs, 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, Supply 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, Safety Evaluation Report 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. LDCN-15-011 4.2-12

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 Company, Fuel Assembly Evaluation of Combined Safe Shutdown Earthquake (SSE) and Loss-of-Coolant Accident (LOCA) Loadings, NEDE-21175-3-P, July 1982. 4.2-26 Deleted. LDCN-15-011 4.2-13

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 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-carbide 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, grams/cm3 1.76 (Nominal) 1.76 (Nominal) 1.76 (70% Theoretical) Absorber tube Cladding material 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, grams/cm3 13.1 13.0 Absorber plate - hafnium Number per control rod - 4 - Length, in. (mm) - 6 (152) - Width, in. (mm) - 3.42 (86.87) - Thickness, in. (mm) - 0.188 (4.78) - Density, grams/cm3 - 13.1 - Sheath thickness, 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 LDCN-02-022 4.2-15

Amendment 57 December 2003

                                                             ~      HANDLE 9.88 in.

UPPER GUIDE ROLLER 6.5" TYPICAL 4 PLACES 0 () WELDED END PLUG 0 0 () 0 0 0 0 0 0 NEUTRON ABSORBER 0 RODS T SHEATH T 1/2 in. (TYPICAL) 143 in. ACTIVE POISON LENGTH 0 () 0 16 in. BETWEEN BLADE () BALLS (TYPICAL) 0 () _j 0 () 0 () 0 () COUPLING RELEASE HANDLE VELOCITY LIMITER ABSORBER ROD LOWER GUIDE ROLLER COUPLING TYPICAL 4 PLACES SOCKET Original Equipment (OEM) Control Rod Blade Columbia Generating Station Assembly Final Safety Analysis Report Draw. No. 960690.96 Rev. Figure 4.2-1.1 Form No. 960690 LDCN-02-022

Amendment 57 I December 2003 Zone 2 Solid Hafnium Rods Solid Hafnium Plate Zone 2 Zone 1 0 <;:) 0 <;:) 0 <;:) 0 <;:) 0 <;:) 0 <;:) Solid Hafnium Rods Standard B4C Absorber with Improved Tubing Material Zone 1 DuraLife 215 Control Rod Blade Assembly Columbia Generating Station Final Safety Analysis Report Draw. No. 010126.54 Rev. Figure 4.2-1.2 Form No. 960690 LDCN-02-022

Amendment 57 December 2003 HANDLE BLADE NEUTRON ABSORBER RODS COUPLING RELEASE HANDLE VELOCITY LIMITER COUPLING SOCKET Marathon Control Rod Blade Assembly Columbia Generating Station Final Safety Analysis Report Draw. No. 010126.55 Rev. Figure 4.2-1.3 Form No. 960690 LDCN-02-022

Amendment 57 December 2003 LOBE SQUARE TYPE ABSORBER TUBE GAP BORON CARBIDE ABSORBER CAPSULE POWDER B4C Placement in Capsules and Absorber Tubes Absorber Tubes (Before Welding) Absorber Tubes Welded to Tie Rods Marathon Control Rod Blade Absorber Details Columbia Generating Station Final Safety Analysis Report Draw. No. 010126.56 Rev. Figure 4.2-1.4 Form No. 960690 LDCN-02-022

Amendment 57 December 2003 TYPE 1 TYPE 2 TYPE 3 TOP TYPE ABSORBER LOADING 1 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 HAFNIUM B4C ABSORBER CAPSULE EMPTY CAPSULE BOTTOM ABSORBER MATERIAL CONTAINED IN TUBES TYPE 1 t *.****.**.* .***. TYPE 1

           @        ~=~~~=~~**                    .
                                                    * ,*~**. * ~** ~- ~  ~~~-~~-~~~~~                       *
                                                                                                              ~-....

TYPE 2 TYPE 3 CONTROL ROD CROSS PARTIAL SECTION Marathon Control Rod Blade Absorber Placement Columbia Generating Station Final Safety Analysis Report Draw. No. 010126.57 Rev. Figure 4.2-1.5 Form No. 960690 LDCN-02-022

Amendment 57 December 2003 Rollers 22-1/16 In. Fuel Support Casting To Active Fuel Zone Core Support Plate Orifice Control Rod

                                                                                  ~t 148-7/16 In.

144 In. Stroke Velocity Limiter Coupling Guide Tube Control Rod Drive Housing 10.420 In. Stub Tube Reactor Vessel Control Rod Velocity Limiter Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.97 Rev. Figure 4.2-2 Form No. 960690 LDCN-02-022

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 4.3 NUCLEAR DESIGN 4.3.1 DESIGN BASES See Appendix A, subsection 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, subsection 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 the Supplemental Reload Licensing Report (Reference 4.3-7). Table 4.3-3, Table 2-1 of Reference 4.3-1 and Reference 4.3-8 provide reload fuel neutronic design values. 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 Distribution Calculations See References 4.3-7 and 4.3-3. 4.3.2.2.2 Power Distribution 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 Distribution Anomalies See Appendix A, subsection A.4.3.2.2.4 of Reference 4.3-4. LDCN-21-015 4.3-1

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 reference 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 determined 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 design 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 designed into the core is controlled by the control rod system supplemented by gadolinia-urania 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 behavior because of the strong interdependence of the individual constituents of reactivity. Therefore, the design process does not produce components of a reactivity 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 unless the sequence of the changes is clearly defined. 4.3.2.5 Control Rod Patterns and Reactivity Worths See References 4.3-1 and 4.3-3. LDCN-21-015 4.3-2

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 4.3.2.6 Criticality of Reactor During Refueling See Appendix A, subsection A.4.3.2.6 of Reference 4.3-4. Compliance with Technical Specification shutdown margin requirements is demonstrated through plant procedures and reactivity analyses 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 methodology 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 the Safety Evaluation Report (SER) for referencing in licensing actions. The fluence calculations are performed with the DORTG01V discrete ordinates transport code. The LTR provides a description of the DORT calculation 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 representation of the peripheral fuel assemblies and the core-internals, downcomer and vessel geometry. Calculations are performed to determine the bundle-average power distribution in the peripheral fuel bundles for input to the DORT core neutron source. Calculations employ a relatively fine (r, , z) spatial mesh and are carried out using an S12 angular quadrature set. The eighty-group MATXS cross section library is the basic nuclear data set. The cross section data used in these calculations is based on the ENDF/B-V nuclear data except for iron, hydrogen and oxygen. Since the cross 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 individual iron isotopes. The cross section library is used in performing the energy and spatial self-shielding and removal LDCN-15-011 4.3-3

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 calculations. The scattering cross sections are represented using a P3 Legendre expansion. The calculations are performed in azimuthal (r, ) and axial (r, z) geometries. A synthesis technique is used to determine the three-dimensional fluence distribution. Figure 4.3-1 shows a quadrant of the core and the vessel internal components 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 (typically 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 cladding 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 calculation, the (r,z) calculation was performed at the 300° azimuth, where the capsule was located. For the shroud/RPV flux calculation, the azimuth of 24° was selected because it is near the peak shroud flux and peak RPV flux. The core cylinder contains the afore-mentioned three radial zones for each of the 25 axial fuel nodes. Each axial fuel node is sub-divided into bundle-dependent radial regions so that each core region is modeled with its respective water density, structure material density, and actinide concentration. Similar to the (r, ) model, there are bypass water, shroud, downcomer water, and 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 the end of 40 years (33.1 EFPY), and at the end of 60 years (51.6 EFPY). Note EFPY is defined as 3323 MWt 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 Cycle 17 include a 10% adder to bound potential variation in future cycles. Note: Columbia Generating Station is evaluated for a fluence that bounds the required value for operation at 3544 MWt from cycle 24 through the end of life (Reference 4.3-14). 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/cm2) used for P-T curve development are: 1.75E+17 for lower shell #1, 5.11E+17 for lower-intermediate shell #2, 2.81E+17 for N6 nozzle and 2.13E+17 for girth weld between 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, subsection A.4.3.3 of Reference 4.3-4. LDCN-18-012 4.3-4

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 4.3.4 CHANGES See Appendix A, subsection A.4.3.4 of Reference 4.3-4. 4.

3.5 REFERENCES

4.3-1 GNF2 Advantage Generic compliance with NEDE-24011-P-A (GESTAR II), NEDC-33270P, (most recent version referenced in COLR). 4.3-2 Deleted. 4.3-3 Nuclear Design Report (most recent version referenced in COLR). 4.3-4 General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A, and Supplement for United States, NEDE-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 Generating Station Neutron Flux Evaluation, GE-NE-0000-0023-5057-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 Report for Columbia (most recent version referenced in COLR). 4.3-8 Fuel Bundle Information Report for Columbia (most recent version referenced in COLR). 4.3-9 Deleted. 4.3-10 GE Nuclear Energy, Licensing Topical Report, General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations, NEDC-32983-P-A, Revision 2, January 2006. 4.3-11 Deleted. LDCN-21-015, 21-036 4.3-5

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 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. 4.3-14 GE-Hitachi Nuclear Energy, Safety Analysis Report for Columbia Generating Station Thermal Power Optimization, NEDC-33853P, March 2016. LDCN-16-005 4.3-6

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 Table 4.3-1 Summary of Neutron Fluence Results Flux (n/cm2-s) Fluence (n/cm2) Representative 40-year 60-year Cycle 10 Future Cycle (33.1 EFPY)* (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 17 Elevation for 10 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 based 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).

Note: Columbia Generating Station is evaluated for a fluence that bounds the required value for operation at 3544 MWt from cycle 24 through the end of life (Reference 4.3-14). LDCN-16-005 4.3-7

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 Table 4.3-2 DELETED LDCN-21-015 4.3-8

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 Table 4.3-3 Neutronic Design Values Parameter Value Core data Number of fuel assemblies 764 Rated power, MWt 3544 Rated core flow, Mlbm/hr 108.5 Core inlet enthalpy, Btu/lbm 528.5 Reactor dome pressure, psia 1035 Fuel assembly pitch, in. 6.00 Control rod dataa Absorber material B4C 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. LDCN-16-005 4.3-9

Amendment 58 December 2005 0° RPV 30° Shroud Capsule 45° J/P Riser J 1 3 3 3 3 3 3 3 2 2 2 2 2 3 3 3 3 60° 3 2 2 2 2 2 2 3 3 3 3 4 1 1 1 2 2 2 2 2 3 3 J/P Mixer 5 1 1 1 1 1 1 2 2 2 3 3 6 1 1 1 1 1 1 1 2 2 2 3 3 3 7 1 1 1 1 1 1 1 1 2 2 2 3 3 8 1 1 1 1 1 1 1 1 1 2 2 2 3 3 9 1 1 1 1 1 1 1 1 1 1 2 2 3 3 3 10 1 1 1 1 1 1 1 1 1 1 1 2 2 3 3 11 1 1 1 1 1 1 1 1 1 1 1 2 2 3 3 0 12 1 1 1 1 1 1 1 1 1 1 1 2 2 2 3 13 1 1 1 1 1 1 1 1 1 1 1 1 2 2 3 14 1 1 1 1 1 1 1 1 1 1 1 1 2 2 3 15 1 1 1 1 1 1 1 1 1 1 1 1 2 2 3 90° 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 I Core Layout and Vessel Internal Columbia Generating Station Components Final Safety Analysis Report Draw. No. 960690.10 Rev. Figure 4.3-1 Form No. 960690FH LDCN-04-005

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 heat generation rate (MLHGR) must 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 the thermal limits given previously. The core and fuel design basis for steady-state operation (i.e., MCPR and LHGR limits) have 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 condition 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, subsection A.4.4.2 of Reference 4.4-1. 4.4.2.1 Summary Comparison An evaluation of plant performance 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. Any changes for reload cores will be indicated in the Supplemental Reload Licensing Report (Reference 4.4-4). LDCN-21-015 4.4-1

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 4.4.2.2 Critical Power Ratio See Appendix A, subsection A.4.4.2.2 of Reference 4.4-1 and Reference 4.4-2. 4.4.2.3 Linear Heat Generation Rate See Appendix A, subsection A.4.4.2.3 of Reference 4.4-1 and Reference 4.4-2. 4.4.2.4 Void Fraction Distribution See Appendix A, subsection A.4.4.2.4 of Reference 4.4-1 and Reference 4.4-3. 4.4.2.5 Core Coolant Flow Distribution 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, hence, 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 orifice flow zones. The outer zone is a narrow, reduced-power region around the core periphery. The inner zone is the core central region. No other flow or steam distribution, other than that provided by adjusting 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 the design power distributions. The flow distribution to the fuel assemblies was calculated based on the assumption that the pressure drop across all of the fuel assemblies is the same. This assumption 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 Channel 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 MCPR99.9%. LDCN-21-015 4.4-2

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 The channel flow uncertainty is not an independent parameter contributing to the MCPR uncertainty. Its effect has been included in evaluating the probability 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 and Reference 4.4-2. 4.4.2.7 Correlation and Physical Data See Appendix A, subsection A.4.4.2.7 of Reference 4.4-1 and Reference 4.4-2. 4.4.2.8 Thermal Effects of Operational Transients See Appendix A, subsection A.4.4.2.8 of Reference 4.4-1 and Reference 4.4-2. 4.4.2.9 Uncertainties in Estimates See Appendix A, subsection A.4.4.2.9 of Reference 4.4-1 and Reference 4.4-2. LDCN-21-015 4.4-3

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 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 THERMAL AND HYDRAULIC DESIGN OF THE REACTOR COOLANT SYSTEM 4.4.3.1 Plant Configuration Data 4.4.3.1.1 Reactor Coolant 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 System 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 length, 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. LDCN-03-003 4.4-4

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 4.4.3.3 Power-Flow Operating Map 4.4.3.3.1 Limits for Normal Operation The power-flow operating map for the power 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 Limit Analysis (MELLLA) Boundary: The line passes through 100% power at 82.7% 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 system startup operational 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 use 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 maintain power-flow conditions to the required values shown in Figure 4.4-1: LDCN-21-015 4.4-5

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015

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 action is initiated electronically through a time delay.

b. Minimum power limit at low core flow. During low power, low loop flow operations, the temperature differential interlock provides cavitation protection.

Activation of the temperature differential interlock will run back the pump speed to 15 Hz. The ASD output speed/frequency is measured by instrumentation provided for monitoring the ASD. The speed change action is electronically initiated.

c. Pump bearing limit. For pumps as large as the recirculation pumps, practical limits of pump bearing design require that minimum pump flow be limited to D25% of rated. To ensure this minimum flow, the system is designed so that the minimum pump speed will allow this rate of flow.

d. Valve position. To prevent structural or cavitation damage to the recirculation pump due to pump suction flow starvation, the system is provided with an interlock to prevent starting the pumps or to trip the pumps if the suction or D

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 established for two-pump operation, but will not protect the jet pumps and recirculation pumps on one-pump operation. Therefore, additional procedural operational limits are established to prevent cavitation damage during the 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 LDCN-10-004 4.4-6

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 system output frequency and by withdrawing control rods. Recirculation pump speed increases resulting from ASD system output frequency increases toward 63 Hz with constant control rod position will result in power/flow changes along, or nearly parallel to, the 100% rod line. 4.4.3.4 Temperature-Power Operating Map Not applicable. 4.4.3.5 Load-Following Characteristics The automatic load following feature 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 characteristics 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 and Reference 4.4-2. 4.4.4.1 Bypass Flow Reference 4.4-3 shows the bypass flows for the 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 described in Reference 4.4-1. The analysis supporting the OPRM System Period Based Detection 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 stability protection analysis are presented in Reference 4.4-1. LDCN-21-015 4.4-7

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 4.4.5 TESTING AND VERIFICATION See Appendix A, subsection A.4.4.5 of Reference 4.4-1. 4.4.6 INSTRUMENTATION REQUIREMENTS See Appendix A, subsection 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 Company, General Electric Standard Application for Reactor Fuel, NEDE-24011-P-A, and Supplement for United States, NEDE-24011-P-A-US (most recent approved version referenced in COLR). 4.4-2 GNF2 Advantage Generic Compliance with NEDE-24011-P-A (GESTAR II), NEDC-33270P, (most recent version referenced in COLR). 4.4-3 Global Nuclear Fuel, GNF2 Thermal Hydraulic Compatibility with Columbia Generating Station Legacy Fuel, 002N3118, Revision 0, December 2014. 4.4-4 Supplemental Reload Licensing Report for Columbia (most recent version referenced in COLR). LDCN-21-015 4.4-8

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 4.4-9 GEXL97 Correlation Applicable to ATRIUM-10 Fuel, 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). LDCN-10-029 4.4-9

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 Table 4.4-1 Thermal and Hydraulic Design Characteristics of the Reactor Core General Operating Conditions Parameter Reference design thermal output, MWt 3544 Power level for engineered safety features, MWt 37021 Steam flow rate, at 422.1F final feedwater temperature, millions lb/hr 15.28 Core coolant flow rate range, millions lb/hr 89.7-115 Feedwater flow rate, millions lb/hr 15.25 System pressure, nominal in steam dome, psia 1035 Core exit pressure, nominal, psia 1050 Coolant saturation temperature at core design pressure, F 551 Average power density, kW/liter 52.40 Average linear heat generation rate, kW/ft 4.18 Core total heat transfer area, ft2 86,499 Core total heat transfer area, ft2 134,750 Design operating minimum critical power ratio (MCPR) (see COLR)2 Core inlet enthalpy at 422.1F FFWT, Btu/lb 528.5 Core inlet temperature, at 422.1F FFWT, F 533.6 Core total heat transfer area, ft2 72.4 Core total heat transfer area, ft2 121.53 Core pressure drop, psid 22.9393 1 Per data on page 18 of NEDC-32141P, Power Uprate with Extended Load Line Limit Safety Analysis for WNP-2, June 1993. 2 Core Operating Limits Report 3 Based on full core of GNF2, (1035 psia dome pressure, 3544 MWt power and 108.5 Mlbm/hr (100% of rated core flow)). LDCN-21-015 4.4-11

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 Table 4.4-2 Deleted LDCN-21-015 4.4-12

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Table 4.4-3 Reactor Coolant System Geometric Data Flow Path Height and Elevation of Minimum Length Liquid Bottom of Flow Areas (in.) Level (in.) Each Volumea (ft2) Lower plenum 216 216 -172.5 71.5 216 Core 164 164 44.0 142.0 164 Upper plenum and 178 178 208.0 49.5 separators 178 Dome (above normal 312 312 386.0 343.5 water level) 0 Downcomer area 321 321 -51.0 79.5 321 Recirculation loops and 108.5 ft 403 -394.5 132.5 in2 jet pumps (one loop) 403 a Reference point is recirculation nozzle outlet centerline. 4.4-13

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Table 4.4-4 Lengths and Sizes of Safety Injection Lines Line O.D. Line Length (in.) (ft) HPCS line Pump discharge to valvea 16 319 From HPCS-V-4 inside containment to RPV 12.75 108 Total 427 LPCI lines Loop A

1. Pump discharge 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 discharge to reducer 18 394

2. Reducer to injection valve RHR-V-42B 14 6

3. Inside containment to RPV 14 93 Total 493 Loop C

1. Pump discharge to reducer 18 71

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

3. Inside containment to RPV 14 99 Total 308 LPCS line Pump discharge to valvea 16 222 Inside containment to RPV 12.75 117 Total 339 a

Injection valve located as near as possible to outside of containment wall. 4.4-14

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 Table 4.4-5 Deleted LDCN-21-015 4.4-15

Amendment 64 December 2017 Core Flow (Mihm/hr) 0 10 20 30 40 50 60 70 80 90 100 11 0 120 130 120 ICF Increased Core Flow Region 100% Power 3544. 0 MWt 4000 A Natural Circulation 100% core Flow 108.5 Mlbm/hr 11 0 B Minimum Pump Speed C 56.6 % Power I 32 . 3 % Flow D 100 . 0 % Power/ 82 .7 % Flow D E F 100 D' E 98 . 4 % Power/ 80 . 7 % Flow 100 . 0% Power / 100.0 % Flow MELLLA Boundary 1i~:8~ i 3500 D' E' F' E' 98 . 4 % Power I 100 . 0 % Flow 90 F 100 . 0 % Power I 106 . 0 % Flow ~ F' 98 . 4 % Power I 106 . 0 % Flow 3000 G 64 . 0 % Power I 106 . 0 % Flow !CF 80 H 59 . 3 % Power I 100.0 % Flow

  'c                     14 . 4 % Power I   30 .4 % Flow
  ..:l                                                                                                                                                  C' 0::    70 J         32 . 5 % Power I   65 .4 % Flow                                                                                           2500 ;$

0 l... ....

SC 60 C REGION m H G :SC 0

2000 c.. 0 c.. -; E 50 E ~ V

                                           ...:z:

Jet Pump Cavitation Interlock g5 1500 40 0 A ts B 30 [a;l 0:: J 1000 REGION II 20 500 10 / I

                                            //

0 0 0 10 20 30 40 50 60 70 80 90 100 11 0 120 Core F low(% of Rated) Power-Flow Operating Map Columbia Generating Station Two Loop Operation Final Safety Analysis Report Draw. No. 960690.03 Rev. 2 Figure 4.4-1 Form No. 960690 LDCN-16-005

Amendment 64 December 2017 90 100% Power = 3544 . 0 MWt A B

Natural Circulation

Minimum Pump Speed I 100% Core Flow = 108 . 5 Mlbm/ hr C  : 76 . 0 % Power I 57. 0 % Flow 80 D  : 63 . 1 % Power I 57.0 % Flow E  : 17 . 8 % Power I 41. 0 % Flow C 70

                                                                                                         -~~
                                                                                        ~

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                                                                                ~
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                                                                                        -i I

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                                                                   ~
                                                      -~

B A

                                                         ~                              , Rod Line I ~ "'

I Procedural Op ~ration Limit (For Cavitatio ti Protection) I 30

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J-l----T 20 4 E 10

                                                  ~                  Jet Pump Cavitatio 1 Interlock 0

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               -------====     10               20                30                  40                 so                 60               70 Core F low(% of Rated)

Power-Flow Operating Map Columbia Generating Station Single Loop Operation Final Safety Analysis Report Draw. No. 060108.05 Rev. 2 Figure 4.4-2 Form No. 960690 LDCN-16-005

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 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 control 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 grade 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 LDCN-00-086 4.5-1

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 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 assembly), and their properties LDCN-00-086 4.5-2

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 are readily available. The outer tube is approximately 1/8 hard and has a tensile strength of 90,000/125,000 psi, yield strength of 50,000/85,000 psi, and minimum elongation of 25%. The coupling spud, collet fingers, and collet spring are fabricated from Inconel X-750 in the annealed or equalized condition and heat treated 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 properties 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 (precipitation 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. The 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 system 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 Intergranular Attack in Stainless Steels. Two special processes are employed which subject selected components to temperatures in the sensitization range. These processes are performed on austenitic stainless steel, including XM-19.

a. The cylinder (cylinder, tube, and flange 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)

LDCN-00-086 4.5-3

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Colmonoy hard-surfaced components have performed successfully in the past in drive mechanisms. Nitrided components have accumulated many years of BWR service. It is normal practice to remove some CRDs periodically during refueling outages. At this time, both the Colmonoy hard-surfaced parts and nitrided surfaces are accessible for visual examination. In addition, dye penetrant examinations 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 Delta 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, grinding, and tapping coolants 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 decrease of accessibility for cleaning, and

c. Release of parts for shipment.

The specification for packaging and shipping 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 barrier with desiccant. Packaging is designed to protect the drive and prevent damage to the 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 these procedures meets the requirements of Regulatory Guide 1.37. 4.5-4

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 Site or warehouse storage specifications require inside heated storage comparable to level B of ANSI 45.2.2. 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 aligners), core plate wedges, and internal structures welded to these components, ASME SA240, SA182, SA479, SA312, SA249, or SA213 (all type 304, except the shroud which is 304L, and the core plate wedges which are type 316),

c. Peripheral fuel supports - SA312 type 304,

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

e. Control rod drive housing. ASME SA312 type 304, SA182 type 304,

f. Control rod drive guide tube. ASME 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: LDCN-19-028, 21-024 4.5-5

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 The components in the jet pump assemblies are a riser, 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 type 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 casting 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, made to Specification ASTM B166;

c. The inlet-mixer contains a pin, inserts 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; LDCN-06-000 4.5-6

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

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 materials and designed using ASME Code Section III, Appendix I allowable stresses, and ASME Code Section III, Class I, reactor vessel design rules as guides. The other reactor internals are fabricated from ASTM specification materials. Material requirements in the ASTM specifications 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 Subsection NB, and the material specified is ASME SA-312 supplemented by GE specifications which invoke Subsection NB requirements. This material meets the requirements 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 the extent specified therein. In addition, the specification for tubular products employed for CRD housings external to the reactor pressure vessel (RPV) meet requirements 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 ASTM material specifications. These specifications require a hydrostatic test on each length of tubing. LDCN-06-000 4.5-7

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 4.5.2.4 Fabrication and Processing of Austenitic Stainless Steel - Regulatory Guide Conformance Regulatory Guide 1.31, Control of Stainless Steel Welding All austenitic stainless steel weld filler materials 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 General Electric Company, with the concurrence of the Regulatory Staff, has demonstrated that controlling weld filler metal ferrite at 5% minimum produces production welds which meet the requirements of Regulatory Guide 1.31. A total of approximately 400 production welds in five BWR plants were measured and all welds met the requirements of the Interim Regulatory Position to Regulatory Guide 1.31. Regulatory Guide 1.34, Control of Electroslag Weld Properties. Electroslag welding is not employed for any reactor internals. Regulatory Guide 1.36, Nonmetallic Thermal Insulation for Austenitic Stainless Steel. Nonmetallic thermal insulation is not employed for any components in the reactor vessel. For external applications, all nonmetallic insulation meets the requirements of Regulatory Guide 1.36. Regulatory Guide 1.44, Control of the Use of Sensitized Stainless Steel. All wrought austenitic stainless steel was solution heat treated. Heating above 800°F was prohibited (except for welding) unless the stainless 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 Section IX. These controls were employed to avoid severe sensitization and comply with the intent of Regulatory Guide 1.44. Regulatory Guide 1.71, Welder Qualification 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, Protection, and Cleaning of Austenitic Stainless Steel Exposure to contaminant was avoided by carefully controlling all cleaning and processing materials which contact stainless steel during manufacture and construction. Any inadvertent surface contamination was removed to avoid potential detrimental effects. 4.5-8

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Special care was exercised to ensure removal of surface contaminants prior to any heating operation. Water quality for rinsing, flushing, and testing was controlled 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 Construction (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 allowable 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 stresses (60% and 40% of yield, respectively). For purposes of mechanical design, the postulated failure resulting in the highest forces is an instantaneous circumferential separation of the CRD housing from the reactor vessel, with the reactor at an operating pressure of 1086 psig (at the bottom of the vessel) acting on the area of the separated housing. The weight of the separated 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 equipment 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 Schnerr, 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.

4.5-9

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6 FUNCTIONAL DESIGN OF REACTIVITY CONTROL SYSTEMS Functional design of the control rod drive (CRD) system is discussed below. Functional designs of the recirculation flow control system and the standby liquid 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 abnormal 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 rod 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 rapid control rod insertion (scram) is signaled so that failure of power sources external to the positioning device does not prevent other positioning devices control rods from being inserted.

4.6.1.1.1.2 Power Generation 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 core reactivity by incrementally positioning neutron absorbing control rods within the reactor core in response to manual 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 4.6-1

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 system consists of locking piston CRD mechanisms, and the CRD hydraulic system (including power supply and regulation, hydraulic control units (HCUs), interconnecting piping, instrumentation and electrical controls). 4.6.1.1.2.1 Control Rod Drive Mechanisms. The CRD mechanism (drive) used for positioning the control rod in the reactor core is a double-acting, mechanically latched, hydraulic cylinder using water as its operating fluid (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 servicing. The bottom location makes maximum utilization of the water in the reactor as a neutron shield 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 piston 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 insertion when required. A mechanism on the drive locks the control rod at 6-in. increments of stroke over the length of the core. A coupling spud at the top end of the drive index tube (piston rod) engages and locks into a mating socket at the base of the control rod. The weight of the control rod is sufficient to engage and lock this coupling. Once locked, the drive and rod form an integral 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 hydraulic 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 limit 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 just below the large display on the vertical part of the benchboard. This display presents the positions of the control rod selected for movement and the other rods in the affected rod group. For display purposes the control rods 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 the positions, in digital form, of the rods in the 4.6-2

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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 operating 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 are 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 piston. The drive piston and index tube make up the main moving assembly in the drive. The drive piston operates between positive end stops, with a hydraulic cushion provided at the upper end only. The piston has both inside and outside seal rings and operates in an annular space between an inner 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 mounted with one set sealing in each direction. A pair of nonmetallic bushings prevents metal-to-metal contact between the piston assembly and the inner cylinder surface. The outer piston rings are segmented step-cut seals with expander springs holding the segments against the cylinder wall. A pair of split bushings on the outside of the piston prevents piston contact with the cylinder 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. Circumferential 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 (part 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 locking groove in the index tube. The collet piston is normally held in the latched position by a force of approximately 150 lb supplied by a spring. Metal piston rings are used to seal the collet piston from reactor vessel pressure. The collet assembly will not unlatch until the collet fingers are unloaded by a short, automatically sequenced, drive-in signal. A pressure, approximately 180 psi force, slide the collet up against the conical surface in the guide cap, and spread the fingers out so they do not engage a locking groove. 4.6-3

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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 bushing for the index tube. If reactor water is used during a scram to supplement accumulator 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. The 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 upper 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 functions as a positive end stop at the upper limit of control rod travel. Piston rings and bushings, similar 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 space for a set of spring washers which serve to protect both the drive piston and the stop piston from damage as the drive piston reaches its end of travel. The upper end of the piston tube has a series of orifices 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 pressures generated in the buffer are confined to the cylinder portion of the stop piston, and 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, position 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 tube 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 latching point. Two additional switches are located at each midpoint between latching points to indicate the intermediate positions during drive motion. Thus, indication is provided 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 position, the drive can pass this position and actuate the over-travel switches only if it is uncoupled from its control rod. A convenient means is 4.6-4

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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 assembly 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. The seals contain reactor pressure and the two hydraulic control pressures. Teflon coated, stainless steel rings are 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 through 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 differential 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) accommodates 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 then enters the spud and prevents uncoupling. Two means of uncoupling are provided. With the reactor vessel head removed, the lock plug can be raised against the spring force of approximately 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 portion of the drive mechanism is pushed up against the uncoupling rod assembly, which raises the 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 socket 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 Materials of Construction. Factors that determine the choice of construction materials are discussed in the following subsections. 4.6-5

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 resistance. The column and tensile loads can be satisfied by an annealed, single phase, nitrogen strengthened, austenitic stainless steel. The wear and bearing requirements are provided by malcomizing the complete tube. To obtain suitable corrosion resistance, a carefully controlled process 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 plating also prevents galling of the threads attaching the coupling spud to the index tube. 4.6.1.1.2.3.3 Collet Fingers. Inconel 750 is used for the collet 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 boiling 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 have the revised collet retainer design. General Electric (GE) has demonstrated by testing and 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 drives, GE has discovered evidence of intergranular stress corrosion cracking (IGSCC) in some CRD drive components and has made design improvements to preclude IGSCC in the future. The spare parts for CRD components purchased by Energy Northwest incorporate this revised design. Along with the other parts of the drive, the collet retainer tube, 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 resistant to degradation at high temperatures. The Carbon Graphite material is relatively soft, which is advantageous when an occasional particle of foreign matter reaches a seal. The resulting scratches in the seal reduce sealing efficiency 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 reactor vessel water are made of austenitic stainless steel except the following: LDCN-14-026 4.6-6

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015

a. Seals and bushings on the drive piston and stop piston are Carbon Graphite material,

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

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

d. Elastomeric O-ring seals 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 portions of the drives are designed and fabricated in accordance with requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section III. 4.6.1.1.2.4 Control Rod Drive Hydraulic System. The CRD hydraulic 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 positioning operation flows through the HCU, the exhaust header, and is returned to the reactor vessel via the HCUs of nonmoving drives. Each CRD has an associated HCU. 4.6.1.1.2.4.1 Hydraulic Requirements. The 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 approximately 260 psi above reactor vessel pressure is required. A flow rate of approximately 4 gpm to insert a control rod and 2 gpm to withdraw a control rod is required; LDCN-14-026 4.6-7

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015

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 instrumentation 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 Description. 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 continuous system operation if an inservice component requires maintenance. 4.6.1.1.2.4.2.1 Supply Pump. One supply pump pressurizes the system with water from a condensate supply header, which takes suction from the condensate 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 flow is diverted through a minimum flow bypass line to the condensate storage tank. This flow is controlled by an orifice and is sufficient to prevent immediate pump damage if the pump discharge 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 the filter. The 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 rugged 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 CRD pump suction filter can withstand a maximum differential pressure of 20 psi and an alarm indicates in the control room high suction 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. LDCN-14-026 4.6-8

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 If the CRD systems pump suction and discharge 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 rod operations and is detectable. 4.6.1.1.2.4.2.2 Accumulator Charging Pressure. Accumulator charging pressure is established by the discharge pressure of the system supply pump. During scram the scram inlet (and outlet) valves open and permit the stored energy in the accumulators 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 substantially) into the CRDs via the charging water header. The flow sensing system upstream of the accumulator 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 pressure is not essential to successfully scram the plant. Each of the accumulators are prevented from leaking back to the charging water header by a check valve. Therefore, the pressure required to scram each rod is maintained. The integrity and leaktightness of these check valves are routinely tested 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, drive cooling, and system stability. 4.6.1.1.2.4.2.3 Drive Water Pressure. Drive water pressure required in the drive header is maintained by the drive/cooling water 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 passes from the drive water pressure stage through two solenoid-operated stabilizing valves (arranged in parallel) and 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 withdrawal 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 valves. Thus, flow through the drive/cooling water pressure control 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 stabilizing valves to be adjusted when necessary. Differential pressure between the reactor vessel and the drive pressure stage is indicated in the control room. 4.6-9

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6.1.1.2.4.2.4 Cooling Water Header. The cooling water header is located downstream from the drive/cooling water pressure 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 virtually constant. Therefore, once adjusted, the drive/cooling water pressure control valve will maintain the correct 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 changes in the cooling requirements of the drives, as drive seal characteristics change with time. A flow indicator in the control room monitors cooling water flow. A differential pressure indicator in the control room indicates the difference between reactor vessel pressure and drive/cooling water pressure. Although the drives can function without cooling water, temperatures above 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 individual HCU banks to an 8-in. combined return header) 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 evaluated as part of the plant design basis. The header piping is sized to receive and contain all the water discharged by the drives 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 circuit, 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 control room indicate the position of these valves. During a scram, the SDV partly fills with water discharged from above 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. LDCN-14-026 4.6-10

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT November 2017 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. Two transmitter/level switches (non-indicating) and two transmitter/level indicating switches directly connected to each instrument volume monitor the volume for abnormal water level. They provide redundant and diverse input to the RPS scram function. One transmitter on each instrument volume also provides input for the control room annunciation and control rod withdrawal block function. There are three different actuation levels. At the lowest level, a level switch on each instrument volume actuates to indicate that the volume is not completely empty during post-scram draining or to indicate that the volume starts to fill through leakage accumulation at other times during reactor operation. At the second level, one level switch on each instrument volume produces a rod withdrawal block to prevent further withdrawal of any control rod, when leakage accumulates to half the capacity of the instrument volume. The two level switches and the two level indicating switches on each instrument volume are interconnected (one of each per trip channel) with the RPS and will initiate a reactor scram on high water level while sufficient volume for a full scram still exists within the SDV. To provide diversity for the RPS function the two transmitters per channel use a different sensing operating principle and have a different transmitter manufacturer. The level switches and the level indicating switches in each channel are also from different manufacturers. In the event of a slow or partial loss of air pressure, the high-level scram setpoint and the SDV/IV system capacity ensure that scram capability is maintained even in the event of maximum inleakage into the SDV prior to a scram. Analysis, assuming the maximum inleakage of 5 gpm and using the 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 level in the IV, a scram signal is produced. This will cause the air supply to the vent and drain valves to vent, thereby ensuring 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 furnishes pressurized water, on signal, to a drive unit. The drive then positions its control rod as required. Operation of the electrical system that supplies scram and normal control rod positioning signals 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, electrical 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. LDCN-14-003 4.6-11

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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 Insert Exhaust Valve. The insert exhaust solenoid valve 121 also opens on an insert signal. The valve discharges water from above the drive piston to the exhaust water header. 4.6.1.1.2.4.3.3 Withdraw Drive Valve. The withdraw drive valve 122 is solenoid operated and opens on a withdraw signal. The valve supplies 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 Speed Control Units. The insert drive valve and withdraw exhaust valve have a speed control unit. The speed control unit regulates the control rod insertion and withdrawal rates during normal operation. The manually adjustable flow control 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 compensate 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 scram exhaust valve. The scram pilot valves are identical, three-way, solenoid-operated, normally energized valves. 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 open on both valves. The pilot valves (Figure 4.6-5) are arranged so that the trip system signal must be removed from both valves before air pressure can be discharged from the scram valve operators. This prevents the inadvertent scram of a single drive in the event 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 the 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 Scram 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 4.6-12

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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 supplanted by reactor vessel pressure. The accumulator is a hydraulic cylinder with a free-floating piston. The piston 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 actuates 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 accumulator instrumentation block. 4.6.1.1.2.5 Control Rod Drive System Operation. The CRD system performs rod insertion, rod withdrawal, and scram. These operational 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 signal 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 illustrated in Figure 4.6-3, the locking mechanism is a ratchet-type device and does not interfere with rod insertion. The speed at which 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 psi) will then be available to cause continued insertion. With 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 fingers in place. The index tube must 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 drive piston and opening the area below the piston 4.6-13

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 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 set to give the control rod a shim speed of 3 in./sec. The entire valving sequence is automatically controlled and 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 drive piston is vented to the SDV. The large differential pressure (initially approximately 1500 psi and always 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 initial acceleration and provides a large margin of force to overcome friction. After the initial acceleration is achieved, the drive continues at a nearly constant velocity. This characteristic provides a high initial 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 accumulator in the HCU has approximately 1450-1510 psig on the water side and 1000-1200 psig on the nitrogen side. As the inlet 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 accumulator completely discharges with a resulting gas-side pressure of approximately 575 psi. The CRD accumulators 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 drive flange allows reactor pressure to supply the scram force whenever reactor pressure exceeds 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, reactor pressure alone will insert the control rod in the required time, although the accumulator does provide 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. LDCN-16-013 4.6-14

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 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 changes in nuclear reactivity so that reactor power level and power distribution can be controlled. The system allows the operator to manipulate 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 any resulting nuclear transient could not be sufficient to cause fuel damage, and

b. The clearance between the CRD housings and the supports 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 compress approximately 2 in. under the design load. LDCN-08-035 4.6-15

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 The support bars are bolted between the bottom ends of the hanger rods. The spring pivots at the top and the beveled, loose fitting ends on the support bars 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 respective CRD housing that it would support in the postulated accident. When the support bars and grids 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, this 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 springs, and two adjacent beams. For purposes of mechanical design, the postulated 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 vessel design pressure) acting on the area of the separated housing. The weight of the separated housing, CRD, and blade, plus the pressure of 1250 psig acting on the area of the separated housing, gives a force of approximately 35,000 lb. This force is multiplied 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, which are Schnorr, Type BS-125-71-8. 4.6.2 EVALUATION OF THE CONTROL ROD DRIVES Safety evaluation of the control 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. 4.6-16

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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, B4C powder, hafnium, and type 304 austenitic stainless steel, have been found suitable in meeting the demands of the BWR environment. 4.6.2.1.2 Dimensional and Tolerance Analysis Layout studies are done to ensure that, given the worst combination of extreme detail part tolerance ranges at assembly, no interference exists 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 restriction to rod motion and will listen for any scraping or binding noises which may signify rod misalignment. In addition, the function of each CRD line will be measured as indicated by the differential pressure developed across the CRD piston during notch withdrawal. These differential pressure traces will be compared to reference traces to proper operation and the absence of abnormal friction. 4.6.2.1.3 Thermal Analysis of the Tendency to Warp The various parts of the control 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 control 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 pressure 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 remain open, which is unlikely, calculations indicate that the steady-state control rod withdrawal velocity would be 2 ft/sec for a pressure-under line break, the limiting case for rod withdrawal. 4.6-17

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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 addition, analysis has been performed both on the velocity limiter device and the effect of probable control 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 failures 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 continuously 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 analysis 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 performed considering both a recirculation 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 deformations of the guide tube never are great enough to cause the free movement of the control rod to be jeopardized. 4.6-18

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 4.6.2.1.9 Evaluation of Control Rod Velocity Limiter The control rod velocity limiter limits the free fall velocity of the control rod to a value that cannot result in nuclear system process barrier damage. This velocity is evaluated by the rod drop accident analysis in Chapter 15. 4.6.2.2 Control Rod Drives 4.6.2.2.1 Evaluation of Scram Time The rod scram function of the CRD system provides 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 multiple malfunctions are postulated, studies show that an unplanned rod withdrawal can occur at withdrawal speeds that 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 analyzed 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 drive housing is raised into 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 housing. The housing material is seamless, type 304 stainless-steel pipe with a minimum tensile strength of 75,000 psi. The basic failure considered here is a complete circumferential 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 events is foreseen. The housing would separate from the vessel. The 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 support 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 far enough to clear the vessel 4.6-19

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 penetration. Reactor water would leak at a rate of approximately 220 gpm through the 0.03-in.-diametral clearance 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 separate from the vessel. The drive and housing would be blown downward against the CRD housing support. Calculations indicate that the steady-state rod withdrawal velocity would be 0.3 ft/sec. During withdrawal, pressure under the collet piston would be approximately 250 psi greater than the pressure over it. Therefore, the collet would be held in the unlatched position 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 drive housing flange: (1) pressure-under line break; (2) pressure-over line break; and (3) coincident breakage of both of these lines. 4.6.2.2.2.2.1 Pressure-Under Line Break. For the case of a pressure-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 directly 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 insert on a scram signal. The ball check valve is designed to seal off a broken pressure-under line by using reactor pressure to shift the check ball to its upper seat. If the ball check valve were prevented from seating, reactor water would leak to the atmosphere. Because 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 recorder. A second indication would 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 collet 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 control rod withdrawal velocity would be 2 ft/sec. 4.6.2.2.2.2.2 Pressure-Over Line Break. The case of the pressure-over line breakage considers the complete breakage of the line at or near the point where it enters the housing flange. If the line were to break, pressure over the drive piston would drop from reactor 4.6-20

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 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 exhaust 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 more than 10 gpm, based on experimental measurements. If the reactor were hot, drive 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 Simultaneous Breakage of the Pressure-Over and Pressure-Under Lines. For the simultaneous breakage of the pressure-over and pressure-under lines, pressures above and below the drive piston would drop to zero, and 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 below 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, the fully inserted drive, and operation of the drywell sump pump. 4.6.2.2.2.3 All Drive Flange 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 alloy steel, with a minimum tensile strength of 125,000 psi. Each bolt has an allowable load capacity of 15,200 lb. Capacity 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 bolts were to occur, the drive would separate from the housing. The control 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 pressure 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 downward past the velocity limiter piston, through the large drive filter, and into the annular space between the thermal sleeve and the drive. For worst-case leakage calculations, the large filter is assumed to be deformed or swept out of the way so it would offer no significant flow restriction. At a point near the top of the annulus, where pressure would have dropped to 350 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. LDCN-18-022 4.6-21

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 If the collet were latched, control rod ejection would be limited to the distance the drive can drop before coming to rest on the support structure. There would 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 Joining 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 around the housing. The flange material is forged, type 304 stainless steel, with a minimum tensile strength of 75,000 psi. The housing 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-sectional 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 and 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 and limit control rod motion to approximately 3 in. Downward drive movement would be small; therefore, most of the drive would remain inside the housing. The pressure-under and pressure-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 flange-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 drive. The leakage rate would be approximately 840 gpm. If the basic failure were to occur during control rod withdrawal (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 support structure. The calculated steady-state rod withdrawal velocity would be 0.13 ft/sec. Because pressure-under and pressure-over lines remain intact, driving water pressure would continue to the drive, and the normal exhaust line restriction would exist. The pressure below the velocity limiter piston would drop below normal as a result of leakage from the gap between the housing and the flange. This differential pressure 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 4.6-22

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 withdrawal to approximately one-half of normal speed. With a 560 psi differential across the collet piston, the collet would 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 drive 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 gpm. 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 withdrawal would stop, but the collet would remain unlatched. The drive would be stopped 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 pressure in the annulus outside the drive to approximately 540 psig, thereby reducing the pressure acting on top of the drive piston to the same value. A pressure differential of approximately 710 psi would exist 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 drilled in the drive flange. The outer end of this hole is sealed with a plug of 0.812-in. diameter and 0.25-in. thickness. A full-penetration, type 308 stainless steel weld holds 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 across 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 flange. Actually, hot reactor water would flash 4.6-23

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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 open plug hole in the flange would cause reactor water to flow downward past the velocity limiter 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 would 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 and 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 assumes liquid flow, but flashing of the hot reactor water to steam would reduce this rate to a lower value. 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 failure), the collet would relatch at the first locking groove. If the collet were to stick, calculations indicate 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 Water 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 either 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. 4.6-24

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 If the flow through the drive/cooling water pressure control valve were to be stopped, as by a valve closure or flow blockage, the drive pressure would increase to the shutoff 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 differential of 1670 psi across the collet piston would hold the collet unlatched. Flow would be upward past the velocity 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 pressure would increase and the drive water pressure would decrease. The resulting cooling water pressure increase could cause control rods to drift inward. The existence of rod drifts would be alarmed to the control room operator for appropriate action. The resulting drop in drive water pressure would make normal control rod notch movements impossible but would not affect the ability of the scram function. In both of the cases described above, the manually operated bypass PCV 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 the failure to the full open or full closed position of the drive/cooling water PCV will cause perturbation in the CRD system 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 prevented from reseating following the insert portion of a drive withdrawal sequence, water below the drive piston would return to the reactor through the vessel ports and the annulus between the drive and the housing rather than through the speed control valve. Because the flow 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 collet piston would be approximately 40 psi. Therefore, the collet would tend to latch and would have to stick open before continuous withdrawal at 2 ft/sec, could occur. Water would flow upward past the velocity limiter piston, generating a small retarding force of approximately 120 lb. 4.6.2.2.2.10 Hydraulic Control Unit Valve Failures. Various failures of the valves in the HCU can be postulated, but none could produce differential pressures approaching those described in the preceding paragraphs and none alone could produce a high velocity withdrawal. Leakage through either one or both of the scram valves 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. 4.6-25

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 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 drive continues to withdraw at a fraction of the normal speed. This assumption is made because there is no known means for the collet fingers to become unlocked without some initiating signal. Because 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 collet 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 system and is independent of reactor vessel pressure. Tests have shown 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 withdrawal and it has been shown above that only multiple failures in a drive unit and its control unit could cause an unplanned 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 the SDV headers. This allows for direct detection of liquid buildup so that the ability 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 system capacity ensure that scram capability is maintained even in the event of maximum inleakage 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 requirements, 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 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 drain valves to vent, thereby ensuring that the vent and drain valves close and isolate. For leakage rates which do not result in buildup in the IV, the leak will drain to the reactor building equipment drain system. LDCN-14-003 4.6-26

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 pressure, and the reactor vessel pressure itself at power;

b. Each drive mechanism has its own scram and pilot valves 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 signal and mode of operation override all others;

d. The collet assembly and index tube are designed so they will not restrain or prevent control rod insertion 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 independently supported and controlled 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 initial 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 compression (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 substantially limited below one drive notch movement (6 in.). Sudden withdrawal 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. LDCN-14-026 4.6-27

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 The CRD housing supports are in place during power operation and when the reactor coolant system is pressurized. If a control rod is ejected during shutdown, the reactor remains subcritical because it is designed to remain subcritical with 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. Because the supports do not contact any of the CRD housing except during the postulated accident 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 conditions for 5000 hr. These tests demonstrated the following:

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

b. Wear, abrasion, and corrosion of the nitrided stainless parts are negligible.

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

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

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

4.6.3.1.1.2 Factory Quality Control Tests. Quality control of welding, heat treatment, dimensional tolerances, material verification, and similar factors is maintained throughout the manufacturing process to ensure reliable performance of the mechanical 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; 4.6-28

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998

2. Electrical components are checked for electrical 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 hydrostatically tested in accordance with the applicable code;

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

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

4. The units 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 that are partially withdrawn from the core can be tested for rod-following by inserting or withdrawing the rod 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. 4.6-29

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 Hydraulic supply subsystem pressures can be observed from instrumentation 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 the 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 specification defined criteria and acceptable ranges of such characteristics as seal leakage, friction, and scram performance under fixed test conditions which 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 coolant temperatures and pressures from ambient to operating. 4.6.3.1.1.5 Surveillance Tests. The surveillance requirements 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 following fuel movement within the RPV or control rod replacement, 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;

c. Each withdrawn control rod shall be exercised one notch (i.e., inserted at least one notch and then may be returned to its original position) in accordance with the Technical Specifications.

LDCN-17-028 4.6-30

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 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 applied 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 indirectly that the rod and drive are coupled. The over-travel position feature provides a positive check on the coupling integrity, for only an uncoupled drive can reach the over-travel position;

e. During operation, accumulator 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 outage, 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 refueling 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 as necessary based on performance history and the preventative maintenance program requirements.

4.6.3.1.1.6 Functional Tests. The functional testing program of the CRDs consists of the 5-year maintenance life and the 1.5X design life test programs as described in Section 3.9.4.4. LDCN-18-022 4.6-31

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 There are a number of failures that can be postulated on the CRD but it would be very difficult to test all possible failures. A partial test program with postulated accident conditions and imposed single failures is available. The following tests with imposed single failures 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 performance with V120 malfunction,

f. HCU drive up outlet control valve (V121) failure,

g. HCU drive up inlet control 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 velocity limiter drop test.

Additional postulated CRD failures 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 control rods are then inserted. When the support structure is reinstalled, it is inspected for correct assembly with particular attention to maintaining the correct gap between the CRD flange lower contact surface 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. 4.6-32

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 A seismic event or the postulated accident environments (see Section 3.11) are not considered potential common mode failures since the essential (scram) portions of the CRD system are designed to Seismic Category I standards and to operate as required under 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 override any other CRD function. The SLC system has two independent power supplies 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 physical barriers and/or by at least 40 ft of physical separation. 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 potential missiles. The location of the primary components of these 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, combined with a failure to inject boron 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 means to scram the control rods which is diverse and independent from the RPS. The ARI system may be actuated either 4.6-33

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 the scram inlet and outlet valves to open. The CRD units then insert the control blades to shutdown the reactor. The ARI system has been designed to ensure that rod motion begins 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 conditions and compliance with ARI design 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 scram system and is, therefore, not redundant in itself. That is, the ARI system is only one system with two divisions. Both divisions must function properly for the design basis rod insertion times to be met. The ARI system is, however, redundant in the aspect of preventing 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 Electric Company, Atomic Power Equipment Department, APED-5555, November 1967. 4.6-2 NEDE-31096-P, Licensing Topical Report, Anticipated Transient Without Scram, Response to NRC ATWS Rule 10 CRF 50.62, February 1987. 4.6-34

Amendment 53 November 1998 Control Rod Assembly Unlocking Handle (Shown Raised Coupled View Against Spring Force) Lock plug Unlocking Tube Index Tube - Drive Spud Actuating Shaft Velocity Limiter Lock Plug Return Springs Socket Control Rod to Control Rod Drive Coupling Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.99 Rev. Figure 4.6-1 Form No. 960690

Amendment 53 November 1998 Coupling Spud Bottom of Reactor Vessel Guide Cap Drive Housing Fixed Piston (Stop Piston) Collet Piston Latch (Collet Fingers) Return Spring Collet Piston Piston Tube Index Tube Drive Cylinder Moving Piston (Main Drive Piston) Drive Insert Line Drive Withdraw Line Arrows show water flow when the drive is in the Ball Check withdrawal mode of Valve operation. PR Pressures shown are maximum. PR = Reactor Pressure Control Rod Drive Unit Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.99 Rev. Figure 4.6-2 Form No. 960690

Amendment 53 November 1998 Spud Control Rod Guide Tube Index Tube Index Tube Outer Filter Outer Filter Inner Filter Guide Stop Guide Reactor Piston Reactor Cap Cap Pressure Pressure Vessel Vessel Drive Housing Thermal Sleeve Drive Housing Thermal Sleeve Buffer Hole Coll. Pist. Coll. Pist. Index Tube Index Tube Pressure Outer Tube Inner Tube Inner Tube Outer Tube Pressure Over Under Port Port Drive Piston Drive Piston Rod Piston Information Detector Probe Piston Tube Housing Housing Piston Tube Flange Flange Cooling Circumferential Orifice Screen Drive Piston Main Tube Head Flange Inst Tube Control Rod Drive Unit (Schematic) Columbia Generating Station Final Safety Analysis Report Draw. No. 960222.96 Rev. Figure 4.6-3 Form No. 960690

15 14 13 12 11 10 8 7 2 Amendment 65 December 2019

                                                                                                                                                                                                                                                                                                                                   ~                                                              =

1"CR0(55,t;-1

                                                                                                                                                                                                                                                                                                                                           - - ARI CHN-INEL "El" CRD - SPV- 258

1. ALL PRESSURE ANO FLOW I NSTRUMENT ROOT VALVES NOT LABELED WI LL BE 3/4" CLOBE

                                                                                                                                                                                                                                                                                                                                           - - ARI CH.ANNEL "A"                                        UNLESS SPECIF IC ALLY NOTED OTHERW ISE Cf!O-SPV-25.'.

2 THES( COM PON ENTS AR( SUPPLIED WITH 1*c ss - J - 15 TH[ ASSOC JATE0£0UIPM(NT i "CR0(55) - J- 15 (B/7) J PIP!NG VALVES AND .\SSO CI ATED CO MPON[ N"TS ON THJS DRAWH-IG S1-1.ALL BE CLASSIFIED 1'S FOLLOWS (BREAK POINTS ARE INDICATED ON THE FLOW DIAGRAM) A.. ALLPIPI NGA NOVALVE S,E XCEPTAS NOTED 1 1/2" PIPET W/BLI ND SEISIJIC CATEGORY llel FLANGE,7PLCS. QUALITY CLASS II CODE GRO UP D

                                                                                                                                                                                                                                                                                                                                                                                                                       $HANGERS TO BE DESIGNED TO SEIS MI C CATEGORY I LOADS C. PIPING ANO VALVES OF SUBSYSTEM (1 0 ). ( 1 1),( 12). (50), (53),{55).

ANO (60 ) AS NOTED SEIS~IC CATEGORY I QUALITY CLASS I CODE GRO UP 8 D. ~~~~uc~~N_:CT!~2~ 01!gLJg:~-~~~GN. I NSTRU MElflS CRD - LT-1 3,,1, THRU CRD - LT - 13D INCLUDES DI1!.PHRAGM

                                                                                                                                                                                                                                                                                                                                                                                                              ..\ND HOUSING)

E. INSTRUMENT IMPU LSE LINES AND I/ALY£S AS NOTED

g:gmi::Er:~ \iu "CRD( ll)-45-~4 rnRU 6 SE IS MIC CATEGORY I 1 6 QUALITY CLASS I CODE GROUP 8

                                                         ........~~-

R~UHC u - xnx(c12 -000 1

                                                                                                                                                                                                                                                                                                                                                                                                       # UNJOUE LI NE NUMBERS 1 THRU 18!'i ARE H                                                                                                                                                                                                                                                                                                                                                                                                    DIRECTLYRELATED TOTHEHYDRAULIC CO NTROL UNIT (HCU) MPL NUMBERS ASSIGNED BY G.E. THE 185 UNIQUE [PN"s ARE DENOTED BY * * ** (CRD- 1/- 105/XXXX).

5 ALL INSTRUMENTATION ON THIS DRAWING TO BE I DENTffl ED BY THE PR EFIX " CRO" UNLESS OTHERWISE NOTED t---t--+-+,,-/-,,+-,.-,,+,-,,-, +--~--r,< ); XXX(C l2 6. CODE BREAK OUIN ITIONS FOR THERM DWELLS

                                                                   .,_,c,_,,,,,,,~:::::: - ---
                                                                                   ,=t:'.:::--

ARE SHOWN ON M610, -INSTALLATION OF THERMOWELLS AND SAMPLE PROBES".

7. HCU PIPI NG ANO VALVES AS NOTED SEISMIC CATEGORY I QUALITY CLAS S I CODE GROUP D

                                                                 !rn~im::E~l~%\lsw 1"CRD( 11 )-4S-2J THRU 3.11 G                                                                                     1
                                                                                                                          - .I.RI CflANNEL "B"
                                                                   .,_,c,-m,(1~:.:.:!; - ---

CRD -HCU-XXXX(C 12-DOOl-2J ) t:'.::-#-:--

                                                         *cRC(1 1) 10THRU22 t---t--+-+-+---tr--+--'            ;-:S:g:g1~l=!Elg~1r~u          2

11. THE POSITION O[T[CTO~ AND TEMPERAT\JRE

                                                                                                                      =
                                                                                     ~~ w f~~U HCU-XXXX(C12-D00 1-1 0)                                                                                                                                                                                                                                                                                                                   EL EMENT ARE PART OF THE ORJV[ UNlT SCRA M                                                                                                                                                                                                                                                                        ANO 00 NOT HAV E SEPARATE EPNs.
                                                                                          -.+-: : : -

RD -HC u - xnx(c12 - 000 1- 22)

                                                                                      ~

INSTR VOLUME " A" 12. THIS JSACT UALLY AOPJS BU TISUSEO AS CRO TK SOIVIA A OP I, WIRES AND SWITCH ARE SP/I.RED IN PLACE.

13. FLEX HOSE IS SH OWN BETWEE N CRD -SP\1 - 117/* , CRO-SP\1-1 18/ *. &

CRO - V- 1 16/'. COPPER TUBING IS AN ACCEPTAB LE ALTERNATIVE . 2"CRO(:lo0) - J -I 1J.i"CAS(5)- 1S TGHPO INTVENTS{TYP) CltARGING WATER HEADER (ORI\IE WATER HEADER) 1"CRD{5-,s ([XHAUST'll'AT[R I-OJ)[R)

                                ~

S i I LEGEN D:

1. ALL VALVES SUFFIXED WITH A (TH)

DEN OTE A THROTT LED VAL.I/[.

                                ~I I      l!JIBQG.EII I CHARGI NG UNIT I

I D I I I I

                                                                                                                                                     , -~

I SPS _J I Ir-----------, L--- ~i~ts:-L~~; 11 I

                                                                                                                                                    ~      f ROMR[-'CTOR         I
                                                                                                                                                    ,...~PROTECTIONS'l'STEM      :

11 I TOCRO*l/*\60 I L___ I ZONE{K/6) I I L_ ~ I

                                                                                                                                                          ~                      I 01>,::,              RPS                \wa( TH)                   TOCRO-V- \8 \

ZONE (F/ 6)

                                                                                                                                               %,,,              6 CR0- Y- l 0C        CRD-J.*182 3/4 I

I I TO SCRAM I DISCH. HEAOER

                                                                                                                                                                            ,- _J I
                                                                                                                                                                                                                                                                                                                    "'"'"}

NSERT I I P~~~ll~~~~M F1J6 FROIJREACTOR w..NUAI. CONIROL

                                                                                                                                                                                                                                                                                                                 ~JEWw TO CRO - M/A- 0009A & B M~28- 2 (F/6)

DETAI L " B" WATER DETAIi "A" HYDRAULIC CON TROL UNIT (HCU) (

• SEE NOTE 4)

Control Rod Drive Hydraulic System Columbia Generating Station Final Safety Analysis Report Draw. No. M528-1 Rev. 85 Figure 4.6-5.1 Form No. 960690ai

Amendment 66 14 10 December 2021 15 13 12 11 2 CONTFRDM rno~(*),o, M528-1 (D/5) [ CRD-Y-718 1/4" 1/2_" OD SS ~ 4 1/2" OD SS CONTONM529 C12-NDH 'f CRD-V-717 C12-R004 (J/12)

                                                                                                                                                                                                                                                                                                                                                                                                            ~

CONT FROM M528-1 (C/B) lci7 " GciJ C12-Rl305 CONTONt.A529 (K/6)

                                 - - -->-----------_..J                                                                                                                                                                                                                                                   6                  B
                                                                                                                                                                                                                                                                                                          ~   IC12-R60.3 ~

L _ _ _ _ _ _ _ _ _ _ _J 1 c12- R00 5 I CRD-V-711 16 CONTONt.A529 (J/5) FOUR ORIFICES CONNECTED IN SERIES d3B e<o-ec-a ~"-=' r---v~fi-'-{_};;,;._______:::...______ CRD-Y-61 """

                                                                                                                                                                                                                                                                                                                                                                          .f.RE.SS..IIBE I,~-~~

Cl2-R015 2"

                                                                                                                                                                                                                                                                                                                                                                            -"'IIJlli G
                                                                                                                                                                                                                               ~--t>'-;c1----s,.;------l CONTONM529 C12-N600   C12-N00S ce o

r~

                                                                                                                                                                                                                                                                                                                                                                 ~:rt [12-FOOJ LJ TOC12-dPT-I\Q11 ZONE(H/5)

(J/12) l"CR0(7)-4S CRD-V-~~* ] 1/2" Pl{1)-4S-CRD-Fl-4C FLOW CONTROL PANEL 4C CRD 1 MS 1/2" oc ss ,- I

                                                                                                ~@'ID Fl
                                                                                                           -n~eo+ao,       I                                       1/2_" OD SS rr~---;--->.-------.---ctk>--:-----<>>--,."-="----"-!_,'_,J-,S-D----!~_J_-,-,_-tV,~tg;---S L

CONTONM529 CRD-V- 4 C4 I CRD-F-,4C 4C (H/4)

                                                                                             ':.CR~-::_ -     -  __J                                                                           (REF)
                                                                                                                                                                                                                                                                                                                                                                                                                ,f;-~

I CRD-Y-752 [ic,]L2J Cl2-R604 C12-RD03 CONT ON DWG M523-2(C/10}

                                                                                                                                                                                                                                                                                                                                                                                                                                                              "'I "DW(30)-1S FLUSHCONN r:,-----'---:;..;.="'--C..,L;__              _;l.-,'Si21TJN(Ji,i)

DWG M517 ZONE (B/B) 3/4"CRD(~1)-1 1/4"NPT TO RWCU PUMPS

                             ~

DRAIN MOTOR PURGE

                                 'i
                                 '1'
                                 ,i,.  ,h
                                  <    D po- 4rCR  -.
                                       ~                                                                                                                                                                                                                                  3/4"CRD(50)-1 2"CRD(54)-1                                                                                                                                                                                                                                           3/4"CR 14)-4S I'

4"CRD(l)-1

t.D CONT. ON o

I I 1---..___n_<;;;;O(C;;_)-_;<S'---icoNT FRO~ ZOOE (F/B) ZONE (D/9) 1/4"CR 51 -1S C ti f-----L ____ _J

                                                                                                                                                                                                                                                 ~                                     LcaD+,rn filIAfL_J;
                                                                                                                                                                                                                                                                                                                                    ,-==~~-=                          _,

I e, I I I I ~ r"-""'"'"'"-""-'--'-'- - - - - ~

                                                            =w CRD-ST-28 I

I I l CRD-V 4 CRD- 5 I 2"CRD(2)- 4S w SEE DWG M525-2 P-lA(B/10) 1 fRD-4 CR -. P-18(8/11) 3/4"CRD(S0)-1 LUBRICATION DETAIL FOR CRD P 1 (A & 8) 1..R. (ALL EPN NUMBERS ARE FOLLOWED BY EITHER A OR B DEPENDING ON THE PUMP THEY SERVE) TOCONDENS'.TESTORAGETANK (SEE DWG ~527-1 (B/7) Control Rod Drive Hydraulic System A Columbia Generating Station Final Safety Analysis Report Draw. No. M528-2 Rev. 11 Figure 4.6-5.2 Form No. 960690ai

Amendment 53 November 1998 3: 4 5 I 6 .7 8 CEl£11AL(j)mc11111: 2

                                                                                                                                                                                                                                                                               *.*,, P         E    !AGRAM 92109h6         CONTROL ROD DRIVE HYO SYS
              ~
                                                                                                                                                                                                                                                                              'lo\l lll('f 'O* NU: L(.AA  ~~L~R    sy s
               ..~,.~re~ )i{l((t11*,. *.IP'!'ll:,.,S: A"{   u.o,t,U(L' 6"' ~l.11PH. ..-~ .. 1rc-.-i ~hft""'S REFERENCE DOCUMENTS                                                                        MPL llEM No                                                                                                                                                                                   (C12*10201 A

l CONTROL ROD Dli'IVE HYO SYS P&IO - - - - - - - - - - - Cl:?*1010 2 CONTROL ROD ORIIIE HYD SYS l'CO - - - - - - - - - - - Cl2*1030 STABILIZING VAL VE ASSEMBLY, f"007 3 DES.IGN SPECIFICAT'ON - - - - - - - - - - - - - - - - - C12*4010

           &ID- - - - - - - -                                 -       - -    - -    -   13JS- 1010                                                                                                                                         NOTEs:

I. FOR DA.TA PERTAINING TO NUMSERS, WITHiN H(XAGONS REFER TO PROCESS DATA REI' 6-2, SOURCE OF CRO SYSTEM WATER SMALL BE NORMALLY FROM CONOENS4TE TREATMENT B SYSTEM. CONDENSATE STORAGE TANK IS THE ALTERN4TE SOURCE IF CONDENSATE lR'EMMENT svsro-1 IS !1;0T iN OPERATION. FOR C[iAILEO OE.SIGN REQUIREMENTS FOR SOURCE ANO ~UALITY Of" WATER, SFE REF J, REACTOR VESSEL J. DELE TEO

4. MAXIMUM ALLOWABLE PUMP SUCTION PRESSURE SHALL BE 50 PSIG.

C 6-u_Jl

                                                                                         ~

AECIRCULAT*ON SY~TEM SEAL PUR/3E LINE. D CONTROL DRIYE ROD WATER D003 DRIVE OPEN AT 2 gpm & 80p~*<l FILTER OTMEI< HCU'S WITHDRAWAL 1N'.>FRT

                                                                                                                                                                                                                                                      ,coNTAINMENT
                                                                                                                                                                                                   ....................................... " ...............u.

WITHDRAWAL INSERT

                                                                            'RO'                                                                                           COOLING HE ADER

• 00 CONDENSATE
• 00()1 STORAGE l~NK -
• CONDENSATE

                       *             ~                       .STORAGE                                                                                                      DRIVE HEADER I  SEE .        .      ROM                     38 MOTE Z            CONDENSATE TREATMEf'.IT SYSTEM
                                          . EFFLUENT              PUMP
                                           --ti*"'"""'I SUCT!ON*l'x'.'}-_ __                                                                                               CHARGING HEADER ftl TER

_.. ,. *oo,o HYDRAULIC CONT R'OL UNJT Control Rod Drive System (Process Diagram) Columbia Generating Station Final Safety Analysis Report Draw. No. 02C12-04,25,l Rev. 1 Agure 4.6-6.1 Form No. 960690

                     -               --                                                                                                                                  ,,&                                                                                                                                                                                Amendment 53 November 1998
                                                                                                           '                                                                                                                                                                              9:

I a-ta**"* Ii 3 ! ...

                                                                                                                                                                                                                                                                                             ~ IUtal .. ~ -

I I Ii I I 2 I  ! 4 I 5 I I  ! 7 I 8 j UIIIL(i)lllffllC I****************--****-****

                                                                                                                                                                                                                       -***---cn-1 i.*1**m I: -- 1!-*-* I: - r::__
              ~

I i..11111.HI Of'"l..-,\1 S"fC.1hlD U':I. 1*C *Ol.1.0~-. - 1::0 PROCESS OIAG DATA

                                                                                                                                                                                                                                                                                                             ,__ , ,_,._,oa
                                                   !                                                                                                                                                                                                                                             9'2.1D966AA           CONTROL ROD DRIVE HYO SYSTEM

.MOOE A NORMAL OPERATION 0

I

t

            *,.,! *-                LOCATION              IA     I     2          3                   5         SA        6            7        8        9       10
                                                                                                                                                                               "            12      13                                                                            MPL NO. Cl2-IOZO                                 I CONDITIONS:

F'LOW

• GPM 93 93 93 20 73 13 10 63 63 57 57 63 0 0 2 I. DRIVES LATCHED

2. PRESSURE Of" REACTOR IPRI AT 1000 PSIG.

PRESSURE fJS1G 21 19 1487 187 1476 16Z 1~2 ,..ss PR

• 260 PR
• 260 PR* 30 PR
• 30 PR PR PR* 30

3. MAXIMUM COOLING l"LOW TO DRIVES. MfNlltCUM REQUIRED PRESSURE AT POSITION IA IS 20 f"EET OF WATER AT 200 GPN.

j 0

                                                                                                                                                                                                           ~ SIZES THE COOLING                             WATER HEADERS.

i LOCATION 14 15 16 17 18 20 21 22 23 24 ZS 26 27 LINE LOSS FROM LOCATION 10 TO LOCATION 20 SHALL NOT EICCEEO 3 PSIG. FLOW. GPM 4 6 0 0 0 .3-4 MAX .34 t.lAX .3-4 MAX .3 MAX 0 0 0 0

                                                                     ,.ss
          **                       PRESSURE PSIG     PR

• 30 PR* 30 PR
• IS PR* 14 PR
• I PR PR PR 0

              .~,..;MOOE B                       ROD INSERTION 0         IA      I       2         3                    5        SA           6          7        8        9       10           II           IZ      13
                            ... LOCATION CONDITIONS:

FLOW

• Gflll 93 93 93 zo 73 73 10 63 63 57 57 59 0 .7 z t? f; z.

1. DRIVE INSERTING PRESSURE or REACTOR IPR! AT 1000 PSIG.

21 19 ,.,.97 1487 1-476 I4S5 PR

• 260 PR
• 260 PR* 30 PR
• 30 <PR* 8 *PA* 8 PR* 30 3. MAXIMUM DRIVING f"LOW TO DRIVES

                   . '.j           PRESSURE PSIG                                                     r 6Z      162
                           -.,*1                                                                                                                                                                           MODE 8 SIZES THE DRIVE WATER HEADERS.

c *.*. LOCATION 0 1* 15 16 17 18 20 21 22 23 24 25 26 27 -

         ..              *:~
                                                                                 .4 FLOW. GPM             0       2       0                   4                     0         4          4       1.3       .7        .7        .7             0
             ..         ,I PRESSURE PSIG PR,JO       PR* 30   1<155  PR

• 260 PR
• zso PR* 15 PR
• 91 Pa* 90 PR PR* 20 PR
• 20 PR* 8 0 I

I MAX MAX M/IX _;f

                 . ':{
                      '. l MOOE C                SCRAM                                                                                                                              .,

0

              . . .-1*.*

LOCATION IA I z 3 -4 5 SA 6 .7 8 9 10 II 12 13

1

          .... ~

CONDITIONS: FLOW, GPM 45 <15 45 20 25 25 10 15 15 15 15 15 15 14.9 0 D. I. DRIVES SCRAMMING I;I SEE 2. PRESSURE Of" REACTOR IPFU AT 1000 PSIG

• PRESSURE PSIG 21 21 1S50 1550 SEE 3. f"LOWS BASED ON MAXIMUM ROD VELOCITY Of" 85 INCHES PER SECOND.

NOTE 9 NOTE 9 MOOE C SIZES THE INSERT AND WITHDRAW LINES ** 0 LOCATION 14 15 16 17 18 20 21 22 23 24 25 26 27

         -~
         -:.*.:                    FLOW. GPM            0       0       0         0         0                     0        90         90      -3.6       JO       30     0.1

• SEE APPROX I

                     *ii                                                                                                                                                  NOTE 9          5565
       *J

-Ii.

I;:; PRESSURE PSIG 1167 MIN ?31 MIN PR 256 MAX 94 65 MAX

                     .,. J'                                                                                                                                                               SEE NOTE 10 MOOE 0          SCRAM COJ,tPLETED LOCATION   O*       "IA       I       z         3                   5         SA         6           7        8        9        10         II            12      13 CONDITIONS:

zoo ' FLOW. GPM* zoo 200 20 180 180 10 15 15 15 15 15 15 14.9 0 I, SCRAM WING OF' DRIVES COMPLETED

2. PRESSURE Of REACTOR IPRI AT o PSIG.

3. MAXIMUM CRO SUPPLY PUMP fLOW.

PRESSURE PSIG ZI 19 1210 >PR  :,,PR >>PR >PR >PR  :,,pff MOOE 0 SIZES THE PUMP SUCTION LINE. r,(_ NOTE: MINIMUM ACCUMULATOR PRECHARGE PRESSURE IS 565 PSIG. LOCATION_Q 14 15 16 17 18 20 21 22 23 2 25 26 27 FLOW, GPM -0 155 0.92 SEE SEE I 0 0 0 0 0.92 0.92 NOTE 9 NOTE 9 0.1 0

       ~

PRESSU11£ PSIG 988 76 76 PR SS MAX 65 MA)( 65 MAX

       ~

-** SEE NOTE 10

       ~* ...

11 I-ti f. i~

     .Is Control Rod Drive System (Process Diagram)

F= Columbia Generating Station r:*.

          ~

Final Safety Analysis Report I Rev. I Rgure

      .* -:I Draw. No. 02Cl2-04,26,1                 1           4.6-6.2 Form No. 960680

                 . . -*-1
- J___ _ _ _-2~:..'.l::"~=*~~---'----------__._

I 2 I_ _ ___.~__,___...__ I ii 3 I _ __,,I_ _ __ _ 4 _ _ _ ___.I_________ s I I 1J 6......I_ _ _ _I,_________ __...___......___....._ 7 _ Amendment 63 December 2015 TABLE I NOTES: A 18--1 2---6 6--9 78-7C . I. DEftNITION Of SYMBOLS 7. MAXIMUM ALLOWABLE PUMP SUCTION PRESSURE SHALL BE 50 PSIG. LOCATION IA-I8 '3A-::'3B 7A-7B PR -

• INDICATES PRESSURE Of THE REACTOR

8. PROCESS DIAGRAM CJZJD'" SHALL BE USED WITH AND fORIA PART Of DESIGN PRESS. 1750 1750 1750 1750 2. MAXIMUM OPERATING TEMPERATURES THIS PROCESS DATli. If THERE ARE ANY ~CONfLICTS BETWEEN THE 150 150 l 750 . - PROCESS DIAGRAM AND THIS PROCESS DATA, THE PROCESS DATA CPSIG.J

                                                                                                                                           - THE MAXIMUM SYSTEM OPERATING TEMPERATURE WILL NOT EXCEED 150 DEG . f.                SHALL GOVERN.
-           DESIGN TEMP .                                                                                                                    FROM LOCATION I THROUGH 27 W!Tf.l THE FOLLOWING EXCEPTIONS.

(DEG Fl 150 150 150 150 150 .150 150 *9-. DURING SCRAM, THIS fLOW WILL BE DIRECTED INTO THE SCRAM DIS-LOCATION MAXIMUM TEMP. IOEG. f.l CHARGE VOLUME. f"OLLOWING SCRAM, THIS FLOW WILL DECLINE AS MOOE A - 23 200 V*ALVE rooz CLOSES ANO AS THE SCRAM DISCHARGE VOLUME PRES-ESTIMATED LINE SURIZES TO EQUAL THE REACTOR PRESSURE. AFTER THE SCRAM DIS-SIZE CINCHES) 4 .4 2 I 1.5 I 0.75 MOOE A - . 23. 546 CHARGE VOLUME AND THE REACTOR VESSEL PRESSURE HAVE EQUAL-

                                                                                                                              -              MOOE    A-/ LEAklNG SCRAMJ24                                  ~                      IZED, FLOW WILL BE DIVERTED TO THE REACTOR VESSEL VIA THE B                                                                              -                                                                  *,    \DISCHAIIGE VALVE 25                               !500                   CRD WITHDRAW LINES* AT A FLOW RATE DEPENDENT ON THE REACTOR

LOCATION 10-20 11-12 I58-I5C 15-158 I6-I6A 17-18 12-26 I 27 280 PRESSURE: .

MOOE O - 23 ,475 *I.E. IA.I APPROX. 15 GPM AT "0" PSIG. REACTOR PRESSURE.

                                                                                                                                                                                                           ,475                 -          IB.I APPROX. 6 GPM AT "tOOO" PSIG. REACTOR PRESSURE.

DESIGN PRESS. 1750 1750 1750 1750 1750 1750 1750 24 25 475 10. THIS VALUE APPLIES IMMEDIATELY FOLLOWING COMPLETION or SCRAM. (PSIG.J

                                                                                                                                                                               . 27                        4~8                    PRESSURE WILL SUBSEQUENT LY EQUALIZE WITH REACTOR PRESSURE.

DESIGN TEMP .

..:...         (DEG Fl                 150          150          150                   150         150           150           150      3. MOOE A -

11. DESIGN PRESSURE ANO TEMPERATURE SHOWN IN "TABLE I" IS FOR A. MAXIMUM CHARGING WATER PR£SSURE SHALL BE

• 1600 PSIG NOMINAL. INFORMATION ONL y . ANO IS THE BASIS fOR DESIGN Of BWRS SUP-

         .ESTIMATED LINE                                                                                                                           ACCUMUtATOR             PRECHARGE PRESSURE SHALL BE

• 575 PSlG NOMINAL . PLIED EQUIPMENT. ESTIMATED LINE SIZES ARE FOR INFORMATION SIZE CINCHES) 2** I 0.75 I 2 I I ONLY. ACTUAL LINE SIZES AS DETERMINED BY THE PIPING DESIGNER 5 80 PSI G MAXIMUM, AT 70° F .

                                                                                                                               -               8 . DELETED                   .                                                    SHALL MEET THE PROCESS DATA HYDRAULIC REQUIREMENTS.

LOCATION 24-25 27A-27B 278-27 27-27C C. LOCATION 20 - THE CRO COOLING WATER PRESSURE SHALL BE. UITTRMINEi:> 12. ALL VALUES SHOWN IN MODES A, B, C, l'INO DARE NOMINAL UNLESS-21-22 27C-27D SA BY THE COOLI NG WATER FLOW . OTHERWISE NOTED. C "SEH/OTE 13" "SEENOTE13" "SEE ""10TEI3"

• c;~i:: unrE 13' "SEE t.lOTE 14 * '"SEE IJOTE 14" O. LOCATION 23 - MAXIMUM DRIVE COOUNG REQUIREMENTS WILL NOT EXCEED 13. INSERT AND WITHDRAWAL PIPING SHALL BE DESIGNED FOR DESIGN PRESS. 1750 1750 1250 1250 1250 1250 1750 0.34 GPM/ORIVE FOR THE CONDITIONS LISTED. MINIMUM DRIVE COOLING HY.DRCDYNAMIC LOADS A':. A RESULT OF A NORMAL SCRAM AT CPSIG.) REQUIREMENTS WILL NOT BE LESS THAN 0.20 GPM/ORIVE. ZERO!. fJORMAL REACTOR PRESSURE.'i:. SHORT STROKE A ND DESIGN TEMP.

(DEG Fl 150 ~ ~~ (PEAK)

                                                                                     -4&08         ..eo8        ,4608           150     4. MOOE B -

FULL STROKE SC.RAM AND A SCRAM WITI-I FAILED CRD BUFFER . PLANT LOAD COMBINATIONS SI-IOULD INCLUDE CONSIDERAT/01'1 OF (~ (PEAi() (PEAK) PEAK)

-         ESTIMATED LINE                I          0 .75        0.75

• 10 *2 .75 A. LOCATION 13 AND 14 - INSERT VALVE F007-A CLOSES ON DRIVE INSERT SIGNAL. WITHDRAW VALVE F007-B CLOSES ON DRIVE WITHDRAW SIGNAL THOSE SYSTEM HYDRODYNAMIC LOADS .

SI ZE CINCHES) BUT DOES NOT STAY CLOSED DURING SETTLING. 14 THE SCRAM DISCHARGE VOLUME (SDV) MJD ITS VBIT AND DRAIN PIPING DESIGI-J SHAL L CONS.IDE.R THE HYDRODYNAMIC. L OADS B. LOCATION 18

• THE CRO DRIVE WATER PRESSURE SHALL .NOT BE LESS THAN WHICI-I MAY OCCUR DUE TO I )SDV ISOLATION AND 2) SDV VENTING

-

• SEE CRO SYSTEM DESIGN SPECIFICATION.

uc, o, TaE TOTAL OOA,T,TY o, ,a,*s. ~ PR

• 250 PSIG. FOR THE CONDITIONS INDICATED. AND DRAll-JING FOLLOWING. A SCRAM COMPLETION AT REACTOR OPERATING PRESSURE .

(,**'

           ** 2 '""' "'ADER TO                 "Al' MOMENTARY TE MPERATUR E THAT OCCU RS AT 65 PSIG. REFER TO SPEC 1 FOR MAXIMUM DESIGN PRESS URE AND TEMPERATURE.

5. MOOE C -

A.DELETED D

-         ~'--"~"-.__/~~                                                                                                                       B. THE TEMPERATUMS LISTED IN NOTE 2 FOR POSITION 24, 25 >><<l 27 MAY BE ASSUMED TO OCCUit LESS THAN I ftERC£NT OF THE OPERATING LIFE 01" THE SYSTEM . SEE THE CRO HYDRAULIC SYSTEM DESIGN SPECIFICATION TO DETERMINE CYCLIC STRESS OUE TO THERMAL EXPANSION.

C. LOCATION 21 TO 22 - THE PRESSURE DROP FROM LOCATION 21 TO 22 SHALL NOT EXCEED 435 PSI AT 90 GPM FOR ANY CRO. D. LOCATION 2'3 - A NEGATIVE FLOW RATE INDICATES FLOW FROM THE REACTOR THROUGH THE DRIVE SEAL. INTO THE CRD. THE MAXIMUM LEAK RATE FROM THE E THE REACTOR CAN REACH 10 GPM PER DRIVE. E. LOCATION 24 TO 25 - THE PRESSURE DROP FROM LOCATION Z~ TO 2~ SHALL NOT EXCEED 162 PSI AT '30 GPM FOR ANY CRD. F. RESPONSE TIME Of FCV-F002 IS SUCH THAT SCRAM IS COMPLETED BEFORE FCV-F002 STARTS TO CLOSE. G. SCRAM DRAIN VALVE FOIi ANO VENT VALVE FOIO CLOSE WITH A SCRAM SIGNAL

6. MODE D -

A. DELETED B. LOCATION 27 - THE SCRAM DISCHARGE VOLUME SHALL BE SliEO SO THAT

                                                                                                                                                . THE RESULTING PRESSURE AFTER JOO PERCENT STROKE IS LESS THAN 65 PSIG* .

F FSAR FIG. Control Rod Drive System (Process Diagram) Columbia Generating Station Final Safety Analysis Report Draw. No. 02C12-04,26,2 I Rev. 3 I Figure 4.6-6.3 Form No. 960690ai

Amendment 53 November 1998 Isolation Valve Charging Water Riser Scram Valve Pilot Air Isolation Valve Isolation Valve Exhaust Water Riser Withdrawal Riser Isolation Valve Isolation Valve Drive Water Riser Insert Riser Scram Pilot Valve Assembly Isolation Valve Cooling Water Riser Junction Box Isolation Valve Scram Discharge Riser Wiring Trough Assembly Outlet Scram Valve Unit Interconnecting Inlet Scram Valve Cable Directional Control Valve (Withdraw) Directional Control Valve (Insert) Directional Control Manifold Valve (Insert) Directional Control Valve (Withdraw and Settle) Shutoff Valve Water Accumulation Drain Scram Accumulation N2 Cylinder Scram Water Accumulator Accumulator N2 Pressure Indicator Frame Cartridge Valve Accumulator N2 Charging Accumulator Instrumentation Assembly Control Rod Drive Hydraulic Control Unit Columbia Generating Station Final Safety Analysis Report Draw. No. 900547.25 Rev. Figure 4.6-7 Form No. 960690

Amendment 53 November 1998 Bracket Steel Form Liner Disc Springs Beams CRD Housing Reactor Vessel Support Pedestal Grid Plates Hanger Rod Grid Bolt CRD Flange Support Bar Grid Clamp Washer Jam Nut Nut Control Rod Drive Housing Support Columbia Generating Station Final Safety Analysis Report Draw. No. 900547.26 Rev. Figure 4.6-8 Form No. 960690

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS TABLE OF CONTENTS Section Page 5.1

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 CODES 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 Generation Design Bases ................................................. 5.2-2 5.2.2.1.3 Discussion............................................................................ 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 Evaluation of Results............................................................... 5.2-5 5.2.2.2.3.1 Safety Valve Capacity ........................................................... 5.2-5 5.2.2.2.3.2 Pressure Drop in Inlet and Discharge......................................... 5.2-6 5.2.2.2.3.3 Reload Specific 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 Description ........................................................................... 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 5-i

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 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 Chemistry of Reactor 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 Construction 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 Pressure Vessel ........................................................... 5.2-23 5.2.4.2.2 Piping, Pumps, 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 Inspection 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 Preservice Examination .......................................................... 5.2-27 5.2.4.10.2 Inservice Examination ............................................................ 5.2-27 5.2.4.11 Augmented Inservice Inspection 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 LDCN-02-046 5-ii

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 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 Expected 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 VESSEL 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, Cooldown, 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 LDCN-02-046, 04-033 5-iii

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 5.3.2 PRESSURE-TEMPERATURE 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 Description ........................................................................... 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 Protection of Closure Studs..................................................... 5.3-10 5.3.3.1.2 Safety Design Bases ................................................................ 5.3-11 5.3.3.1.3 Power Generation Design Basis .................................................. 5.3-11 5.3.3.1.4 Reactor Vessel 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 Control Rod Drive Return Line ............................................. 5.3-12 5.3.3.1.4.3 In-Core Neutron 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 Materials of Construction ............................................................ 5.3-14 5.3.3.3 Fabrication 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 RECIRCULATION PUMPS ........................................... 5.4-1 5.4.1.1 Safety Design Bases................................................................... 5.4-1 5.4.1.2 Power Generation 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 LDCN-04-033 5-iv

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 5.4.2 STEAM GENERATORS (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 Safety 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 Safety 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 ISOLATION 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 Component 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 Reliability Considerations ............................................... 5.4-27 5.4.6.2.5 System Operation ................................................................... 5.4-28 5.4.6.2.5.1 Automatic Operation............................................................. 5.4-28 5.4.6.2.5.2 Test Loop Operation ............................................................. 5.4-29 5.4.6.2.5.3 Steam Condensing (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 Preoperational Testing................................................................ 5.4-30 5.4.6.5 Safety Interfaces ....................................................................... 5.4-30 LDCN-00-056, 01-009, 01-025 5-v

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 5.4.7 RESIDUAL HEAT REMOVAL SYSTEM ......................................... 5.4-30 5.4.7.1 Design Bases ........................................................................... 5.4-30 5.4.7.1.1 Functional Design Basis ........................................................... 5.4-31 5.4.7.1.2 Design Basis for Isolation of Residual Heat Removal System from Reactor Coolant System ........................................................... 5.4-33 5.4.7.1.3 Design Basis for Pressure 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 Protection 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 Component Description ........................................ 5.4-38 5.4.7.2.3 Controls and 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 Limiting Failure ............................... 5.4-42 5.4.7.4 Preoperational 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 Generation 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 Demineralizer Resins ................................................................. 5.4-46 5.4.8.5 Reactor Water Cleanup Water Chemistry......................................... 5.4-46 5.4.8.5.1 Analytical 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 Safety Design Bases................................................................... 5.4-47 5.4.9.2 Power Generation 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 LDCN-04-027 5-vi

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 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 CORE 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 LDCN-01-009, 01-025 5-vii

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 5.2-1 Exceptions to Conformance to 10 CFR 50.55a Reactor Coolant Pressure Boundary Components 5.2-37 5.2-2 Reactor Coolant Pressure Boundary Component Code Case Interpretations 5.2-38 5.2-3 Nuclear System Safety/Relief Setpoints 5.2-39 5.2-4 Systems Which May Initiate 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 Test Pressure for RCPB Components 5.2-42 5.2-7 Reactor Coolant Pressure Boundary Materials 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 Valves 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 LDCN-02-000 5-viii

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 5.3-3 Weld Material Cross Reference .............................................. 5.3-24 5.3-4 Plate Material.................................................................... 5.3-25 5.3-5 Weld Material ................................................................... 5.3-26 5.3-6 Vessel Beltline Plate............................................................ 5.3-29 5.3-7 Vessel Beltline Weld Material Chemistry .................................. 5.3-30 5.3-8 10 CFR 50 Appendix H Matrix .............................................. 5.3-31 5.3-9 Reactor Vessel Beltline Minimum Wall Thickness and Diameter ...... 5.3-33 5.4-1 Reactor Coolant Pressure 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 Ingersoll-Rand Emergency Core Cooling Systems Pumps ........................................................ 5.4-60 5.4-4 Operating Experience of Similar 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 LDCN-04-033 5-ix

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS LIST OF FIGURES Number Title 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 - Curves 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 LDCN-15-011 5-x

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 5.3-4 Bracket for Holding 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 5-xi

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS LIST OF FIGURES (Continued) Number Title 5.4-15 Residual Heat Removal System - 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 Removal (LPCI) Pump Characteristics (S/N 0473-111) P-2A 5.4-19 Residual Heat Removal (LPCI) Pump Characteristics (S/N 0801MP004399-1) P-2B 5.4-20 Residual Heat Removal (LPCI) Pump Characteristics (S/N 0473112) P-2C 5.4-21 Vessel Coolant Temperature 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/Demineralization System P&ID 5.4-25 Vessel Coolant Temperature Versus Time (One Heat Exchanger Available) LDCN-16-004 5-xii

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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-containing appendages out to and 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 isolation 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 does not penetrate primary reactor containment, and

3. The reactor coolant system safety/relief valves.

Section 5.4 discusses the various subsystems to the RCPB. The nuclear system pressure relief system protects the reactor coolant pressure boundary from damage due to overpressure. To protect against overpressure, pressure-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 depressurize 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 cooling water to adequately cool the fuel. Section 5.2.5 establishes the limits on nuclear system leakage inside the drywell so that appropriate action can be taken before the integrity of the nuclear system process barrier is impaired. 5.1-1

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 The reactor vessel and appurtenances 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 loading 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 established that avoid conditions where brittle fracture is possible. The reactor recirculation system provides coolant 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 recirculation system routing is such that a piping failure cannot compromise the integrity of the 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 are designed to limit the loss-of-coolant resulting from a main steam line break outside 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 the 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 line 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 pump 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 condenser) is not available (e.g., hot standby). One mode of RHR operation allows the removal of heat from the primary containment following a LOCA. Another operational mode of the RHR system is 5.1-2

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 low-pressure coolant injection (LPCI). The LPCI operation is an engineered safety feature for use during a postulated LOCA. This operation is described in Section 6.3. The low-pressure core spray (LPCS) system also provides 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 dissolved impurities from the reactor coolant. It also removes excess coolant from the reactor system under controlled conditions. 5.1.1 SCHEMATIC FLOW DIAGRAM Schematic flow diagrams of the reactor coolant system denoting all major components, principal pressures, temperatures, 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 INSTRUMENTATION 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 dimensions of the reactor and coolant system in relation to the containment is shown in Figures 1.2-11 and 1.2-12. LDCN-05-009 5.1-3

Amendment 64 December 2017 3 Steam Dryers Main Steam Flow Turbine Steam Separators

                                                                                                                       *4 5          Main Feed Flow Driving Flow 2

Jet Pump Note 1 Core FCV FCV Note 1 Note 1 Recirculation 1 6 7 Pump PRESSURE FLOW TEMP. ENTHALPY (psia) (lb/hr) (°F) (Btu/lb)

1. Core Inlet 1069 # 108.5 x 10 6* 534 # 528.5

2. Core Outlet 1047 # 108.5 x 10 6 550 # 639.9 #

3. Separator Outlet (Steam Dome) 1035 15.28 x 10 6 549 # 1191.0

4. Steam Line (2nd Isolation Valve) 999 15.28 x 10 6 545 # 1191.0

5. Feedwater Inlet (Includes RWCU Return Flow) 1063 # 15.4 x 10 6 422 399.7

6. Recirculating Pump Suction 1037 # 32 x 10 6 # 534 # 528.4 #

7. Recirculating Pump Discharge 1327 # 32 x 10 6 # 534.4 529.5

• Channel Bypass - Nominally 10%

Note 1: The FCVs are kept in mechanically blocked full open position. Note 2: These values identified by # are based upon 3486 MWt and were dispositioned as having insignificant change from or effect to the operating conditions for 3544 MWt. Rated Operating Conditions of the Columbia Generating Station Boiling Water Reactor Final Safety Analysis Report Draw. No. 900547.44 Rev. Figure 5.1-1 Form No. 960690 LDCN-16-005

Amendment 53 November 1998 D Steam Dryers Main Steam Flow Turbine Steam Separators C E Main Feed Flow F Driving Flow Jet Pump Note 1 Core B FCV FCV Note 1 Recirculation Pump

• A Note 1 Volume of Fluid (ft3)

A. Lower Plenum 4010 B. Core 1990 C. Upper Plenum and Separators 2290 D. Dome (Above Normal Water Level) 7160 E. Downcomer Region 5210 F. Recirculating Loops and Jet Pumps 1010 Note1: The FCVs are kept in mechanically blocked full open position. Coolant Volumes of the Boiling Water Reactor Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.04 Rev. Figure 5.1-2 Form No. 960690

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 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 Codes 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 the components were ordered as shown in the table. The code edition and applicable addenda that would be required by strict interpretation of the rules set forth in 10 CFR 50.55a are identified in Table 5.2-1. Application for Columbia Generating Station (CGS) was filed with the Commission in August 1971. At that time a construction permit 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 March 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 the award of a construction permit to meet construction schedules. Had the construction permit been issued 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 applied was one addenda earlier (6 months) than the code version required 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 changes in quality control procedures from the code version applied in the procurement of the components. The 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 components, which had all been shipped to the construction site, would not have provided a compensating increase in the level of safety and quality. 5.2.1.2 Applicable Code Cases The reactor pressure vessel (RPV) and appurtenances and the RCPB piping, pumps and valves, were designed, fabricated, and tested in accordance with the applicable edition of the ASME LDCN-99-000 5.2-1

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 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 Regulatory 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 code cases that are adopted for use, as approved by Regulatory Guides 1.147, 1.84, 1.85, or specifically approved by the Regulatory Authority for use at CGS, are specified in the components 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-relief system is designed to

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

b. Provide automatic depressurization 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 loadings and forces resulting from operation during abnormal, accident, or special event conditions.

5.2.2.1.2 Power Generation Design Bases The nuclear pressure relief system safety/relief valves (SRV) have been designed to meet the following power generation bases:

a. Discharge to the containment suppression pool, and 5.2-2

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 t b. 5.2.2.1.3 Correctly reclose following operation so that maximum operational continuity can be obtained. Discussion I 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 pressure of 110% of design pressure under upset conditions. 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 specifications for safety valves because all valves open at less than the nuclear system design pressure of 1250 psig. The automatic depressurization capability of the nuclear 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 nameplate capacity credit for overpressure protection function, and

c. Must meet other performance requirements 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 adequate to limit the primary system pressure, including transients, to the requirements of the ASME B&PV Code, Section III, 1971 Edition through the Summer 1971 Addenda. Table 5.2-4 lists the systems which could initiate during the safety valve capacity overpressure event. LDCN-98-113 5.2-3

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 characteristics 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, recirculation flow, reactor water level, pressure, and load demand. These are presented with all their principal nonlinear features in models that have evolved through extensive experience and favorable comparison of analysis with actual boiling water reactor (BWR) test data. A detailed description of the models is documented in licensing topical reports, References 5.2-1 and 5.2-7. Safety/relief valves are simulated in the nonlinear representation, 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 characteristics, and anticipated transients without scram (ATWS) pump trip are also represented fully in the models. 5.2.2.2.2 System Design The overpressure protection system must accommodate the most severe pressurization transient. There are two major transients, the closure of all 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 plant configuration has shown that the isolation valve closure is slightly more severe when credit is taken only 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 various systems assumed to operate during the main steam line isolation closure with flux scram event. Compliance to ASME Code overpressure protection requirements for introduction of GNF2 fuel has been conservatively demonstrated for the limiting overpressure event. The GE thermal-hydraulic and nuclear coupled transient code TRACG (References 5.2-7 and 5.2-8) was used to obtain system response and peak vessel pressure. The setpoints are listed in Table 5.2-3. The evaluation, based on reactor operation at 100% of uprated power, end-of-cycle nuclear dynamic parameters, an initial dome pressure of 1035 psia (nominal uprated dome LDCN-15-011 5.2-4

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 pressure), six SRVs with lowest safety setpoints out of service, and SRV opening pressures at 3% above nominal setpoint values resulted in a maximum reactor pressure 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 Capacity. The required SRV capacity is determined by analyzing the pressure rise from an MSIV closure with flux scram transient. The plant is assumed to be operating at the turbine-generator 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 neutron flux scram. For the analysis, the spring-action safety valve setpoints used are in the range of 1236 to 1256 psia. The TRACG analysis indicates that the design valve capacity is capable of maintaining adequate margin below the peak ASME Code allowable pressure in the nuclear system (1375 psig). Figure 5.2-2 shows the result of the TRACG analysis. The sequence 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 determining 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 could 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 safety function. This ensures sufficient margin between anticipated relief mode closing pressures 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 failure in the redundant direct scram system. The typical time response of the vessel pressure to the MSIV transient 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 does not reach the limit of 1375 psig. LDCN-15-011 5.2-5

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 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 calculating the maximum vessel pressures. Pressure drop in the discharge piping to the suppression pool is limited by proper discharge line sizing to prevent back-pressure on each SRV from exceeding 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 demonstrated by cycle-dependent analysis just prior to the operation of that cycle. The results are reported in Supplemental 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 isolation 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 expected 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 generated heat drops into the decay heat characteristics. The pressure increase and relief cycle 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 dissipate this heat. The duration of each relief discharge should, in most cases, be less than 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 life and reducing challenges to the SRV. A schematic of the main SRV is shown in Figure 5.2-8. It is opened by either of two modes of operation: l l

a. The spring mode of operation which consists of direct action of the steam pressure against a spring-loaded disk that will pop open when the valve inlet LDCN-10-029 5.2-6

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 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 I

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 arranged 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 open 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 affecting the spring lift setpoint, each valve is provided with a bellows and balancing piston to counteract the effects of any static backpressure which may be present in the discharge line before the valve is opened to discharge steam. The bellows isolates steam in the valve discharge chamber from the valves internals. If the bellows fails, the balancing piston serves as a functional backup by presenting an effective piston 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 designed and constructed in accordance 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. I The pneumatic accumulator has sufficient capacity to provide one SRV actuation at approximately 1000 psig valve inlet pressure. IAlthough no credit is taken under ASME Code Section III for overpressure protection 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 pressure switches (one per valve) which sense reactor steam space pressure at lower values than the spring mode inlet steam opening pressure. The pressure switches initiate the opening of the SRVs by energizing the pneumatic solenoids (one per valve) at the relief setpoints designated in Table 5.2-3. l l 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 5.2-7

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 t0.1 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 the power-actuated mode by remote-manual controls from the I main control room. The SRVs are designed to operate to the extent required for overpressure 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 period, at 25 psig drywell pressure, and

d. 200°F during the next 99 days at 20 psig drywell pressure.

The automatic depressurization system (ADS) utilizes selected SRVs for depressurization of the reactor (see Section 6.3). Each of the SRVs utilized for automatic depressurization is equipped with an air accumulator and check valve arrangement. These accumulators ensure that the valves can be held open following failure of the air supply to the accumulators. I 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. I For a discussion of the noninterruptible air supply to the ADS valves, see Section 9.3.1. I Three ADS SRVs and their associated solenoid pilot valves (SPV) are qualified for the full post-LOCA time frame for long-term cooling. 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 classified 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 Category 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: LDCN-98-113 5.2-8

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000

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 with negligible vibration observed. The SRV discharge piping is designed to limit valve 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 excessive pressure at the valve discharge when the valve is again opened. I For this reason, redundant 10-in. vacuum relief valves 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 termination 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 system 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 Design Parameters Table 5.2-6 lists design temperature, pressure, and maximum test pressure for the RCPB components. The specified operating 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 appropriate design condition (i.e., normal, upset, emergency, and faulted). The design requirements established to protect the principal components of the reactor coolant system against environmental effects 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 valve inlet and outlet are 1250 psig at 575°F and 625 psig at 500°F, respectively. 5.2-9

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 The valves have been designed to achieve the maximum practical number of actuations consistent with state-of-the-art technology. Cyclic testing has demonstrated that the valves are capable of at least 60 actuation cycles 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 thrust, bending, and torsional 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 any 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 Codes 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 general 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 systems of the nuclear reactor. Hence, credit is taken for the scram protective system as a complementary 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 instrumentation 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 principally a function of the SRVs in their spring-opening mode of operation. No credit is taken in the ASME Code Section III required overpressure protection report for power actuation of the SRVs to provide protection against overpressure. 5.2-10

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 Section 5.2.2.10 discusses the inspection and testing conducted to ensure high 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 accumulated on this type of SRV, approximately 150 individual valve years, only one stuck-open relief valve had occurred. This was due to an air solenoid valve sticking open after it was deenergized, thus holding the SRV open in the power-actuated mode. Proper maintenance procedures are incorporated into the instruction manual to preclude recurrence. This type of SRV has demonstrated good inservice 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 actual 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 demonstrated the design of the valve is capable of performing its overpressure protection function under normal, upset, emergency, and faulted conditions and its designated mechanical motion(s) to fulfill its safety function to shut down the plant or mitigate the consequence of a postulated event. To ensure that valves to be installed are operable, each valve is manufactured, inspected, and production tested in accordance with quality control procedures to verify compliance with both ASME Code and operability assurance acceptance criteria. The SRV design used at CGS successfully completed the following qualification tests:

a. Life Cycle Test Following the prequalification production tests, each modified SRV was then subjected to life cycle qualification tests with saturated steam conditions, in accordance with GE specification 22A6595. This included approximately 300 relief (power) and safety (pressure) actuations to demonstrate and characterize each valve for acceptable BWR service. Tests parameters included:

1. Seat tightness/leakage characteristics, LDCN-99-000 5.2-11

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000

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 may be subjected while in service. These included temperature, pressure ramp rates, pneumatic operating pressure, solenoid voltage, inlet pressure, and the dynamically imposed backpressure. Test results indicate essentially zero leakage for both the relief (power) and safety (pressure) modes of SRV operation. All valves demonstrated seat-tightness capability to meet the 20 lb/hr specification limit under saturated steam conditions. Each valve demonstrated 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 lower than the nameplate value. The temperature correction value is 0.2 psi/°F for this SRV. Set pressure is independent of ramp rate variance. Response of the SRV is directly related to the effective differential pressure force acting to open the SRV; therefore, outlet static pressure at the exit can be accurately accounted for. Opening times were as follows 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, controlled by blowdown requirement. 5.2-12

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 Relief actuation - time to deenergize solenoid < 0.90 sec disc travel after solenoid < 1.50 sec was deenergized Blowdown within the required range of 2% to 11% was 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 throughout the qualification 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 will open to its full rated capacity lift position when operated in the relief mode with the inlet pressure at zero psig, thus demonstrating its emergency operability capability. Six SRVs were included in this life cycle qualification test program. Test anomalies corrected during this demonstration do not invalidate 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 flanged end connection moment loading with valve inlet pressurized with saturated steam. Valve operability was demonstrated during and after application of loading. Maximum test loads were 8 x 105 in. pound moment at valve inlet and 6 x 105 in. pound moment at valve outlet. Seismic accelerations of 5.0g horizontal and 4.2g vertical are the established maximum for any frequency between 5 to 200 Hz unless otherwise specified for a smaller frequency range.

c. Emergency Environmental Qualification Test The solenoid valves and the pneumatic actuator 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 106 rads, 5.2-13

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000

3. Mechanical aging for 1000 cycles (500 per solenoid),

4. Seismic testing as described 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 actuator assembly was demonstrated 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 requirements of II.D.1 of NUREG-0737.

Test reports/records of the above qualification tests are available for inspection. Each SRV is production tested at the vendor's shop to ensure, by demonstration, each SRV manufactured will reliably perform its required function(s). The SRV production test consist of

a. Inlet and outlet hydrostatic tests at specified 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 relief opening and closing times under thermally stabilized and saturated steam conditions, and 5.2-14

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000

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 valve manufacturer that design and performance requirements have been met. Testing to satisfy the ASME Code requirements is normally performed in situ. Testing can be performed locally or remotely. The local test method is conducted 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 that is controlled by a remote computer. This method does not require any personnel 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 transportation, storage, and installation, and were properly maintained as to cleanliness prior to performance of any tests. In addition, the air accumulator capacity, SRV nameplate set pressure, and capacity were compared with the system design documentation for compliance. Actual mechanical tests included an operability check of the 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, smooth 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 performance. 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 startup test program, each SRV was manually actuated at approximately 250 psig 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 discharge 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 readiness of the SRVs. This code section is applied to both ADS and non-ADS valves alike. Supplemental tests of the ADS 5.2-15

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 valves each operating cycle are required by the Technical Specifications. Applying Section XI, the SRV test schedule (in 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 the testing SRVs, an operability demonstration will be performed in compliance with Section XI, Article IWV-3200. This combination of the startup test program, Technical Specifications surveillance, and inservice inspection testing satisfies industry standards for SRV operability demonstrations. Energy Northwest participated in the BWR Owners Group for TMI concerns on SRV reliability. The final test program 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 Reactor 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. LDCN-99-000 5.2-16

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 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 stainless 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 concentrations. Conductivity is limited because it can be continuously and reliably measured and gives an indication of abnormal conditions and the presence of unusual materials in the coolant. Chloride limits are specified to prevent stress corrosion cracking of stainless steel. For further information, see Reference 5.2-2. Periodically an On-Line NobleChem application will be performed to create a catalytic layering of the noble metal platinum to reduce the hydrogen injection rate required to achieve a low electrochemical corrosion potential (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 range. When conductivity becomes abnormal, chloride measurements are made to determine whether or not they are also out of their normal operating values. Conductivity 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 conductivity 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 and where near neutral pH is maintained, conductivity 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 remedy the condition before reactor water limits are reached. Methods available to the operator for correcting the off-standard condition include operation of the reactor cleanup system, 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-dependent 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 radiolytic formation (principally) rates, corresponds to a nominal value of approximately 200 ppb (0.2 ppm) of oxygen at rated operating conditions. Slight variations around this value have been observed as a result of differences in neutron flux density, core-flow, and recirculation flow rate. LDCN-10-010 5.2-17

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 A reactor water cleanup (RWCU) system is provided for removal of feedwater input impurities plus corrosion and fission products originating from primary system components. The cleanup process consists of filtration and ion exchange and serves to maintain a high level of water purity in the reactor coolant. Additional water input to the reactor vessel originates from the control rod drive (CRD) cooling water. The CRD water is of feedwater quality. Additional filtration 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 iron 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 flow 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 oxygen 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 operation, additional inputs and mechanisms are present as reactor coolant water could contain up to 8 ppm dissolved oxygen. Conductivity of the primary coolant is continuously 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. IThese measurements provide reasonable surveillance of the reactor coolant. Grab sample points are provided at the locations shown in Table 5.2-8, for special measurements such as pH, oxygen, chloride, and radiochemical content. The relationship of chloride concentration to specific conductance 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 feedwater system. Thus, a total plant water quality surveillance program is established providing assurance that off specification conditions will quickly be detected and corrected. LDCN-02-046, 03-069 5.2-18

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 The sampling frequency established for primary coolant at normal conductivity levels is adequate for instrument checks and routine audit purposes. I When specific conductance increases and higher chloride concentrations 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 sample conditioning and flow control equipment. Water Purity During a Condensate Leakage Due to improved water quality limits, any appreciable 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 coolant consist of the following:

a. Solution annealed austenitic stainless steels (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 martensitic stainless steel (all tempered at a minimum of 1100°F), and

e. Cobalt, chromium, nickel, and iron based alloy hardfacing material All of these materials of construction 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 controlled to very low limits by the reactor water quality specifications. No detrimental 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 construction materials. LDCN-10-023 5.2-19

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 The recirculation system piping and normally flooded sections 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 metal surface when an amount of hydrogen 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 CRD hydraulic return line were eliminated and nozzles capped. The core spray lines are fabricated 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 Construction Materials with External Insulation and Reactor Coolant The materials of construction 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 insulation used does not contribute to any surface contamination and has no effect on construction materials. The fibrous insulation used meets the requirements of Regulatory Guide 1.36. DZO and iron are additives in the BWR coolant. Leakage would expose materials to high purity demineralized water, DZO, and iron. Exposure to demineralized water, DZO, and iron would cause no detrimental effects. 5.2.3.3 Fabrication and Processing of Ferritic Materials and Austenitic Stainless Steels Fracture toughness requirements for the ferritic materials 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 LDCN-10-010 5.2-20

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 boundary components only if required in the Design Specification. 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 design pressure. Material information pertaining to the MSIVs is contained in Table 5.2-11. Main steam piping was tested in accordance with and met the fracture toughness requirements of Paragraph NB-2300 of the 1972 Summer Addenda to ASME Code, Section III. The ferritic pressure boundary material of the RPV was qualified 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 ASME 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 conforming to the above requirements, the structural 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 performed in accordance with the requirements of 10 CFR 50.55a subparagraph (g) as described in the Inservice Inspection Program Plan. 5.2.4.1 System Boundary Subject to Inspection The system boundary subject to inspection 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 XI, including the Summer 1975 Addenda. All Class 1 piping, pumps, and valves were examined prior to service 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 inservice inspection system was completed prior to the promulgation of amendments to 10 CFR 50.55a which require the upgrading of the 5.2-21

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 utility's inservice inspection code commitment for examinations 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 piping examination to be upgraded to conform to the requirements of the Summer 1975 Addenda to Section 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 valves. 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 inservice inspection is defined as the design of the plant with the proper clearances for examination 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 provisions 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 volumetric examination of the pressure containing welds from the external surfaces of components and piping by means of removable 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 these inspections and, hence, reduces the amount of radiation exposure to both plant and examination personnel. Working platforms are provided at most strategic locations in the plant which permit ready access to those areas of the RCPB which are designated as inspection points in the inservice 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 compliance with code requirements. 5.2-22

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2.4.2.1 Reactor Pressure Vessel Access for inspection of the RPV is as follows:

a. Access to the exterior surface 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 surface and the insulation interior surface to permit the insertion of remotely operated inspection devices between the insulation and the reactor vessel. The 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. Examinations that can be performed from these tracks include the required coverage of the nozzle-to-shell welds and depending on technique, could provide examination coverage of the nozzle inner radius section and nozzle-to-safe-end weld. Access, geometry and radiation level considerations will determine those nozzles scheduled for manual examination.

b. The vessel flange area and vessel closure head can be examined during refueling outages using manual 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 separator assembly. Removal of these components also enables the examination of remaining internal components by remote visual techniques. The volumetric examination of the vessel-to-flange weld and closure head-to-flange weld can be performed 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 stored during refueling which facilitates direct manual examination. Removable insulation allows 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 refueling 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 dollar plate longitudinal welds, and visual examination of accessible penetration welds.

5.2-23

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2.4.2.2 Piping, Pumps, and Valves The physical arrangement of piping, pumps, and valves is designed to allow personnel access to welds requiring inservice inspection. Modifications to the initial plant design have been incorporated where practicable to provide inspection 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 those welds requiring inspection have been reviewed and modified where necessary to reduce the amount of plant support required in these areas during inspection. Working platforms are provided to facilitate servicing most of the pumps and valves. Temporary 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 minimize the number of fitting-to-fitting welds within the inspection boundary. Welds requiring inspection are located to permit ultrasonic examinations from at least one side, but where component geometries permit, access from 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 Techniques and Procedures Examination techniques and procedures 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 made 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 accomplished 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 examination 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 the equipment will be accomplished through the access openings in the sacrificial shield which are provided at each nozzle location. 5.2-24

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2.4.3.2 Coordination of Inspection Equipment With Access Provisions Access to areas of the plant requiring inservice inspection is provided to allow use of standard equipment wherever practicable. Design in general provides for free space envelopes both radially and axially from welds to be examined 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 ultrasonic 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 Inspection Program Plan. 5.2.4.4 Inspection Intervals Inspection intervals are defined in the Inservice Inspection Program Plan. 5.2.4.5 Examination Categories and Requirements Examination categories and requirements for the preservice inspection are defined in the Preservice Inspection Program Plan and closely follow 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 inservice 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 Edition 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 effective code by 10 CFR 50.55a, for the baseline examinations, only through the Summer 1975 Addenda. However, Energy Northwest also recognized that even though the code through Summer 1975 Addenda included evaluation criteria which could be interpreted to apply to piping (Category B-J) welds, the evaluation criteria found in the Winter 1975 Addenda clearly provides evaluation criteria which 5.2-25

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 are applicable to these welds. Energy Northwest was unaware that the NRC staff was opposed to these evaluation criteria and anticipates that the criteria which 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 hydrostatic test for the RPV was satisfied by the hydrostatic test performed in accordance with the requirements of ASME Section III. Similarly, the requirements for the baseline piping system leakage and hydrostatic tests were satisfied by reference to the Section III hydrostatic test report as permitted by ASME Section XI, IWA-5210(b). Subsequent hydrostatic and system leak tests are conducted 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 preoperational 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 Generating 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 Plan has been implemented for Columbia Generating Station, on high energy* Class 1 piping systems which 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 pressurized and where either the maximum operating pressure exceeds 275 psig or maximum operating 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 augmented inservice inspection. 5.2-26

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2.4.10 Augmented Inservice Inspection of Reactor Pressure Vessel Feedwater Nozzles 5.2.4.10.1 Preservice Examination Energy Northwest performed a preservice inspection ultrasonic examination of the RFW nozzle inner radii, bore, and safe end regions as described in the Preservice Inspection Program Plan. In addition, a preservice liquid penetrant examination was performed 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 Inspection 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 inspection requirements are described in the Inservice Inspection Program Plan. 5.2.4.12 ASME Section XI Repairs/Replacements The repair or modification of N-stamped components will be performed in accordance with the Edition and Addenda of ASME Section 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 referenced code edition and addenda as allowed by code will be reviewed by Energy Northwest and authorized on a case-by-case basis. 5.2-27

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 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 temperature, pressure, and flow sensors with associated instrumentation and alarms. This system detects, annunciates, 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 affected systems and the detection methods used are summarized in Table 5.2-12. Small leaks (5 gpm and less) are detected by temperature and pressure changes, drain sump pump activities, floor drain flow monitoring, and fission product monitoring. Large leaks are also detected by changes in reactor water level 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 discussed 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 leakage detection function. The table shows that those systems which detect gross leakage initiate immediate automatic 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 other appropriate action. 5.2.5.1.1 Detection of Abnormal Leakage Within the Primary Containment Leaks within the drywell are detected by monitoring for abnormally high-pressure and temperature within the drywell, high fillup rates of equipment and floor drain sumps, excessive temperature difference between the inlet and outlet cooling water 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 are monitored at various elevations. Also the temperature of the inlet and exit air to the atmosphere is monitored. Excessive temperatures in LDCN-11-005 5.2-28

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 H the drywell, increased drywell drain sump flow rate, and drywell high-pressure are annunciated by alarms in the control room. I Drywell high pressure and low reactor vessel water level will cause automatic primary containment isolation. IIn 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 systems are common. Each of the leakage detection systems inside the drywell is designed with a capability of detecting leakage 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 that leakage may be detected by area temperature indications. Each leakage detection system discussed in the following paragraphs is designed to detect leak rates that are less than those established by the Technical Specifications. The method used to monitor for leakage for each RCPB component is described in Table 5.2-12.

a. Ambient and differential room ventilation temperature A differential temperature sensing 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 equipment 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 indicated in the control room.

Spurious isolations of systems due to a relatively sharp drop in outside ambient temperature is highly unlikely. For example, the normal approximate operating differential temperature for the RHR and RCIC pump rooms is 26°F and 32°F respectively. The temperature elements are located 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 changes of this magnitude. 5.2-29

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005

b. Reactor building sump flow measurement Instrumentation monitors and indicates the amount of leakage 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 I

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 measurement (cleanup system only)

Because of the arrangement of the RWCU systems, differential flow measurement provides an accurate leakage detection method. I The flow from the reactor vessel is compared with 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 cooling 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 identified 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 details are given in Section 9.3.3.

c. Drywell air sampling The primary containment radiation monitoring system is used to supplement the temperature, pressure, and flow variation method described previously to detect 5.2-30

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 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 background radiation is established. Any sudden or unexplained increase in background radiation indicates 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. This provides diversity in leak detection.

d. Reactor vessel head closure The reactor vessel head closure is provided with double seals with a leak off connection between seals that is piped to the equipment drain sump. Leakage through the first seal is annunciated in the control room. I 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 the 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 SRV discharge piping several feet from the valve body. Temperature rise 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. 5.2-31

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 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, identified and unidentified, that flows to the drywell floor drain and equipment drain sumps. The total leakage rate limit 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 collect all leakage. The equipment sump is drained by one 50-gpm pump and the floor drain sump is drained by two 50-gpm pumps. The total leakage rate limit from inside containment is established at 25 gpm, which includes no more than 5 gpm unidentified leakage. The total leakage rate limit is low 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 the drywell are equipped with double seals. ILeakage from the primary recirculation pump seals is piped to the equipment drain sump. ILeakage in the discharge lines from the main steam SRVs is monitored by temperature sensors that transmit a signal to the control room. Any temperature increase above the drywell ambient temperature detected by these sensors indicates valve leakage. Thus, the leakage rates from pumps and the reactor vessel head seal are measurable during plant operation. These leakage rates, plus any other leakage rates measured 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 more 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. 5.2-32

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.2.5.5 Unidentified Leakage Inside the Drywell 5.2.5.5.1 Unidentified Leakage Rate The unidentified leakage rate is the portion of the total leakage rate received in the drywell sumps that is not identified as previously described. A threat of significant compromise to the nuclear system process barrier exists 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 integrity 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 could 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 temperature recorder, Reactor vessel water level, and Drywell atmosphere radiation monitors. While the indications listed above have no definitive correlation between their engineering units, they provide an early warning of a potential leak to the operator. 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 conducted by GE and Battelle Memorial Institute (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 realistic 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 greater than the 5-gpm criterion. 5.2-33

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 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 are normally open, there are at least two different methods of detecting abnormal leakage from each system within the nuclear system process barrier located 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 determined analytically or based on measurements of appropriate parameters made during startup and preoperational tests. Some alarm points require 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 established limit is sufficiently low so that, even if the entire unidentified leakage rate were coming from a single crack in the nuclear system process barrier, corrective action could be taken before the integrity of the barrier would be threatened with significant compromise. The leak detection system sensitivity and response time 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 interfaces 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-plant systems and equipment include the main steam line tunnel, the SRVs, and the turbine building sumps. 5.2.5.7 Testing and Calibration Provisions for testing and calibration of the leak detection system are described in Section 7.6. 5.

2.6 REFERENCES

5.2-1 Qualification of the One-Dimensional Core Transient Model (ODYN) for BWRs, NEDO-24154-A, Vol. 1 and 2, General Electric, August 1986. 5.2-2 J. M. Skarpelos and J. W. Bagg, Chloride Control in BWR Coolants, June 1973, NEDO-10899. LDCN-10-029, 11-005 5.2-34

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 5.2-3 W. L. Williams, Corrosion, 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 Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactor Plants, NUREG-76/067, NRC/PCSG, dated October 1975. 5.2-6 Washington Public Power Supply System, 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), 001N9271-R1, Revision 1, January 2015. 5.2-9 Letter GO2-85-110 from G. C. Sorenson, Supply System, to A. Schwencer, NRC,

Subject:

Nuclear Project No. 2, CPPR-93 Preservice Inspection Program Plan, Amendment No. 4, Summary 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 System, 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). LDCN-15-011 5.2-35

Table 5.2-1 Exceptions to Conformance to 10 CFR 50.55a Reactor Coolant Pressure Boundary Components Plant Code Applied Component Identification Purchase ASME Code Required by Component Description Quantity System Number Order Date Section III 10 CFR 50.55(a) Status COLUMBIA GENERATING STATION Main steam safety 18 MS-RV-1 A-D April 1971 1971 Edition 1971 Summer Addenda FSa relief valves MS-RV-2 A-D MS-RV-3 A-D MS-RV-4 A-D 5.2-37 MS-RV-5 B-C FINAL SAFETY ANALYSIS REPORT (B22-F013 A-V) Recirc pumps 2 RRC-P-1A April 1971 1971 Edition 1971 Summer Addenda FS (B35-C001) Recirc gate valves 4 RRC-V-23/ June 1971 1971 Edition 1971 Summer Addenda FS RRC-V-67 (B35-F023/F067) Recirc flow control 2 RRC-V-60 June 1971 1971 Edition 1971 Summer Addenda FS valve (B35-F060) Recirc piping 1 lot B35-G001 October 1971 1971 Summer 1971 Winter Addenda FS Amendment 56 Addenda December 2001 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 Case Interpretations Number Title Remarks

1. 1332 - Requirements for steel forgings Regulatory Guide 1.85, Revision 6 Revision 6

2. 1401 - Welding repairs to cladding of Class I, Revision 0 Section III, components after heat treating

3. 1420 - 5b-167 Ni-Cr-Fe alloy pipe or tube Revision 0

4. 1441 - Waiving of 3 Sm requirement for Revision 1 Section III construction

5. 1141 - Foreign produced steel Regulatory Guide 1.85, Revision 1 Revision 5

6. 1361 - Socket welds, Section III Regulatory Guide 1.84, Revision 2 Revision 9

7. 1525 Pipe descaled by means other than pickling, Section III

8. 1535 - Hydrostatic test of Class 1 nuclear valves, Regulatory Guide 1.84, Revision 2 Section III Revision 9

9. 1567 Testing lots of carbon and low alloy steel Regulatory Guide 1.85, covered electrodes, Section III Revision 6

10. 1621 - Internal and external valve items, Regulatory Guide 1.84, Revision 1 Section III, Class 1 Revision 12 (for 1621-2)

11. 1588 Electro-etching of Section III code Regulatory Guide 1.84, symbols Revision 9

12. 1820 Alternative ultrasonic examination Regulatory Guide 1.85, technique Section III, Division 1 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 5.2-38

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-3 Nuclear System Safety/Relief Setpoints Spring Set ASME Rate Capacity at Pressure Setpoint for the Number of Pressure 103% Spring Set Power Actuated Mode Valves (psig) Pressure (lb/hr each) (psig) 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 depressurization function. 5.2-39

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 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 settings L2 and L8 shown in Figure 5.3-3. 5.2-40

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 0 Initiate closure of all main steam isolation valves (MSIV). 0.45 MSIVs reached 85% open and initiated 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. LDCN-15-011 5.2-41

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6 Design Temperature, Pressure and Maximum Test Pressure for RCPB Components Design Design Maximum Test Component Temperature (°F) Pressure (psig) Pressure (psig) Reactor vessel 575 1250 1563 Recirculation system Pump discharge piping, through 575 1650 (a) valves Pump discharge piping, beyond 575 1550 (a) valves 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 vessel to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) 5.2-42

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6 Design Temperature, Pressure and Maximum Test Pressure for RCPB Components (Continued) Design Design Maximum Test Component Temperature (°F) Pressure (psig) Pressure (psig) Shutdown return Recirculation header to second isolation valve Piping 575 1575 (a) Valves 575 1575 (b) Reactor feedwater Reactor vessel to manual valve (F011) Piping 575 1300 (a) Valves 575 1300 (b) Reactor core isolation cooling system Steam to RCIC. 575 1250 (a) Pump turbine Reactor vessel to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) Pump discharge to reactor 170 1500 (a) Reactor vessel 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 inside containmentc Piping 575 1250 (a) Valves 575 1250 (b) 5.2-43

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-6 Design Temperature, Pressure and Maximum Test Pressure for RCPB Components (Continued) Design Design Maximum Test Component Temperature (°F) Pressure (psig) Pressure (psig) From maintenance valve to reactor vessel Piping 575 1250 (a) Valves 575 1250 (b) Low-pressure core spray system Outboard isolation valve to reactor vessel 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. 5.2-44

COLUMBIA GENERATING STATION Amendment 57 FINAL SAFETY ANALYSIS REPORT December 2003 Table 5.2-7 Reactor Coolant Pressure Boundary Materials Specification Component Form Material (ASTM/ASME) Reactor vessel Rolled plate Low alloy steel SA-533 grade B class 1 Heads, shells Forgings SA-508 class 2 Welds Low alloy steel SFA-5.5 Closure flange Forged ring Low alloy steel SA-508 class 2 Welds Low alloy steel SFA-5.5 Nozzle safe ends Forgings or Stainless steel SA-182, F304 or F316 Plates SA-336, F8 or F8 M SA-240, 304 or 316 Welds Stainless steel SFA-519, TP-308L or 316L Nozzle safe ends Forgings Ni-Cr-Fe SB-166 or SB-167 Welds Ni-Cr-Fe SFA-5.14, TP ERNiCr-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 SA-182 grade F, 316L stainless steel Cladding Weld overlay Austenitic SFA-5.9 or SFA-5.4 stainless steel TP-309 with carbon content on final surface limit to 0.09% maximum Control rod Pipe Austenitic SA-312 type 304 drive housings Forgings stainless steel SFA-5.11 Welds Inconel type ENiCrFe-3 or SFA-5.14 type ERNiCr-3 LDCN-00-096 5.2-45

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 Table 5.2-7 Reactor Coolant Pressure Boundary Materials (Continued) Specification Component Form Material (ASTM/ASME) In-core housings Pipe Austenitic SA-312 type 304 Forgings stainless steel SFA-5.11 Welds Inconel type ENiCrFe-3 or SFA-5.14 type ERNiCr-3 Additional RCPB component materials and specifications to be used are specified below. Depending on whether impact tests 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, SA-194 grades 7 and 2H, or SA-540 B23/24 Class 3 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 base 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 LDCN-19-012 5.2-46

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-7 Reactor Coolant Pressure Boundary Materials (Continued) 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 5.2-47

LDCN-09-032 Table 5.2-8 Water Sample Locations Range Alarm Sample Origin Sensor Location Indicator Location Recorder Location mho/cm Low High Reactor water Sample line Sample station Control room 0-1 0.0 1.0 recirculation loop COLUMBIA GENERATING STATION Reactor water cleanup Sample line Sample station Control room 0-1 0.0 1.0 system inlet Reactor water cleanup system outlets Sample line Sample station Control room 0-0.3 NA I 0.15 5.2-48 FINAL SAFETY ANALYSIS REPORT Amendment 61 December 2011

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 Stainless steel to stainless steel 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 stainless steel 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 5.2-49

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 4RRC(4) A-1 thru 4RRC(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 a 4JP (NZ) A-1 Inconel 182 buttering 1 a 4JP (NZ) B-1 Inconel 182 buttering 1 a 4JP (NZ) A-2 1 a 4JP (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%. 5.2-50

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Table 5.2-11 Main Steam Isolation Valves Material Information Material Minimum Design Item Spec Material Type Wall Thickness Body SA-216 GR WCB 1.58 in. Bonnet SA-105 GR II 7.66 in. Stem disca SA-105 N/A 1.56 in. Disc pistona SA-105 N/A 3.24 in. Stema SA-564 or Tp 630 H1100 A-182 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 materials 5.2-51

LDCN-12-020 Table 5.2-12 Summary of Isolation/Alarm of System Monitored and the Leak Detection Methods Used Variable Monitored FUNCTION A A A A/I A/I A A/I A/I A/I A/I A/I A A High/Dry- Equip- Low RB Sump RCIC Reactor PC Sump well Cooler ment Steam or Drain PC High Diaphragm RWCU Low High Fission Source of High High Condensate Area Line High Pressure Flow High Exhaust Flow Water Differential Products Leakage Location PC F Flow Rate Flowa High T Pressure Flow Rate (High) Rateb Line Pressure (High) Level Pressure Higha COLUMBIA GENERATING STATION and T Main steam line PC X X X Xc X X X X RB X c X X X X RHR PC X X X X X X RB X X X X 5.2-52 RCIC steam PC X X X X X X X FINAL SAFETY ANALYSIS REPORT 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 a PC - Primary containment NOTE: All systems within the drywell share a common detection system. Amendment 62 b RB - Reactor building Break downstream of flow element will isolate the system. c RWCU - Reactor water cleanup In run mode only. d CCW - Closed cooling water Alarm only (steam tunnel). A - Alarm December 2013 I - Isolation

Amendment 53 November 1998 1.05 1.04 "Opening" Path "Closing" Path 1.03 Code Approved Capacity t 1.02 I I I Pressure/Pressure Set Point I 1.01

                                                          \--------7l                                                         1.00 l

0.99 0.98 0.97 I I i 0.96 100 80 20 60 40 0 Simulated Safety Relief Valve Spring Mode Columbia Generating Station Characteristic used for Capacity Sizing Analysis Final Safety Analysis Report Draw. No. 960690.46 Rev. Figure 5.2-1 Form No. 960690

Amendment 63 December 2015 MSIVF ICF_ TNE0-OVERPRESS KK1 23 140 420 80 1400

                                        ----- Core Inlet Flow Simulated Thermal Power Neutron Flux
                                                                                                                             - - - RV, SV, and/or SRV Flow
                                                                                                                             ----- Bypass Valve Flow
                                                                                                                             - - Vessel Dome Pressure 120                                                             360                70                                                                 1350 60                                                                 1300 100                                                             300 Q) 50                                                                 1250 _

ii ltl "C 80 240 tt: .iii Q) ii ~ "C .9: Q) l:t: X

J ii 40 1200 ~

l:t:  ::J 0 ii: II) II) 60 180 §

   ';/!.
                                                                               ...          30     ***********:******

Q) 1150 Ii:

                                                                              '5 Q) z 40                                                             120 20                                                                 1100 20                                                              60                10                                                                 1050 0                                                               0                 0                                                                 1000 0                    2  3       4        5       6      7                          0                    2    3         4     5         6       7 Time (sec)                                                                           Time (sec) 120
                                              -----  Feedwater Flow 60                4.0
                                                                                                                                 ----- Total Reactivity Steam Flow                                                                        Scram Reactivity
                                              --r-   Turbine Steam Flow                      3.5                                       Doppler Temperature Reactivity NR level                                                                          Void Reactivity 100                                                               50                3.0 t              2.5

ii:

II) 80 40 B E 2.0 ltl ltl II) C:Q) Cl. Q) C: 1.5 "C II) 0 Q) Cl. E 1.0 Q) ii 60 30 > 0 l:t: 0

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                                                                                     -.:?~ 0.5
   ~

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                                                                              .s::.

u tiltl 40 20 :§. Q) 0.0 l:t: G) Q) -0.5

                                                                              .J 20                                                               10               -1 .0
                                                                                            -1.5 0                                                                0               -2.0 0                    2  3        4        5       6       7                          0                    2       3        4         5         6         7 TRACG_CASE_O: 20141212 .0901165 Time (sec)                                                                                Time (sec)

Columbia Generating Station Final Safety Analysis Report Draw. No. 950021.16 Rev. 1 Figure 5.2-2 Form No. 960690 LDCN-15-011

Amendment 53 November 1998 1400

                                                        -----------~--------------------

Code Limit (1375 psig) Peak Vessel Bottom Pressure (psig) 1350 ---- -

                                                                                                          ,,,,              MSIV - Flux Scram (REDY)

(psig) 1300 MSIV - Flux Scram (ODYN) 0 1250 LR W/O BP (ODYN) 1200 I I I () 40 60 80 100 120 Safety Valve Capacity - % NB Rated Steam Flow I I I I I I I I 8 10 12 14 16 18 Number of Operating Safety Valves Peak Vessel Pressure Versus Safety Valve Capacity Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.47 I Rev. I Figure 5.2-3 Form No. 960690

Amendment 53 November 1998 MSIV Closure - 14 Flux Scram (REDY) 12 MSIV Closure - Flux Scram (ODYN) 10 LR w/o BP Direct Scram (ODYN) 8 Time (Sec) 6 4 2 1350 1300 1250 1200 1150 1100 1050 Vessel Bottom Pressure (psig) Time Response of Pressure Vessel for Columbia Generating Station Pressurization Events Final Safety Analysis Report Draw. No. 960690.48 Rev. Figure 5.2-4 Form No. 960690

2 3 4 5 6 7 8 9 10 Amendment 61 ORI VlNG REC IR.C LOOP December 2011 CALl&RA"TE"O .jEi PUMPS NO"-l-C.ALl5RA7"ED JEl PUMPS (4PI..AC.ES) M PL NO. 822-1040 (IE, PLACE'3) A TABLE Yf, ELEVATION CORRELATION CHART CONTROL ROOM WATER LEVEL fNDtCA.T!ON ANO TRIP LEVEL'5

                          ~EFERENCE                (COLD                   DESCRJPTION                  INSTRUM[NT(Sl        REACTOR SEE NOTE 3 TO FT                                                                                                         NOTES:

VE:SSELl Of TRJPS PROVIDING VESSEL INCI-IES TRIP L[Vtl 5AF'EGUAROS -"EEOWATER TO FT t,JQ34C. l. REF. DOC. 1 SHALL BE USED WITH AND FORM PART OF THIS P&ID DATA, IF THERE ARE ANY CONFLICTS BETWEEN THE P&ID AND THIS ABOVE IDENTITY P&ID DATA, THE P&ID DATA SHALL GOVERN. F"UEL ZONE WIDE RANGE NARROW f.!ANGE UPSET SHUTDOWN VESS[L SEE IU:F.25 2. MPL NO'S ARE PREFIXED BY B22 UNLESS OTHERWISE NOTED. ZERO OF PtlO LR*R015 LR/PR-R623AB C34 LR-R608 C34- Ll*R605 *0 F", N034E 3. WATER LEVEL INSTRUMENTS FOR VARIOUS RANGES ARE CALIBRATED LI-R6I0 LI-R~04 C 34 LI- R606A,B,C LR-R608 AS STATED BELOW. ALL WATER LEVEL SWITCH SET POINTS ARE

                                                                                                                                                                                                                              +400"                                                                                                                                                NOMINAL: IE, THE ANAU'SES ARE PERFORMED WITH THE SWITCH r
                                               ~

TOP OF HEAD LAt.16£ + /BOW TR IP UNCERTAINTY . !1-ICLUDED. REACTOR BU I LO I NG TEMPERATURE B STEAM LIN[ "l 648 ASSUMED TO BE 75 F. A. FUEL ZONE: THE INSTRUMENTS ARE CALIBRATED FOR SATURATED NOZZLE N3 WATER STEAM CONDITIONS AT O PSIG IN THE INSTRUMENT LINE 599 VESSEL AND THE DRYWELL WITH NO JET PUMP

                                                                                                                                                            +GO"             +{,o"             H)O" NOZZLE N,4 J                             SIP RCIC HPCS           & CLOSE INJECTION   VALVEO ~

FLOW. WATER LEVEL SWITCH TRIP UNCERTAINTY IS+/-. 6" OF WATER LEVEL AT CALIBRATION CLOSE MA.IN TURBINE STOP VALVES. TABLE REF. 2 n:t e - - - - - -- - - - +54-5" +54.5" B. WIDE RANGE: CONDITIONS, THE INSTRUMENTS ARE CALIBRATED FOR 1000 PSIG 1~ I~~l~~s~~~to6CT~~ TRIP F£[D PUMPS.

                                                                                                 -                               7
                                                                                                                                            ------ ------- - ----                            +40-5                                                                                                                                                                                                                                 ~~L~ET~r~~55l~N~ATER
                                                                                                                                                                                                                                                                                       ----+-----

HIGH LEVEL ALAi;!M REF. 2 5,6 LEVEL NOZ:Z.LE AND SATURATED CONDITIONS ABOVE i-<ecos """ NORMAL WATEJl LEVEL- REF. 2 4 +31.5 THE MIDDLE WATER LEVEL NOZZ.LE WITH NO JET REF.2 LOW LEVEL ALARM RUN RECIRC FLOW BACK *- PUMP FLOW. WATER IS+/-. 6" OF WATER LEVEL SWITCH TRIP UNCERTAINTY LEVEL AT CALIBRATION CONDITIONS, c:;_ C. NARROW RANGE: (SAFEGUARDS AND FEEDWATER}: THE I1':STRUMENTS SHUTDOWN COOLIN( SOLATION VALVE'>. >-- + 13 11 +13" ARE CALIBRATED FOR SATURATED WATER STEAM TABLE TIT REF. 2 3 ----- ----- CONglTIONS AT 1000 PSIG IN THE VESSEL AND

                                                                                                                                                                                                                                                                                                                                                                                                                                                                 !~I CONTli! lBUT£ TO AUTO                                                                                                                                                                                                                 1                                                                                               135 F IN THE DRYWELL. WATER LEVEL SW!TCH DEPRESSURIZATION.

RUN 8AC.K. RECIRC  !~l~A~~~~=i~6~Tfo~61f16Nr OF WATER LEVEL WATER L£\1EL INSTRU- FLOW

                                                                                                                                                                                                                                                                                                                                                                                                          ~~~E~ Ng~~~E~~~ti ~ T ~~~~ B=~T~~6o~s ~~ T~~Ai~~       1~,

MENT ZERO r::.27_,; INITIATE RC-IC& HPCS,

                                                                                                                               - --              O"            O"                O"               o"             Q"              O"                                                                                                                                                a. UPSET RANGE, VESSEL AND 135 FIN THE ORYWELL,                         -f),.

BOTTOM OF OQYf.R SJ(IRT tVt CLO';E PRIMARY

                                                                                                                                                                                                                                                                                                                                                                                                                                             ~S\~f E. SHUTDOWN,           THE INSTR                                                -t,,...

SYSTEMS ISOLATION 0~~v~:[~~ INSTRUMENT Llr,.IE 5'7 VALVES EXCEPT RHR AT o PS I G~~N!d~E~A~~gR:6~~ NOZZLE N 13 I C:.HUTOOWN COOLING.

                                                                                                                                                             - so" v1I~~~.\

2 ----- TAe.LE I:SZ"

                                                                      ~I~IE sbR~~~N              1-D                                                                   I HIP R.:.U C 1-'UMI-:>                                              -110" TOFT N034D                                                              TOl=""T NOj4-R
                                                                      !N\TlATE RHRt I                         -12.'3"

CORE. SPRAY SYS CONTRIE!.UTE. TO ' - TABLE Ill - -- --- 180"

                                                                                                                                                             -f',Q" AU10 DEPl<E55Uli?-
                                                                                                  ,                                                                                                                                                                                                          TO FT N034V                                                   REFERENCE QOC~:

a** IZATION. 'START STAND-f->Y DIE5EL. INSTRUMENT LINE ~ F", No33c I. NUCLEAR BOILER SYSTEM P&ID--------- I CLOSEMSI Vs, MAINSTEA.M NOZZ:LE Nl2 LINE DRAIN VALVES 2. FEEOWATER CONTROL SYSTEM IED--------- ---- 8 22-1010 TOP OF ACTIVE FUEL 3{;6.3 ~

                                                                                                                               ----                                                                                                                                                                                                                                        3.     ~~CLEAR BOILER SYSTEM FCO------------=============~!;=~~~~

4. EC EQ SEP SAFEGUARD SYS-------------------------A62 4050 JET PUMP IN'a,TRUMEl,ff1 152-0 s. REMOTE SHUTOCJ',,i'N SYS IED---------------------------cs,:1010

                                                                                                                                              -310" NOZZLE N9                         143.5 E               JET PUMP O!FFUSfR TAP

• FUNCTION IS IN FEEDWATER CONTROL SYS(REF 2) FOR LOSS OF ONE FEED PUMP TABLE J: SAFETY /RELIEF VALVE LOCATION SUFFIX ASSIGNMENT ASSOCIATED EQUIPMENT A B C D E F G H J K L M* Nil p R
• S* u@ v@

SAFETY I RELIEF VALVE F013 TABLE Il' JE, PUMP 1'-'STR.UMENTATION '30FFIX LE.T"l"ER ASSIGNMENT A003 (ADS) M N p R s u V LOOP A B F ACCUMULATORS E F G J K L M N p R s u V - -- zo A004 A B C D H I 2 3 4 5 G 7 8 9 10 II 12 1'3 14 15 17 19

                                                                                                                                                                                                                                                                                          .JP l'JO.                                                                                                                                18 E         F                               J          K           L       M           N         p     R       s        u          V e.

A B C D G H CHECK VALVES F036 M N p R s u V FT N034 A C E G J L N R T V D F H I< M p u w F040(AD<;) VACUUM BREAKER F037 A S C D E F G H J K L M N p R s u V E/5K61",

                                                                                                                                                                                                                                                                                                                                                             '                                                                      s     u      w dPI R<>08      A     C       E     G     J      L       N     R                      B        D    F         H               M      p B           C         D            E         F        G            H         J          K           L        M           N        p     R       s        u          V V                                          IS PRE<;<;URE SWITCH                       N039                      A r.,- k600       A      C     E. G     J      L      N      R. T      V         B        D    F         H        I<     M     p       s     u      w e----.

COMPUTER INPUTS FOR VALVE PQ':,(REF 3)/4\ Cl732 Cl733 C1734 C 1735 C1736 C 1737 C1738 C1739 C1740 C 1741 C1742 C1743 C1744 C17 45 C 1746 C1747 C 1748 C1749 p R s u _:E_ _ 14-- ~K60IA KE,OIC- 1------o, KfD7A I+- ~KE.01~ K601D- K607B TEMPERATURE ELEMENT I N004 A B C D E F G H J K L M N V

                                                                                                                                                                                                                                                                                          'E                                                                                                                   K602B K.6O2A YES        YES       YES    YES    YES      YES        YES ADS     FUNCTION A11*1 A.11,z A.17~1               Al~~ Al7'4 Al767 AI768 A17&9 A1770
                                                                                                                                                                                                                                                                                           ~          Al75I Al7'52 A17'53 A!754 A!755 Al75*         Al75&         A.17',0 ADS - SAFETY /RELIEF \ALVE FOR AUTO DEPRESSURIZA TION

• F"T N033 - - - - A - - - C - - - - I!> - - - - D

                                                                                                                                                                                                                                                                                         .,,,---1<.,05 -
                         -CONTROL PROVIDED IN REMOTE SHUTDOWN SYS (REF 5)
                      - (01\!TP..DL PR,OVibEb IN P--LIE.R.NA.IE. -RE\vl.OlE. Sl-hJTUOWN S'IS (S"E."'E. REFS)                                                                                                                                                                                                -      -      -      A    -       -     - -             C       -        -    -          -         I!>   -     -      -     -       D H                  @@

NS 4 EXC EPT MS!Vs, MAIN STEAM LlNE DRAIN VALVES. MS!Vs, MAIN STEAM LINE DRAIN VALVES. FIR609 - - - - A - - - - C - - - - & 0 THE SUPPLY SYSTEM IS RESPONSIBLE. FOR DESIGN C\-\1'-NGE. CONTROL OF l"\-IIS DOCUMEf-!T

                 \A&LE. n;z: WATER LEVEL INSTRUME.NT                                       CONTACT          UTILIZATION                                   TABLE :iz:, PRESSURE INSTRUMENT CON,ACT UTILIZATION UPPE.ii2            RANGE.                                                    LEVEL    TRAt.t.S                  INSTRUMENT INSTR\JME.NT     o,v                                                                                   IF DIV       TRIP NUMl3E.lc.             iRIP 2-A                                                          Tli?lP 1-e,          ~~M:-                     NUMBER.

f  : Ll5-NO -tA PS N020A IA RPS RC-I" (t) IS Ll5-N02-t& PS N020B RPS Ll~-N02.-tC Ll~-NOZ.'tD "R,1c;. (Il) PS P5 N020C N0200 II A II B RPS RPS C D A e. J-1.PC.!, LIS- NIOOA LtS-J,J!QOi,o 1*\PC,S ~ PS P5 N023A N023B IA IB RPS RPS P5 N023C II A RPS MA.IN '3TEAM LlMES tir-~iiii 1 APHA) A175(1>) PS PS N023D N039

• II B I

RPS RELIEF VALVE -- 02-Ll5-N037A I RClC 2 LPC5~RHl<(A AD5(A) PS N045A RECIRC (A) -- 0282 2-0 4 26 22 2 RHR(l!,)f~HR(C ADS(!!,) PS N0458 RECIRC (BJ -- Ll'S-N037B Il RCIC RECIRC(A) -- CVI NO CVI SHT REV DWG SHT L!S-N037C 1 RC lC 2 LPC':> ~ lii!HR(A. AO5(A) PS PS N045C N045D RECIRC(B) --- a* VESSEL

                                                                                                                                                           ~i ~g:;i*.%               m US- N0'37D        II   RC 1 C                                 2      RHR(e.)~RHe(c) ADS(e.)                                                                               HPCS                  --

LIS-N03I A. ill HPC-5 2 m HPCS -- NS4 (II~) K PS N048A,C I RP'S(Il BJ Ll5*N03l B ill HPCS 2 II ~~~{Ei).RHR(C)RHRLA] - - PS N048 B, D l!S-N031 C ill HPC.S 2 PT N051A IA K613A LIS-N031D ID HPCS 2 PT N05iB IS K613B PS N015A IA 2 IB __._l____.,,a_"_,___.2":i2"v".~~._ C72A-K613 A PS N015B 2 C72A-K613 B PS N015C IIA MS -LS-JOOC 2 C72A-K613C PS N015D II B L _ MS -LS-JOOD 2 C72A-K613D VS N056A TA f 24. D - . VS N056B I B LIS- No,oA 2 VSN056C IIA VSN0560 IIB Ll5- N031c.a 2 12' LIS- N03bC 2 LT N02 l K615 180° L dPT N032 K615 LIS-N036D 2 L.T -N027 l(.(ol5 FIGURE II E 12 dPT-N03Z KGIS 1ao0 O!V\'510N ORIENTATION FEE"0WAiER PIPING. DETAIL K<;o3A PT-NO IS SR.V TEST FlGU~E I FOR VE':JSEL IN'5TRUMENTA1I0N 1!;~E C72A-K613A 1 RHR(A) 1 LPCS S.AFE.TY/fl.ELlEF VALVE LOCATION ('5EE REF 4) (TYP,CAL) C72A-K6138 ~~:~: 1 n RHRCB) &,.CC) t SPRING SET PRESSURE MS-LlS-200C C72A-K613C MS-LlS-2000 C72A-K613D Nuclear Boiler System - P&ID Columbia Generating Station M Final Safety Analysis Report Draw. No. 02B22-04,26,1 Rev. 22 Figure 5.2-5 Form No. 960690ai

Amendment 53 November 1998 Drywell Main Steam Line Safety/Relief Valves Reactor Vessel Main Steam Isolation Valves Flow Restrictor Suppression Pool Safety/Relief Valve Schematic Elevation Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.49 Rev. Figure 5.2-6 Form No. 960690

Amendment 53 November 1998 Main Steam Lines Drywell Main Steam Isolation Valves S/R V S/R V S/R V S/R V S/R V S/R V S/R V S/R V S/R V S/R V S/R V S/R V S/R V S/R V Reactor Vessel S/R V S/R V S/R V S/R V Safety/Relief Valve and Columbia Generating Station Steam Line Schematic Final Safety Analysis Report Draw. No. 960690.62 Rev. Figure 5.2-7 Form No. 960690

Amendment 53 SPVD Linear Variable Valve Position Differential November 1998 Indication (VPI) LVDT Transformer (LVDT) SPVD Load Cell Set Pressure Verification Device (SPVD) Pneumatic Head Lever Setpoint Adjust Screw Piston-type Pneumatic Actuator Assembly Bonnet Spring Spindle Balancing Piston Bellows Solenoid/ "A" Eductor Air Control "B" Valve Assemblies Blowdown "C" Adjusting Ring Eductor Sleeve Disc Holder Discharge Disc Ring Nozzle Disc Nozzle Ring Body Steam Schematic of Crosby 6R10/8R10 Dual- Flow Function Type Spring-Loaded Direct- Inlet Acting Safety/Relief Valve Schematic of Safety Valve with Auxiliary Columbia Generating Station Actuating Device Final Safety Analysis Report Draw. No. 960690.85 Rev. Figure 5.2-8 Form No. 960690

Amendment 53 November 1998 100 Safety Valve opening characteristics Safety Valve Lift Valve achieves 50 rated capacity at < 103% of (% of full open) set pressure Valve Stroke Time 0

                                                       ------------------f~

0.3 Time (Sec) T1 T1 = Time at which pressure exceeds the valve set pressure Safety Valve Lift Versus Time Characteristics Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.50 Rev. Figure 5.2-9 Form No. 960690

Amendment 53 November 1998 100 1 10 0.5 Specific Conductance (µmho/cm at 25°C) Chloride (ppm) 0.2 0.1 1 0.1 0.01 4 5 6 7 8 9 10 pH (at 25°C) Conductance Versus pH as a Function of Chloride Columbia Generating Station Concentration of Aqueous Solution at 25°C Final Safety Analysis Report Draw. No. 960690.51 Rev. Figure 5.2-10 Form No. 960690

Amendment 63 December 2015 DELETED Typical BWR Characteristic MSIV Columbia Generating Station Closure Flux Scram Final Safety Analysis Report Draw. No. 960690.52 I Rev. I Figure 5.2-11 Form No. 960690 LDCN-15-011

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 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 appurtenances are shown in Table 5.2-7 together with the applicable 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 ordered to ASME SA-533, Grade B, Class 1, and forgings to ASME SA-508, Class 2. These materials are melted to fine grain practice and are supplied in the quenched and tempered condition. Further restrictions include a requirement for vacuum degassing to lower the hydrogen level and improve 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% ultrasonically tested and surface examined by magnetic particle methods or liquid penetrant methods in accordance with ASME Section III Subsection Nuclear Boiler (NB) standards. Fracture toughness properties 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 drawings, fabrication procedures, and test procedures. The shells and vessel heads are made 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 interpass 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 applied to all low alloy steel welds. Radiographic examination is performed on all pressure containing welds in accordance with requirements of ASME Section III, Subsection NB-5320. In addition, all welds are given a supplemental ultrasonic examination. LDCN-08-000 5.3-1

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 The materials, fabrication procedures, and testing methods used in the construction 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 pressure vessel were examined 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 techniques. The ultrasonic examination method, including calibration, instrumentation, scanning sensitivity, and coverage was based on the requirements imposed by ASME Code 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 with Code Requirements The ferritic pressure boundary material 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 Failure, 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 with 10 CFR 50 Appendix G must have both drop-weight tests and Charpy V-notch (CVN) tests with the CVN specimens oriented transverse to the maximum material working direction to establish the RTNDT. The CVN tests must be evaluated against both an absorbed energy and a lateral expansion criteria. The maximum acceptable RTNDT must be determined in accordance with the analytical procedures of ASME Code Section III, Appendix G. Appendix G of 10 CFR 50 requires a minimum of 75 ft-lb upper shelf CVN LDCN-04-005 5.3-2

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 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 Station (CGS) reactor vessels was qualified by either drop-weight tests or longitudinally oriented CVN tests (both not required), confirming that the material nil-ductility transition temperature (NDTT) is at least 60°F below the lowest service temperature. When the CVN test was applied, 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 RTNDT and the highest RTNDT 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 appropriate method of compliance. 5.3.1.5.2.1 Intent of Proposed Approach. The intent of the proposed 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 toughness. 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, Paragraph 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 pressure during normal heatup and cooldown and during inservice hydrostatic testing were established using 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 areas remote from discontinuities plus the feedwater nozzles were evaluated, and the operating limit curves are based on the limiting location. The boltup limits for the flange and adjacent shell region are based on a minimum metal temperature of RTNDT +60°F. The maximum through-wall temperature 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. LDCN-04-005 5.3-3

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 For the purpose of setting these operating limits the reference temperature, RTNDT, is determined from the toughness test data taken in accordance with requirements of the code to which this vessel is designed and manufactured. This toughness test data, CVN and/or dropweight NDT, is analyzed to permit compliance with the intent of 10 CFR 50 Appendix G. Because all toughness testing needed for strict compliance with Appendix G was not required at the time of vessel procurement some toughness results are not available. For example, longitudinal CVNs, instead of transverse, were tested, usually at a single test temperature of D +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 correlations were derived for the vessel materials to operate on the available data to give a conservative estimate of RTNDT compliant with the intent of Appendix G criteria. These toughness correlations vary, depending upon the specific material analyzed, and were derived from the results of Welding Research Council (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 CVN 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 orientation 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 RTNDT 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 available for the vessel flange, closure head flange, and feedwater nozzle materials for CGS. RTNDT is estimated in the same way as for vessel plate. For the vessel weld metal the 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 the same way as for the vessel plate material, except the 30°F addition of orientation effects is omitted since there is no principal working direction. When NDT values are available, they are also considered and the RTNDT is taken as the higher of NDT or the 50 ft-lb temperature 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. LDCN-04-005 5.3-4

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 For vessel weld HAZ material the RTNDT 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 vessel, including the basic dimensions, all longitudinal and circumferential welds, and all plates 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 the plates and filler material used in the beltline region. Closure bolting material (SA-540 Grade B24) toughness test requirements 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 for 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 connecting to the closure flange forgings. The effect of the feedwater nozzle discontinuities were considered by adjusting the results of a BWR/6 reactor discontinuity analysis to the reactor. The adjustment was made by increasing n the minimum temperatures required by the difference between the CGS and BWR/6 feedwater nozzle forging RTNDT. The feedwater nozzle adjustment was based on an RTNDT 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 energies due to increased flux, was evaluated against the requirements of 10 CFR 50 Appendix G. For a predicted fluence of 7.41 x 1017n/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 closure flanges to assist in warming them. IThe 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. IThe fully preloaded boltup limits are shown in Figure 5.3-1. 5.3.1.5.2.4 Inservice Inspection Hydrostatic or Leak Pressure Tests. Based on 10 CFR 50 Appendix G, and Regulatory Guide 1.99, Revision 2, requirements, pressure/temperature limit curves were established based on an RTNDT of 28°F for the limiting beltline material; see Figure 5.3-1. The fracture toughness analysis for inservice inspection of leak test resulted in LDCN-04-005 5.3-5

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 curve A shown in Figure 5.3-1. The predicted shift in the RTNDT temperature was determined using the methodology outlined in Regulatory Guide 1.99, Revision 2. Technical Specification 3.10.1 allows 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 heatup or cooldown rate of 100°F/hr. The temperature gradients and thermal stress effects corresponding to this rate were included. The results of the analysis are operating limits defined by Figure 5.3-1. Curves A, B, and C give the limits for hydrotest, nonnuclear heating, and nuclear heating. The minimum boltup temperature of 80°F is based on an RTNDT at 20°F for a shell plate which 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 RTNDT of 28°F, is most limiting for inservice hydrostatic D or leak pressure tests (curve A). The feedwater nozzles, which have an RTNDT of 0°F, are more restrictive than the core beltline at lower pressures during nonnuclear 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 beltline 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 program monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting from exposure to neutron irradiation and thermal environment. The CGS plant-specific RPV materials surveillance program is replaced by the NRC approved BWR Vessel and Internals Project (BWRVIP) Integrated Surveillance 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 representative materials for the CGS vessel is based on the latest approved revision of BWRVIP-86 (Reference 5.3.4-2). No capsules from the CGS vessel are included in the ISP. The withdrawal of capsules for the CGS plant-specific surveillance program is permanently deferred by participation in the ISP. Capsules from other plants will be removed and tested in accordance with the ISP LDCN-13-009 5.3-6

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 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 selected 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 typical of those in the beltline region and thus represent base metal, weld metal, and the transition zone between base metal and weld. The plate and weld were heat treated in a manner which simulates the actual heat treatment performed on the core region shell plates of the completed vessel. WPPSS-ENT-089 (Reference 5.3.4-1) provides additional detail and supporting information 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 Surveillance Capsules and Method of Attachment for Plant-Specific Surveillance Program Surveillance specimen capsules are located at two azimuths at a common elevation in the core beltline region. The sealed capsules are not attached 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 position throughout any anticipated event during the lifetime of the vessel. The capsule holder brackets are designed, fabricated, and analyzed to the 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 have to comply with specifications of the ASME Code. 5.3.1.6.2 Time and Number of Dosimetry Measurements General Electric provides a separate 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 over 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 between fluence and power output. LDCN-18-012 5.3-7

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 5.3.1.6.3 Neutron Flux and Fluence Calculations A description of the methods of analysis for neutron flux and fluence 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 tensioning using hydraulic tensioners. The design and analysis of this area of the 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 tensile stress for the bolting material was 167,000 psi which is less than the 170,000 psi limitation in Regulatory Guide 1.65. Also the Charpy impact test recommendations of Paragraph 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 impact properties. For example, the lowest reported CVN energy was 45 ft-lb at 10°F versus the required 45 ft-lb at 70°F and the lowest reported CVN expansion was 26 mils at 10°F versus the required 25 mils at 70°F. Hardness tests are performed on all main closure bolting to demonstrate that heat treatment has been properly performed. Studs, nuts, and washers are ultrasonically examined in accordance with Section III, NB-2585 and the following additional requirements:

a. Examination is performed after heat treatment and prior 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 depth of 0.5 in. For additional details of the techniques used to examine the reactor vessel studs, see 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 circumferential directions.

I 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 retaining lubricant on these surfaces. LDCN-16-021 5.3-8

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3.2 PRESSURE-TEMPERATURE LIMITS 5.3.2.1 Limit Curves Limits on pressure and temperature for inservice leak and hydrostatic tests, normal operation (including heatup and cooldown), 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 transients 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 temperature and pressure condition anywhere in the vessel head and/or shell areas has a minimum fluid temperature of 250°F and a maximum pressure peak of 1180 psig. Scram automatically occurs with initiation of this event, 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 transient pressure of 1180 psig, the minimum allowable reactor vessel metal temperature conservatively bounds the minimum 250°F reactor fluid temperature. 5.3.3 REACTOR VESSEL INTEGRITY The reactor vessel was fabricated for GEs Nuclear Energy Division by CBI Nuclear Co., and was subject to the requirements of GEs Quality Assurance program. Assurance was made that measures were established requiring that purchased material, equipment, and services associated with the reactor vessel and appurtenances conform to the requirements of the subject purchase documents. These measures included provisions, as appropriate, for source evaluation and selection, objective evidence of quality furnished, inspection at the vendor source, and examination of the completed reactor vessel. Energy Northwests agent provided inspection surveillance of the reactor vessel fabricators in process manufacturing, fabrication, and testing operations in accordance with GEs Quality Assurance program and approved inspection procedures. The reactor vessel fabricator was responsible for the first level inspection of manufacturing, fabrication, and testing activities, and GE was responsible for the first level of audit and surveillance inspection. Adequate documentary evidence that the reactor vessel material, manufacture, testing, and inspection conforms to the specified quality assurance requirements contained in the procurement specification is available in plant records. LDCN-04-005 5.3-9

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 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 construction. The vessel is designed, fabricated, tested, inspected, and stamped in accordance with the ASME Code Section III, Class 1, including the addenda in effect at the date of order placement. Design of the reactor vessel 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 for 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 embrittlement is not a problem outside of the vessel beltline region because the irradiation in those areas is less than 1 x 1018 nvt with neutron energies in excess of 1 MeV. The inside diameter and minimum wall thickness of the reactor vessel beltline is provided in Table 5.3-9. Quality control methods used during the fabrication and assembly of the reactor vessel and appurtenances ensure that design specifications were met. The vessel top head is secured to the reactor vessel by studs and nuts. These nuts are tightened with a stud tensioner. IThe vessel flanges are sealed with two concentric metal seal rings designed to permit no detectable leakage through the inner or outer seal at any operating condition,Iincluding heating to operating pressure and temperature 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 carry 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 assemblies. Design of the shroud support also accounts for pressure differentials across the shroud support plate, for the restraining effect of components attached to the support, and for earthquake loadings. The shroud support design is specified to meet appropriate ASME Code stress limits. 5.3.3.1.1.3 Protection of Closure Studs. The BWR does not use borated water for reactivity control. This section is therefore not applicable. LDCN-04-033, 05-021 5.3-10

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3.3.1.2 Safety Design Bases Design of the reactor vessel and appurtenances meet the following safety design bases:

a. The reactor vessel and appurtenances will withstand adverse combinations of loading and forces resulting from operation under abnormal and accident conditions, and

b. To minimize the possibility of brittle fracture of the nuclear system process barrier, the following are required:

1. Impact properties at temperatures related to vessel operation have been specified for materials used in the reactor vessel.

2. Expected shifts in transition temperature during design life as a result of environmental conditions, such as neutron flux, are considered in the design. Operational limitations ensure that NDTT shifts are accounted for in reactor operation.

3. Operational margins to be observed with regard to the transition temperature are specified for each mode of operation.

5.3.3.1.3 Power Generation Design Basis The design of the reactor vessel and appurtenances meets the following power generation design basis:

a. The reactor vessel has been designed for a useful life of 40 years,

b. External and internal supports that are 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 appurtenances 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. 5.3-11

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 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 Control Rod Drive Housings. The control rod drive (CRD) 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 head of the reactor. These loads include the weights of a control rod, a CRD, a CRD tube, a four-lobed fuel support 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 consists of adding pressure equalizing valves between the exhaust and cooling water headers and the use of reverse flow through multiple hydraulic control unit (HCU) solenoid 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 systems functions performed normally. 5.3.3.1.4.3 In-Core Neutron Flux Monitor Housings. Each in-core neutron flux monitor housing is inserted through the in-core penetrations in the bottom head and is welded to the inner surface of the bottom head. An in-core flux monitor guide tube 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 seismic restraints attached to the sacrificial shield wall. The insulation is designed to be removable 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 5.3-12

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 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 the event of injection of cold SLC solution. However, the SLC injection pipe has been relocated 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 below the core plate, but there is no flow through the nozzle under any operating 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 sparger is presented in NEDE-21821, BWR Feedwater Nozzle/ Sparger Final Report, March 1978. The solution of the feedwater nozzle and sparger cracking problems involved several elements, including material selection and processing, nozzle clad elimination, and thermal sleeve and sparger redesign. The following summarizes the problems 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 attributed 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). 5.3-13

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 The cracking of the feedwater nozzles is a two-part process. The crack initiation mechanism as discussed above is the result 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 tolerated; however, there is another mechanism which supports crack growth. This mechanism is the system induced transients, primarily the startup/shutdown transients. Because of CGSs 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 valves, 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 designed 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 surveillance program requirements. 5.3.3.1.4.7 Reactor Vessel Schematic (BWR). The reactor vessel schematic 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 vessel 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 Grade 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. LDCN-04-033 5.3-14

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.3.3.3 Fabrication Methods The reactor pressure vessel is a vertical cylindrical 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 nozzles 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 vessel full penetration welds. Submerged arc and manual stick electrode welding processes were 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 vessels have employed similar fabrication methods. These vessels have operated for periods up to 16 years and their service history is excellent. The vessel fabricator, CBI Nuclear Co., has had extensive experience with GE, reactor vessels, and has been the primary supplier for GE domestic reactor vessels 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 bolting were 100% ultrasonically tested and surface examined by magnetic particle methods or liquid penetrant methods in accordance with ASME Section III requirements. Welds on the reactor pressure vessel were examined in accordance with methods prescribed and met the acceptance requirements specified by ASME Section III. In addition, the pressure-retaining welds were ultrasonically examined using 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 was tightly sealed for shipment to prevent entry of dirt or moisture. Preparations for shipment were in accordance with detailed 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, access controls were applied to 5.3-15

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 personnel entering the vessel, weather protection was provided, periodic cleanings were performed, and only approved miscellaneous materials were used 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 restrictions on coolant temperature are

a. The average rate of change of reactor coolant temperature during normal heatup and cooldown,

b. Coolant temperature difference between the dome (inferred from Psat) and the bottom head drain, and

c. Idle reactor recirculation loop and average reactor coolant temperature differential.

The limit regarding the normal rate of heatup and cooldown (item a) assures that the vessel closure, closure studs, vessel support skirt, and CRD housing and stub tube stresses and usage remain within acceptable limits. The vessel temperature limit on recirculating pump operation and power level increase restriction (item b) augments the item a limit in further detail by ensuring that the vessel bottom head region will not be warmed at an excessive 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 recirculation 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 insure that the stress limits within the reactor vessel and its components are within the thermal limits to which the vessel was designed for normal operating conditions. To maintain the material integrity of the vessel 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 abnormal operating conditions where safety systems or controls provide an automatic response in the reactor vessel. The special and transient events considered in the design of the vessel are discussed or referenced in Section 5.2.2. 5.3.3.7 Inservice Surveillance Inservice inspection of the reactor pressure vessel is in accordance 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, Section XI. Subsequent inservice 5.3-16

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 inspection will be scheduled and performed in accordance with the requirements of 10 CFR 50.55a subparagraph (g). The materials surveillance program monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting from 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 brittle fracture control. Material surveillance programs and inservice inspection programs are in accordance with applicable ASME Code requirements and provide assurance that 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 Surveillance Program, Current Revision. 5.3.4-2 BWRVIP-86, Revision 1-A, BWR Vessel and Internals Project, Updated BWR Integrated Surveillance Program (ISP) Implementation Plan, Final Report, October 2012. LDCN-13-009 5.3-17

Table 5.3-1 10 CFR 50 Appendix G Matrix Comply Appendix G Yes/No Paragraph Topic or N/A Alternative Actions or Comments I, II Introduction; Definitions -- COLUMBIA GENERATING STATION 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. 5.3-19 III.B.3 Calibration of Temperature Instruments and No Paragraph NB-2360 of the ASME B&PV Code Section III was not in FINAL SAFETY ANALYSIS REPORT Charpy Test Machines 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. Amendment 53 III.B.5 Test Results Recording and Certification Yes See References 1 and 2. III.C.1 Test Conditions No See III.A, III.B.2 above. November 1998

LDCN-99-086 Table 5.3-1 10 CFR 50 Appendix G Matrix (Continued) Comply Appendix G Yes/No Paragraph Topic or N/A Alternative Actions or Comments III.C.2 Materials Used to Prepare Test Specimens for Yes Compliance on base metal and weld metal tests. Test weld not made on Reactor Vessel Beltline same heat of base plate necessarily. COLUMBIA GENERATING STATION 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 No Plus 60°F was added to the RTNDT for the reactor vessel flanges. 5.3-20 Region Near Geometric Discontinuities For feedwater nozzles the results of the BWR/6 analysis was adjusted to FINAL SAFETY ANALYSIS REPORT CGS RTNDT conditions. IV.A.2.c RPV Metal Temperature Requirement When Core Yes Comply with 10 CFR 50 Appendix G. is Critical IV.A.2.d Minimum Permissible Temperature During Hydro Yes Test 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 +10°F 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 -20°F and +10°F only. Amendment 54 An estimate of compliance to requirements should be made from the first surveillance capsule results per MTEB 5-2. April 2000

LDCN-04-005, 04-033 Table 5.3-1 10 CFR 50 Appendix G Matrix (Continued) Comply Appendix G Yes/No Paragraph Topic or N/A Alternative Actions or Comments IV.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, COLUMBIA GENERATING STATION 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 5.3-21 (0.09% Cu; 29, 30, 31, 36, 38 ft-lb; 30 and 40% shear at -20°F). FINAL SAFETY ANALYSIS REPORT 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 See V.A Requirements for Material Surveillance Program Table 5.3-8 Requirements for continued operations are covered in Technical V.B Conditions for Continued Operation Yes 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, Amendment 58 Section IV. See Section 5.3.1.6 for description of the Materials Surveillance Program. December 2005

Table 5.3-1 10 CFR 50 Appendix G Matrix for (Continued) Comply Appendix G Yes/No Paragraph Topic or N/A Alternative Actions or Comments V.D Requirement for RPV Thermal Annealing if V.C N/A Cannot be Met COLUMBIA GENERATING STATION V.E Reporting Requirements for V.C and V.D N/A REFERENCES 5.3-22

1. Letter MFN-414-77 from G. G. Sherwood, GE, to Edson G. Case, NRC, dated October 17, 1977.

FINAL SAFETY ANALYSIS REPORT

2. Letter from Robert B. Minoque, NRC, to G. G. Sherwood, GE, dated February 14, 1978.

Amendment 53 November 1998

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-2 Plate Material Cross Reference Heat Slab 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 5.3-23

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-3 Weld Material Cross Reference Weld Identification Type Heat Lot AB - Girthweld E8018NM 492L4871 A422B27AF RAC01NMM 5P6756 0342 RAC01NMM 3P4955 0342 E8018NM 04T931 A423B27AG Ring 21 BA E8018NM 04P046 D217A27A E8018NM 07L669 K004A27A RAC01NMM 3P4966 1214 BB E8018NM 04P046 D217A27A E8018NM 07L669 K004A27A E8018NM C3L46C J020A27A RAC01NMM 3P4966 1214 E8018NM 08M365 G128A27A BC E8018NM 09L853 A111A27A 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 5.3-24

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.3-4 Plate Material Charpy Impact Charpy Expansion Drop Weight RTNDT ft-lb @ +10°F MLE NDT (°F) (°F) Ring 21 PCMK 21-1-1 34, 26, 30/31, 34, 30 30, 34, 24/27, 26, 32 10 28 Heat C1272-1 PCMK 21-1-2 33, 33, 30/30, 34, 35 30, 31, 27/26, 34, 32 20 20 Heat C1273-1 PCMK 21-1-3 38, 48, 55/66, 61, 71 44, 39, 34/53, 52, 56 30 4 Heat C1273-2 PCMK 21-1-4 40, 42, 44/51, 55, 50 32, 36, 38/41, 44, 42 30 0 Heat C1272-2 Ring 22 PCMK 22-1-1 64, 62, 66/52, 52, 55 56, 56, 56/45, 44, 44 30 20 Heat B5301-1 PCMK 22-1-2 70, 72, 71/60, 44, 66 59, 60, 62/56, 41, 51 30 8 Heat C1336-1 PCMK 22-1-3 71, 76, 74/70, 72, 55 61, 60, 60/63, 61, 52 30 20 Heat C1337-1 PCMK 22-1-4 62, 72, 82/73, 67, 73 51, 61, 66/52, 59, 61 50 20 Heat C1337-2 5.3-25

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material Charpy Test Charpy Impact Charpy Expansion Temperature RTNDT Type/Heat/Lot/Control (ft-lb) MLE (°F) (°F) Girth Weld AB E8018NM/492L4871 78, 82, 105, 93, 55, 60, 72, 74, 20a 50 Lot A422B27AF 81 60 RAC01NMM/5P6756b 76, 79, 77, 80, 64, 72, 55, 69, +10 50 Lot 0342 72 60 RAC01NMM/5P6756c 76, 79, 77, 80, 64, 72, 55, 69, +10 50 Lot 0342 72 60 RAC01NMM/3P4955b 49, 63, 47, 49, 39, 48, 36, 43, +10 20 Lot 0342 64 57 RAC01NMM/3P4955c 52, 37, 45, 55, 44, 30, 43, 50, +10 16 Lot 0342 33 32 E8018NM/04T931 86, 84, 102, 63, 69, 58, 60, 57, 20 50 Lot A423B27AG 61 70 Ring 21BA E8018NM/04P046 34, 36, 37, 39, 23, 28, 24, 20, 20a 48 Lot D217A27A 40 24 E8018NM/07L669 50, 50, 54 44, 44, 46 +10a 50 Lot K004A27A RAC01NMM/3P4966c 40, 71, 75, 63, 41, 63, 68, 58, +10a 30 Lot 1214/3482 59 53 RAC01NMM/3P4966b 65, 70, 67, 69, 60, 60, 63, 55, +10a -48 Lot 1214/3482 49 44 Ring 21BB E8018NM/04P046 34, 36, 37, 39, 23, 28, 24, 20, 20a 48 Lot D217A27A 40 24 E8018NM/07L669 50, 50, 54 44, 44, 46 +10a 50 Lot K004A27A E8018NM/C3L46C 35, 39, 40 34, 39, 39 +10a 20 Lot J020827A LDCN-04-005 5.3-26

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material (Continued) Charpy Test Charpy Impact Charpy Expansion Temperature RTNDT Type/Heat/Lot/Control (ft-lb) MLE (°F) (°F) RAC01NMM/3P4966c 40, 71, 75, 63, 41, 63, 68, 58, +10a 30 Lot 1214/3482 59 53 RAC01NMM/3P4966b 65, 70, 67, 69, 60, 60, 63, 55, +10a 48 Lot 1214/3482 49 44 E8018NM/08M365 49, 50, 51 38, 40, 43 +10a 48 Lot G128A27A Ring 21BC E8018NM/09L853 78, 78, 79 60, 62, 62 +10a 50 Lot A111A27A E8018NM/C3L46C 35, 39, 40 34, 39, 39 +10a 20 Lot J020A27A RAC01NMM/3P4966c 40, 71, 75, 63, 41, 63, 68, 58, +10a 30 Lot 1214/3482 59 53 RAC01NMM/3P4966b 65, 70, 67, 69, 60, 60, 63, 55, +10a 48 Lot 1214/3482 49 44 Ring 21BD E8018NM/C3L46C 35, 39, 40 34, 39, 39 +10a 20 Lot J020A27A RAC01NMM/3P4966c 40, 71, 75, 63, 41, 63, 68, 58, +10a 30 Lot 1214/3482 59 53 RAC01NMM/3P4966b 65, 70, 67, 69, 60, 60, 63, 55, +10a 48 Lot 1214/3482 49 44 E8018NM/04P046 34, 36, 37, 39, 23, 28, 24, 20, 20a 48 Lot D217A27A 40 24 Ring 22BE RAC01NMM/3P4966c 39, 38, 38, 82, 68, 64, 63, 81, +10 20 Lot 1214/3481 84 72 RAC01NMM/3P4966b 28, 84, 63, 75, 18, 62, 57, 51, +10 6 Lot 1214/3481 78 57 LDCN-04-005 5.3-27

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-5 Weld Material (Continued) Charpy Test Charpy Impact Charpy Expansion Temperature RTNDT Type/Heat/Lot/Control (ft-lb) MLE (°F) (°F) Ring 22BF E8018NM/04P046 34, 36, 37, 39, 23, 28, 24, 20, 20a 48 Lot D217A27A 40 24 E8018NM/05P018 29, 30, 31, 36, 26, 26, 31, 33, 20a 38 Lot D211A27A 38 35 RAC01NMM/3P4966c 39, 38, 38, 82, 68, 64, 63, 81, +10 20 Lot 1214/3481 84 72 RAC01NMM/3P4966b 28, 84, 63, 75, 18, 62, 57, 51, +10 6 Lot 1214/3481 78 57 Ring 22BG E8018NM/624063 37, 40, 51, 57, 33, 34, 41, 47, 20a 50 Lot C228A27A 70 55 E8018NM/624039 28, 33, 34, 36, 29, 32, 33, 34, 20a 36 Lot D224A27A 42 42 RAC01NMM/3P4966c 39, 38, 38, 82, 68, 64, 63, 81, +10 20 Lot 1214/3481 84 72 RAC01NMM/3P4966b 28, 84, 63, 75, 18, 62, 57, 51, +10 6 Lot 1214/3481 78 57 Ring 22BH E8018NM/04P046 34, 36, 37, 39, 23, 28, 24, 20, 20a 48 Lot D217A27A 40 24 E8018NM/624039 41, 44, 49, 54, 32, 36, 40, 41, 20a 50 Lot D205A27A 58 45 RAC01NMM/3P4966c 39, 38, 38, 82, 68, 64, 63, 81, +10 20 Lot 1214/3481 84 72 RAC01NMM/3P4966b 28, 84, 63, 75, 18, 62, 57, 51, +10 6 Lot 1214/3481 78 57 a Drop weight NDT not applicable. b Tandem wire process. c Single wire process. LDCN-04-005 5.3-28

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 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 0.018 0.60 0.57 -- C1273-2 0.014 0.14 0.23 1.28 0.23 0.018 0.60 0.57 -- B5301-1 0.017 D0.13 0.20 1.34 0.23 0.014 0.50 0.52 -- C1336-1 0.017 0.13 0.21 1.36 0.22 0.013 0.50 0.49 -- C1337-1 0.018 0.15 0.22 1.32 0.21 0.013 0.51 0.50 -- C1337-2 0.018 0.15 0.22 1.32 0.21 0.013 0.51 0.50 -- Peak I.D. EOL (33.1 EFPY) fluence = 7.41 x 1017 n/cm2. LDCN-04-005 5.3-29

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 Table 5.3-7 Vessel Beltline Weld Material Chemistrya Weld Heat/Control Cu C Mn Si S Ni Mo V P 492L4871b 0.03 0.07 1.17 0.32 0.02 0.98 0.51 0.02 0.02 5P6756/0342c 0.08f 0.063 1.27 0.57 0.011 0.936f 0.45 0.006 0.01 5P6756/0342d 0.08f 0.078 1.24 0.53 0.012 0.936f 0.46 0.006 0.01 3P4955/0342d 0.027f 0.035 1.33 0.56 0.011 0.921f 0.52 0.006 0.016 3P4955/0342c 0.027f 0.054 1.28 0.55 0.010 0.921f 0.54 0.007 0.016 04T931b 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 3P4966/3481d 0.025f 0.074 1.38 0.36 0.013 0.913f 0.49 0.006 0.010 3P4966/3481c 0.025f 0.067 1.39 0.38 0.014 0.913f 0.53 0.008 0.011 3P4966/3482c 0.025f 0.059 1.35 0.38 0.013 0.913f 0.50 0.005 0.013 3P4966/3482d 0.025f 0.077 1.42 0.41 0.013 0.913f 0.53 0.005 0.014 CL46Cb 0.02 0.063 0.96 0.32 0.017 0.87 0.53 -- 0.019 08M365b 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. LDCN-08-023 5.3-30

LDCN-06-000 Table 5.3-8 10 CFR 50 Appendix H Matrix Comply Appendix H Yes/No Paragraph Topic or N/A Alternative Actions or Comments I Introduction N/A COLUMBIA GENERATING STATION II.A Fluence 1017n/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, FINAL SAFETY ANALYSIS REPORT however, and can be used to predict behavior of the limiting material. Heat and heat/lot numbers for surveillance specimens were supplied. 5.3-31 See Section 5.3.1.6. II.C.1 Surveillance Specimen Shall be Taken for No Plant-specific Surveillance Program: Noncompliance in that specimens Locations Alongside the Fracture Test Specimens may not have necessarily been taken from alongside specimens required (Section III.B of Appendix G) 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 RTNDT of limiting material is based on Amendment 59 alternative action (see paragraph III.A of Appendix G). II.C.3.b Withdrawal Schedule of Capsules, RTNDT <200°F N/A December 2007 II.C.3.c Withdrawal Schedule of Capsules, RTNDT >200°F N/A

Table 5.3-8 LDCN-13-009 10 CFR 50 Appendix H Matrix (Continued) Comply Appendix H Yes/No Paragraph Topic or N/A Alternative Actions or Comments COLUMBIA GENERATING STATION III.A Fracture Toughness Testing Requirements of Yes Requirements for postirradiation testing of surveillance material are Specimens addressed in the BWRVIP ISP implementation plan (Reference 5.3.4-2). III.B Method of Determining Adjusted Reference Yes Method of determining adjusted reference temperatures found in the Temperature for Base Metal, HAZ, and Weld BWRVIP ISP implementation plan (Reference 5.3.4-2). Metal FINAL SAFETY ANALYSIS REPORT IV.A Reporting Requirements of Test Results Yes Reporting requirements are discussed in the BWRVIP ISP 5.3-32 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 Yes A discussion of the pressure/temperature limits and reporting Limits requirements is found in the BWRVIP implementation plan (Reference 5.3.4-2). Amendment 62 December 2013

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 Table 5.3-9 Reactor Vessel Beltline Minimum Wall Thickness and Diameter Inside diameter with clad = 251 in. (minimum) Wall thickness (ring #22, lower intermediate shell) = 6.188 in. (minimum) Wall thickness (ring #21, 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. LDCN-04-005, 04-033 5.3-33

Amendment 58 December 2005 1400

                                                                                                                        .         ,                               INITIAL RTndt VALUES ARE 28°F FOR BELTLINE, 1300                                                :.                                               34°F FOR UPPER VESSEL,
                                                                                                               ...             I                                              AND 34°F FOR BOTTOM HEAD I

1200 BELTLINE CURVES

                                                                                                        ...                                                       ADJUSTED AS SHOWN:

1100 EFPY SHIFT (°F) I *. 1035 PSIG I I 1035 PSIG 88.6°F 117.1°F I 33.1 35 I PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig)

                                                                                                    .*** I 1000 HEATUP/COOLDOWN 910 PSIG                                 RATE OF COOLANT 900                                   ;                           110°F 20°F/HR 800 PSIG        **

800 68°F 700 600 ACCEPTABLE AREA OF OPERATION TO THE RIGHT OF THIS CURVE 500 f---- BOTTOM HEAD

                                                                                              -                                                              I                                      I 68°F 400 300 FLANGE                              -       UPPER VESSEL 200                                               ..,.,,.....-   REGION                                      AND BELTLINE 80°F                                      LIMITS I~
                                                                                                                                                                  -       BOTTOM HEAD 100                                                                                                          CURVE 0

0 25 50 75 100 125 150 175 200 MINIMUM REACTOR VESSEL METAL TEMPERATURE (°F) Pressure Temperature Limits Columbia Generating Station Testing Curve A Final Safety Analysis Report (Inservice Leak and Hydrostatic Testing Curve) Form No. 960690FH Draw. No. 900547.42 I Rev. I Figure 5.3-1.1 LDCN-04-005

Amendment 58 December 2005 1400 .

                                                                                                                      ...                                  INITIAL RTndt VALUES ARE 28°F FOR BELTLINE, 34°F FOR UPPER VESSEL, 1300
                                                                                                            ..                                           I AND 34°F FOR BOTTOM HEAD I

1200 BELTLINE CURVES 1100 1035 PSIG .

                                                                                                        .                                                        ADJUSTED AS SHOWN:

EFPY SHIFT (°F)

                                                                                                     ...                                       I PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig) 1035 PSIG 109.3°F                                148.1°F                    I        33.1  35 I

1000 HEATUP/COOLDOWN 900

RATE OF COOLANT

                                                                                                            ..                                                                               I
                                                                                                                                                                     -< 100°F/HR I

800 . 790 PSIG 140°F I I 700 ..

                                                                                                  /

600 PSIG 1**: 600 ~ 68°F I ACCEPTABLE AREA OF OPERATION TO THE RIGHT OF THIS CURVE 500 I I 400 BOTTOM 300 - HEAD 68°F 200 I J - UPPER VESSEL AND BELTLINE LIMITS FLANGE REGION ....... 100 - 80°F BOTTOM HEAD IA-- CURVE 0 - 0 25 50 75 100 125 150 175 200 225 250 MINIMUM REACTOR VESSEL METAL TEMPERATURE (°F) Pressure Temperature Limits Columbia Generating Station Curve B Final Safety Analysis Report (Non-Nuclear Heating and Cooldown Curve) Form No. 960690FH Draw. No. 990578.74 I Rev. I Figure 5.3-1.2 LDCN-04-005

Amendment 58 December 2005 1400 INITIAL RTndt VALUES 1300 ARE 28°F FOR BELTLINE, 34°F FOR UPPER 1200 VESSEL, AND 34°F FOR BOTTOM HEAD 1100 I 1035 PSIG 188.1°F I PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig) 1000 BELTLINE CURVE ADJUSTED AS SHOWN: EFPY SHIFT (°F) 33.1 35 900 790 PSIG HEATUP/COOLDOWN 800 180°F RATE OF COOLANT

                                                                                                                                                         -< 100°F/HR I                                  I 700 600 ACCEPTABLE AREA OF OPERATION TO THE 500                                                                            RIGHT OF THIS CURVE I                                  I 400 I312 PSIG I I                                         1-300 BELTLINE AND NON-BELTLINE Minimum Criticality                                                             LIMITS 200       Temperature 80°F                                                                                    I
                                                                             \                V
                                                                                  \    r 100 60 PSIG   I 0

0 25 50 75 100 125 150 175 200 225 250 275 300 MINIMUM REACTOR VESSEL METAL TEMPERATURE (°F) Pressure Temperature Limits Columbia Generating Station Curve C Final Safety Analysis Report (Nuclear Heating and Cooldown Curve) Form No. 960690FH Draw. No. 900547.43 I Rev. I Figure 5.3-1.3 LDCN-04-005

Amendment 57 December 2003 Weld "BG" PCMK 22-1-4 Heat C1337 Slab 2 Weld "BF" PCMK 22-1-3 Heat C1337 Slab 1 PCMK 22-1-2 Heat C1336 Slab 1 PCMK 22-1-1 251" dia. Heat B5301 Slab 1 Weld "BH" Weld "BE" PCMK 21-1-2 Weld "BC" Girth Weld "AB" Heat C1273 Slab 1 Weld "BB" PCMK 21-1-1 405" Elev. Heat C1272 Slab 1 Ring #22

• 360.31" Top Core Elev.

Weld "BA" PCMK 21-1-4 230" Elev. Heat C1272 Slab 2 216.31" Bott. Weld "BD" Core Elev. PCMK 21-1-3 Ring #21 Heat C1273 Slab 2 99 13/16" Elev.

• EOL Limiting Plate 0" Elevation Vessel Beltline Plate and Weld Seam Columbia Generating Station Identification Final Safety Analysis Report Draw. No. 910402.30 Rev. Figure 5.3-2 Form No. 960690 LDCN-02-064

Amendment 53 November 1998 High Water Level Steam Line Alarm, L7 = 568.0 in. Nozzle = 648.0 in. High Water Level

                                   /1 Normal Water Level = 563.55 in.

Trip, L8 = 582.0 in. Low Water Level Scram, L3 = 540.5 in. Feedwater Low Water Level Nozzle = 493.25 in. Alarm, L4 = 559.0 in.

                                          ~

Low Water Level, L2 = 477.5 in.

                                                                                                                                      ......                                           Low Water Level, Top of Active Fuel                                                                                                                                                L1 = 398.5 in.

Zone = 366.31 in.

                                          ~

Bottom of Active Fuel Zone = 216.31 in.

                                          ~                                                                                                                                            Recirc. Inlet Recirc Outlet                                                                                                                                                 Nozzle = 181.0 in.

Nozzle = 172.5 in. .*

                                                                                                                              .**:._-. ;*.*. .*. '.* ...- ::-_:.].:<.*. .*. '.* ...-
                                          ~
                                                                             .**:.*... .**:( ~- . .**:.*. ;.
                                              .:                                                                                                                                       Elevation 0.00 in.
                                                                                         ** : : .! : *~ : *; * *~. *: : , :

Nominal Reactor Vessel Water Level Trip and Columbia Generating Station Alarm Elevation Settings Final Safety Analysis Report Draw. No. 960690.53 Rev. Figure 5.3-3 Form No. 960690

Amendment 53 November 1998 Vessel Inside Clad Radius 11 B .12

                                                                                    +/-.06
                                        +/-.06                                1.38
                                      .75 111     C     .50 Total
                                                                                +/-.06
                            .25                                           .62 Typ.
                                                                          +/-.06
                            .25                                     2.00
                                                                                  +.25                               +.12 B                   +/-.06                 -.00
                                                      .75                 2.00                                 118.31-.25 C
                                                                           +/-.06 2.00
                                                                          +/-.06
                                                                    .62
                                                                                 +/-.06 Full
                                                                                           'j_~~_i 1.18 Penetration Weld (Typ.)

Bracket for Holding Surveillance Capsule Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.54 Rev. Figure 5.3-4 Form No. 960690

Amendment 53 November 1998 REACTOR VESSEL HEAD TOP HEAD COOLING SPRAY NOZZLE DAYER ASSEMBLY LIFTING LUGS STEAM DAY EA ASSEMBLY STEAM DRYER AND SHROUD HEAD ALIGNMENT AND GUIDE BARS STEAM SEPARATOR AND SHROUD HEAD STANDPIPE ASSEMBLY LIFTING LUGS FEEDWATER SPARGER FEEDWATER INLET NOZZLE SHROUD HEAD TOP FUEL GUIDE CORE SPRAY ------1 SUPPLY HEADER SHROUD HEAD FUEL ASSEMBLY HOLD DOWN BOLTS CONTROL ROD CORE SPRAY SPARGER~--- FUEL SUPPORT PIECE IN CORE FLUX -'-- -- - - - FLOW INLET INTO FUEL BUNDLE MONITOR ASSEMBLY

• CORE SHROUD RECIRCULATING WATER '"1C::.,'1----- -- - CORE PLATE ASSEMBLY INLET NOZZLE  :..___,..___ _ _ _ __ VELOCITY LIMITER JET PUMP ASSEMBLY

                                                                -- - - - - - - - - - - RECIRCULATING WATER OUTLET NOZZLE DIFFUSER SEAL RING --------

CONTROL ROD GUIDE TUBE AND SHROUD SUPPORT PLATE CONTROL ROD DRIVE HOUSING Reactor Vessel Columbia Generating Station Final Safety Analysis Report Draw. No. 020002.44 Rev. Figure 5.3-5 Form No. 960690

Amendment 53 November 1998 4 9/16" 3 7 7/16" 1 2 1 1/8" 7/8" 2 3/ 4" 5 6 R 7 1/8" 0 1 01 3 9/ 16 Nozzle, SA-508, CI.II 02 Safe End, SB-166, Inconel "R 6 3/4" 03 Thermal Sleeve Extension, SB-166 04 Thermal Sleeve, SA-336, CI.F8 05 Inconel Overlay 06 Weld Illustration 07 Back-up Ring, SB-168 Feedwater Nozzle Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.56 Rev. Figure 5.3-6 Form No. 960690

Amendment 53 November 1998 1 2 3 Typ. for Weld Forged Tee End Bracket L 6" o o o o o o o o o o o o olSI}I o o o o o o o o o o o o o [g 01 Nozzle, SA-508, CI.II 02 Forged Tee, 304S.S 03 Sparger Header, 304S.S Feedwater Sparger Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.57 Rev. Figure 5.3-7 Form No. 960690

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 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 integrity shall not compromise the ability of the reactor vessel internals to provide a refloodable volume, and

c. The system shall maintain pressure integrity during adverse combinations of loadings and forces occurring during abnormal, accident, and special event conditions.

5.4.1.2 Power Generation 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 recirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reactor vessel jet pumps (see Figure 5.4-1). Each external loop contains one high-capacity variable-speed motor-driven recirculation pump. The motor is powered by an adjustable speed drive (ASD). The external loop also contains two motor-operated gate valves (for pump maintenance). Each pump suction line contains a flow measuring system. The recirculation loops are part of the RCPB and are located inside the drywell structure. The jet pumps are reactor vessel internals. ITheir location and mechanical design are discussed in Section 3.9.5. The important design and performance characteristics of the RRC is shown in Table 5.4-2. 5.4-1

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 The head, flow, torque, net positive suction head (NPSH), BHP, and efficiency curves are shown in Figures 5.4-2, 5.4-3, and 5.4-4. Instrumentation and control description is provided in Sections 7.6 and 7.7. The recirculation system piping and normally flooded section of the reactor vessel is periodically coated with a microscopic layer of noble metals. This coating serves to create a catalytic layering of the noble metal platinum to reduce the hydrogen addition injection rate required to achieve a low electrochemical corrosion potential (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. 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 portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the two external recirculation loops discharges 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 remaining portion of the coolant mixture 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 total 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 idle loop can be kept hot by leaving the loop valves open; this permits the reactor pressure plus the active jet pump head to cause reverse flow in the idle loop. IWhen starting the pump in an idle recirculation 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 internals would require 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 with up to 50 psi differential, while the discharge valve can close with up to 400 psi differential. Both valves are remote manually operated. LDCN-10-010 5.4-2

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 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 pressure conversion. The difference between these two readings is a direct 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 instrumentation for cavitation protection. When preparing for hydrostatic tests, the nuclear system temperature must be raised above the vessel nil ductility transition (NDT) temperature limit. The vessel is heated by core decay heat and/or by operating the recirculation pumps. Connections to the piping on the suction and discharge sides of the pumps provide a means to flush and decontaminate the pump and adjacent piping. The piping low point drain, designed for the connection of temporary piping, is used during flushing or decontamination. Each recirculation pump is driven by an adjustable speed motor and isIequipped with a two-stage mechanical seal cartridge. 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. I 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. 5.4-3

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 The pump drive motor, impeller, and wear rings are 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 availability 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 designed as Seismic Category I equipment. The pump is assumed to be filled with water for the analysis. 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 are supported by hangers to avoid the use of piping expansion loops that 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 circumferential break do not jeopardize drywell integrity. This restraint system provides adequate clearance for normal thermal expansion movement of the loop. The criteria for the protection against 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 covered with thermal insulation having a total maximum heat transfer rate of 65 Btu/hr-ft2 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 all-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. LDCN-15-060 5.4-4

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4.1.3.1 Recirculation System Cavitation Consideration Cavitation Coefficients The recirculation pump, jet pump, and FCV were tested to determine their cavitation coefficients so that prolonged operation in cavitating regimes can be avoided. Equipment Damage Provisions Cavitation interlocks are provided for the recirculation pump and jet pumps; since cavitation produces material damage after 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-term 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 component and repair or replacement if the inspection showed unacceptable damage. Consequently, cavitation could call for increased scheduled outage time for inspection/repair affecting plant availability power generation design goals. The ASD and its GE-FANUC digital control system is a non-safety-related system. The ASD and control system have alarm and protective systems and are provided with on-line video diagnostic displays at the main control room operating benchboard. 5.4.1.4 Safety Evaluation Reactor recirculation system malfunctions that pose threats of damage to the fuel barrier are described and evaluated in Section 15.3. It is shown in Section 15.3 that none of the malfunctions result in significant fuel damage. The RRC has sufficient flow coastdown characteristics to maintain fuel thermal margins during abnormal operational transients. The core flooding capability of a jet pump design plant is discussed in detail in the emergency core cooling system (ECCS) document 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 parts are chosen in accordance with applicable codes. Use of the listed code design criteria ensures that a system designed, built, 5.4-5

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 and operated within design limits has an extremely 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 required and approved. Purchase specifications require that integrity of the pump 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 exceeded during the safe shutdown earthquake (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 loops pump. Design studies determined that the overspeed was not sufficient to cause destruction of the motor; consequently no pump overspeed protection provision was made. A failure modes effects analysis (FMEA) was performed on the block 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 inadvertent closure without a coincident pump trip is covered in the FMEA. 5.4.1.5 Inspection and Testing Quality control methods were used during fabrication and assembly 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 cleaned and flushed before fuel was loaded initially. During the preoperational test program, the RRC 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 applicable to BWR plants. 5.4-6

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4.3 REACTOR COOLANT PIPING The RCPB piping is discussed 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 cracking 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 containment. This limits the reactor depressurization rate to a value which will ensure that the steam dryer and other reactor internal structures remain in place.

b. Withstand the maximum pressure difference expected across the restrictor, following complete severance of a main steam line,

c. Limit the amount of radiological release 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 restrictor assembly consists of a venturi-type nozzle insert welded, in accordance with applicable code requirements, into the main steam line. The flow restrictor 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 maximum 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 differential (unrecovered pressure) of about 10 psig at 100% of rated 5.4-7

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 flow. This design limits the steam flow in a severed line to less 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 upstream 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 closure 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 Regulatory 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 operating conditions, and discharge moisture level. The tests 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 stainless 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 rapidly in applications where soft stainless steel is unaffected. Surface finish has a minor effect on erosion-corrosion. Experience shows that a machined or a ground surface is sufficiently smooth and that no detrimental erosion will occur. 5.4.4.4 Inspection and Testing Because the flow restrictor forms a permanent part of the main steam line piping and has no moving components, no testing program is planned. Only very slow erosion will occur with LDCN-05-009 5.4-8

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 time, and such a slight enlargement will have no safety 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 and the exit velocities are 600 to 900 ft/sec. However, calculations show that, even if the erosion rates are as high as 0.003 in. per year, after 60 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 lines within the time established by design-basis accident analysis to limit the release of reactor coolant,

b. Close the main steam lines 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 close independently the redundant isolation valves in the individual steam lines,

e. Use local stored energy (compressed air and/or springs) 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 normal operating conditions to demonstrate that the valves will function.

LDCN-15-052 5.4-9

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 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 and the other is just outside the primary containment. Figure 5.4-9 shows an MSIV. Each is a 26-in. Y-pattern, globe valve. Rated steam flow rate through each valve is 3.85 x 106 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 sufficient to give flow areas 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 valve 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 helps prevent debris blockage. The pressure drop at 105% of rated flow is 7 psi maximum. The 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 the valve is fully open. Attached to the upper end of the stem is an air cylinder that opens 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 support 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 pneumatic 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 operator 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 backup 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. 5.4-10

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Each valve is designed to accommodate saturated steam at plant operating conditions, with a moisture content of approximately 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 operating conditions to accommodate plant overpressure conditions. In the worst case if the main steam line should rupture downstream 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 estimated to be 100 cycles per year during the first year and 50 cycles per year thereafter. In addition to minimum wall thickness required by applicable codes, 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% humidity, in a radiation field of 15 rad/hr gamma and 25 rad/hr neutron plus gamma, continuous for design life. IThe inside valves are not continuously exposed to maximum conditions, particularly during reactor shutdown, and valves outside the primary containment and shielding are in ambient 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 are designed to remain closed 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 100 days at 20 psig maximum.

To resist sufficiently the response motion from the SSE, the main steam line valve installations are designed as Seismic Category I equipment. The valve assembly is manufactured to withstand the SSE forces applied at the mass center of the extended mass of the valve operator, assuming the cylinder/spring operator is cantilevered from the valve body and the valve is located in a horizontal run of pipe. The stresses caused by horizontal and vertical seismic forces are assumed to act simultaneously. The stresses in the actuator supports caused by 5.4-11

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 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 complete, sudden steam line break outside the containment is described in Chapter 15, Accident Analyses. The shortest closing 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 valve to close in a few seconds after a steam line break, under conditions of high pressure differentials and fluid flows with fluid mixtures ranging from mostly steam to mostly water, has 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 hydrostatic, leakage, and stroking tests, as a minimum, were performed by the valve manufacturer in shop tests:

a. To verify valve capability to close at settings between 3 and 10 sec,* each valve was tested at rated pressure (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 cm3/hr/in. of nominal valve size. In addition, an air 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 valve 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 operation for 3 sec minimum, 5 sec maximum.

5.4-12

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001

c. Each valve was hydrostatically tested in accordance with the requirements of the applicable edition and addenda of the ASME Code. During valve fabrication, extensive nondestructive tests and examinations were conducted. Tests included radiographic, liquid penetrant, or magnetic particle examinations of castings, forgings, welds, hardfacings, and bolts; and

d. The spring guides and guiding of the spring 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 cylinder 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 tested 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 control systems are separated physically. Electrical equipment that is associated with the isolation valves and operates in an accident environment is limited to the wiring, solenoid 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 operability during plant operation and refueling outage. The test provisions are listed below. During refueling outage the MSIVs can be functionally tested, leak tested, and visually inspected. The MSIVs can be tested and exercised individually to the 90% open position, because the valves still pass rated steam flow when 90% open. The MSIVs can also be tested and exercised individually to the fully closed position if reactor power is reduced sufficiently to avoid scram from reactor overpressure or high flow through the steam line flow restrictors. Leakage from the valve stem packing will become suspect during reactor operation from measurements of leakage into the drywell, or from observation or similar measurements in the steam tunnel. l The leak rate through the pipe line valve seats (pilot and poppet seats) can be measured accurately during shutdown by the procedure described in the following: 5.4-13 l

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001

a. With the reactor at approximately 125°F and normal water level and decay heat being removed by the RHR system in the 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 isolation 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 valve 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. I Also, the inboard MSIV containment instrument air (CIA) supply pressure boundary from the accumulator 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 within a 30-sec time interval. IThe RCIC water discharge into the reactor vessel varies between a temperature of 40°F up to and 5.4-14

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 t j 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 electrical power source of high reliability, which permits operation with either onsite power or offsite power. The steam supply to the RCIC turbine is automatically isolated 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 containment isolation valve arrangements are described in Section 6.2. The RCIC system as noted in Table 3.2-1 is designed commensurate with the safety importance of the system and its equipment. Each component 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 throughout the life of the plant. In addition to the automatic operational features, provisions have been included for remote-manual startup, operation, and shutdown of the RCIC system, provided initiation or shutdown signals have not been actuated for startup and operation. The RCIC system is physically located in a different quadrant of the reactor building and uses different divisional power (and separate electrical routings) than the HPCS system. The system operates for the time intervals and the environmental conditions specified in Section 3.11. LDCN-14-030 5.4-15

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 divert the steam to the main condenser, and the feedwater system will supply the makeup water required to maintain reactor vessel inventory. In the event the reactor vessel is isolated and the feedwater supply is unavailable, 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 continued 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 the reactor and exhausts to the suppression pool. The turbine-driven pump takes suction from the condensate storage tank (CST) during normal modes of operation and injects into the reactor vessel. Condensate storage tank freeze protection is discussed in Section 9.2.6. Since the CST is a covered tank, the water supply is not affected by dust storms. I 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. I This automatic switchover feature for RCIC consists of two Class 1E level switches mounted on a standpipe in the pump suction line. This standpipe is located on the condensate supply line inside the reactor building 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 designed, fabricated, and installed to Seismic Category I, Quality Class I, and ASME Section III, Class 2 standards. The piping from the reactor building/service building interface to the RCIC system is Seismic Category I; each circumferential buttweld has been radiographically examined per ASME Section III, NC-5230, and a chemical analysis has been performed 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 approximate four-ft margin while the switchover 5.4-16

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 I occurs, thus ensuring a water supply for continuous operation of the RCIC system. The CST switchover level of 448 ft 3 in. provides an additional submergence of 2 ft (above the top of the CST outlet pipe), which is more than adequate to preclude vortex formation in the CST since less than 6 in. of additional submergence for vortex prevention is required for RCIC. The available NPSH for worst-case operating conditions (i.e., 625 gpm rated flow, maximum water temperature) was calculated for the RCIC pump suction from the suppression pool and the CST. Using the conservative water temperature 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. IIn 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 suppression pool has also been evaluated for vortex formation. The RCIC system has adequate NPSH and will not vortex under the conditions it would be expected to operate. During RCIC operation, the suppression pool acts as the heat sink for steam generated by reactor decay heat. This will result in a rise in pool water temperature. Heat exchangers in the RHR system are used to maintain pool water temperature within acceptable limits by cooling the pool water directly. The RCIC turbine discharges into a 10-in. exhaust pipe (see Figure 5.4-11), which has been installed as a sparger to prevent flow-induced oscillations due to steam bubble formation and collapse in the suppression pool. Also, a vacuum breaker system has been installed close to the RCIC turbine exhaust line suppression pool penetration to avoid siphoning water from the suppression pool into the exhaust line as steam in the line condenses during and after turbine operation. The vacuum breaker line runs from the suppression pool air volume to the RCIC exhaust line through two normally open motor-operated gate valves and two swing check valves arranged to allow air flow into the exhaust line and to preclude 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 turbine 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 interface system and subsystems 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 hydraulic requirements, and LDCN-04-029 5.4-17

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019

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 activates 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 activates when fully open and clears RCIC-V-45 (F045) permissive so RCIC-V-45 (F045) can open;

d. RCIC-V-45 (F045) limit switch activates when RCIC-V-45 (F045) is not fully closed and energizes 15-sec time delay for 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 openIand 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 and 113 (F080 and F086);

h. RCIC high turbine exhaust pressure, low pump suction pressure, low discharge header pressure(1), 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 the mechanical trip at the turbine and the trip throttle valve. The former is reset at the turbine and then the later is reset in the control room; (1)

NOTE: This equipment protection feature has been disabled by placing the RCIC-RMS-PIS1 switch in the OVERRIDE position. LDCN-17-022 5.4-18

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

j. Valves RCIC-V-8 (F008), RCIC-V-63 (F063), and RCIC-V-76 (F076) automatically isolate on low reactor pressure, high turbine exhaust line pressure, high ambient temperature in RCIC equipment areas (leak detection) and high turbine steam supply flow rate I(>300% - break detection). A setpoint of 300%

for break isolation provides sufficient operating margin to prevent inadvertent isolations due to startup transients and yet is low enough to detect large pipe breaks. Small breaks are detected by the leak detection system. Steam condensing supply valve RCIC-V-64 (F064) has been lock closed as a part of the steam condensing mode deactivation. Note, the key-locked switches for RCIC-V-8 (F008) and RCIC-V-63 (F063) do not prevent automatic isolation of these valves. The key-locked switches 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 RCIC-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 (F019). 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 turbine and accessories,

b. One 100% capacity pump assembly and accessories, and

c. Piping, valves, and instrumentation for

1. Steam supply to the turbine,

2. Turbine exhaust to the suppression pool, 5.4-19

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

3. Makeup supply from the CST to the pump suction,

4. Makeup supply from the suppression pool to the pump suction, and

5. Pump discharge to the head cooling spray nozzle, including 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 Design Parameters. Design parameter for the RCIC system components are listed below. See Figure 5.4-11 for cross reference of component numbers listed below:

a. RCIC pump operation RCIC-P-1 (Reference to Figures 5.4-11 and 5.4-13)

(C001) 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 HP condition LP condition RCIC-DT-1 (C002)

Reactor pressure (saturation 1225 psia 165 psia temperature) Steam inlet pressure 1210 psia 150 psia Turbine exhaust press 15 to 25 psia 15 to 25 psia Design inlet pressure 1265 psia + saturated temperature Design exhaust pressure 165 psia + saturated temperature 5.4-20

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

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 through 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 requirements 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 pressure and open in thermal over-pressure conditions in the RCIC discharge header 5.4-21

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 Capable of maintaining constant water pressure control downstream pressure of 75 psia valve RCIC-PCV-15 (F015) through lube oil cooler Pump discharge header relief 1500 psig 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 Qualified 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) 5.4-22

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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) turbine exhaust pressure and RCIC-V-113 (F086)

e. Rupture disc Assemblies Utilized for turbine 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 pressure valve makeup is 135,000 gal.

g. Piping RCIC water temperature The maximum water temperature range for continuous system operation will not exceed 140°F. However, due to potential short-term operation at higher temperatures, piping design 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.

5.4-23

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013

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 and trip throttle valves Design pressure 1250 psig Design temperature 575°F LDCN-11-039 5.4-24

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001

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 materials and fabrication meets ASME Section III, Class 2 requirements. The N stamp is not be applied since 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 cylindrical, 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, therefore, require relief devices or some other basis for addressing overpressure protection. The design pressure of the other major pipe lines is equal to the vessel design pressure and subject to the normal overpressure protection system. In addition, the RCIC discharge header LDCN-00-056 5.4-25

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 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 bases 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 RCIC 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 vented 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 normally 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 downstream of RCIC-PCV-15 (F015)

In the standby condition this line is separated from reactor 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 relief 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. LDCN-00-056 5.4-26

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4.6.2.3 Applicable Codes 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 and those for the condensate 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 necessary, the power supply for the system is taken from immediately available energy sources of high 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 starts 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 different 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 system operation. Separate detection initiation logic is used for each system.

d. Both systems are designed to meet appropriate 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 discharging 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. I 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:

LDCN-04-027 5.4-27

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

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. Closure of either or both of these valves requires operator action to properly sequence their opening.

An alarm sounds when either of these valves leaves the fully open position.

3. Bypassed or other deliberately rendered inoperable 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 manufacturers 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. I Operating procedures require throttling open the outboard isolation valve RCIC-V-8 to remove any condensate trapped 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 valve, and then opening the inboard isolation valve RCIC-V-63. I 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 operation 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 this manner without its keepfill function.

5.4.6.2.5 System Operation 5.4.6.2.5.1 Automatic 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 automatic operation, ITechnical Specifications operability requirements ensure that all necessary components are available to perform their required functions. In addition, the following are periodically verified:

a. The flow controller has the correct flow setpoint and is in automatic mode; LDCN-04-027 5.4-28

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015

b. Each RCIC manual, power-operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured 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 operation 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 adjusting flow to the amount necessary to maintain vessel level. Subsequent starts of RCIC will occur automatically if the water level decreases to the low level initiation point (Level 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 closing 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 will 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 switches 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 Operation. This operating mode (described in Section 5.4.6.2.4) is conducted by manual operation of the system. 5.4.6.2.5.3 Steam Condensing (Hot Standby) Operation. The 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 supply 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 systems capability to bring the reactor to cold shutdown. LDCN-14-030 5.4-29

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 5.4.6.2.5.4 Manual Actions. The RCIC system will automatically initiate and inject 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 operators can manually initiate the system prior to reaching the low level. 5.4.6.2.5.5 Reactor Core Isolation 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 the 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 RCIC system is presented in Chapter 14. Regulatory Guide 1.68 compliance is described in Section 1.8. 5.4.6.5 Safety Interfaces The balance-of-plant/GE nuclear steam supply system safety interfaces for the RCIC system are (a) preferred water supply from the CST, (b) all associated wire, cable, piping, sensors, and valves that lie outside the nuclear steam supply system scope of supply, and (c) air supply for testable check and solenoid-actuated valve(s). 5.4.7 RESIDUAL HEAT REMOVAL SYSTEM 5.4.7.1 Design Bases The RHR system is comprised of three independent loops. Each loop contains its own motor-driven pump, piping, valves, instrumentation, and controls. Each loop has a suction source from the suppression pool and is capable of discharging water to the reactor vessel via a separate nozzle, or back to the suppression pool via a separate suppression pool return line. In addition, the A and B loops have heat exchangers 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 cooling (FPC) system (see Section 9.1.3 for details). A spool piece intertie was also used to provide a preoperational flushing 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 condensing mode has been eliminated. LDCN-08-000 5.4-30

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4.7.1.1 Functional Design Basis The RHR system is designed to restore and maintain the coolant inventory in the reactor vessel and to provide primary system decay heat removal following reactor shutdown for both normal and postaccident conditions. The primary design operating modes associated with performing these functions are briefly described as follows:

a. Low-pressure coolant injection (LPCI) mode - The RHR system automatically initiates into this mode and 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 systems LPCI mode operates in conjunction with the other ECCS to provide adequate core cooling for 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 vessel 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 cooling can be provided following a LOCA at uprated power conditions;

b. Suppression pool cooling (SPC) and containment spray cooling (CSC) modes -

The RHR systems SPC and CSC modes provide heat removal from the suppression pool and containment by pumping suppression pool water through the systems heat exchangers and discharging the water either directly back to the suppression pool (i.e., in the SPC mode) or discharging the water to the wetwell and drywell spray spargers (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 pressures following major transients. Suppression pool cooling is manually initiated by the operator; however, at least one RHR loop is placed in the SPC mode to maintain suppression pool temperature <110°F. IThe drywell spray function removes radioactive fission products from the containment atmosphere during a LOCA and is manually initiated within 15 minutes after the event occurs; LDCN-05-009 5.4-31

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

c. Shutdown cooling mode - The RHR systems normal shutdown 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 systems alternate shutdown cooling mode is utilized during normal plant operation and design basis events when the normal shutdown cooling mode is not available to remove reactor core decay and sensible heat. This heat removal function is safety related, initiated manually and pumps suppression pool water into the core and allows the water to return to the suppression pool through the SRVs. The design objective of this mode (as established by Regulatory 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 removed, the RHR system is designed to be capable of being aligned to assist the 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 the 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 vessel depressurization to below the RHR system shutoff discharge pressure. This mode cools the pumps by providing a pump flow return line to the suppression pool that allows sufficient pump cooling flow to return to the pool until flow in the main discharge line is sufficient to provide adequate pump cooling. When flow in the main discharge lines is sufficient for cooling of the pumps, motor-operated valves in the minimum flow bypass line to the suppression pool automatically close so that all of the systems 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 suppression pool and all other 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 following depressurization.

5.4-32

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Until adequate flow is established, the RHR pumps are cooled automatically by flow through the minimum flow valves;

h. Reactor steam condensing mode - The reactor steam condensing 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 inhibit shutdown cooling mode alignment whenever reactor pressure is above the design pressure of the low pressure 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 pressure. The minimum pressure above which LPCI protection is required is below the design pressure 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 can 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 approximately 460 psig, which also provides protection for the low pressure portions of the RHR system. In addition, 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 detection 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 plus 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 overpressurization between RHR-V-8 and RHR-V-9.

5.4-33

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 The relief valves protecting the RHR system are listed below (see Figure 5.4-15): Nominal Required Setpoint Capacity Design Relief Valve (psig) (gpm) Piping Location 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 220 from recirculation pipe 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 125 radwaste RHR-RV-36* All RHR relief valves are purchased to ASME Section III, Class 2, requirements to match the requirements of the piping they are protecting. As such, the setpoint 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 hydrodynamic loads are not considered a potential problem in RHR relief valve piping. Redundant interlocks prevent opening valves to the low-pressure 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 addition a high-pressure check valve will close to prevent reverse flow 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 higher 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. 5.4-34

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 The shutdown cooling suction piping 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 overpressurization of the lower pressure piping. With the RHR pumps normally lined 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. IA 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 using 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 failure 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 located in series and has pressure interlocks to prevent opening at high reactor vessel pressure. No single active failure or operator error will result in overpressurization of the lower pressure piping. The head spray piping has three swing check valves 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. ITwo of the swing check valves have air operators but are only capable of opening the testable check valve 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 thermal expansion or from leakage past the head spray, shutdown injection, and LPCI isolation valves 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. 5.4-35

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4.7.1.4 Design Basis With Respect to General Design Criterion 5 The RHR system for this unit does not share equipment or structures 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 room. IThe 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 suction 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 failure 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 and GDC 34. This mode is safety related, Quality Class 1, Seismic Category 1, redundant and single failure proof. Since the normal Shutdown Cooling Mode of RHR is preferred 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. I With the exception of the shutdown suction including the reactor recirculation loop suction and discharge valves, and shutdown return, the entire RHR system is safety grade and redundant, is part of the ECCS and containment cooling systems, and is designed with the flooding protection, piping protection, power separation, etc., required of such systems. See Section 6.3 for an explanation of the design bases for ECCS systems. I 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 may 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 cooling mode, if vessel depressurization 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. 5.4-36

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Low-pressure liquid flow test results are presented in NEDE-24988-P. This test program adequately demonstrated the ability to use SRVs in the alternate shutdown cooling mode. I Following reactor depressurization (i.e., 100°F/hr), an alternate shutdown coolant flow rate of 2600 gpm would be requiredIto bring the reactor to a shutdown condition. This flow capacity can be achieved by using one ADS 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 resistance head is 550 ft using one SRV 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 Protection from Physical Damage The RHR system is designed to the requirements of Table 3.2-1. With the exception of the common shutdown cooling line, redundant components of the RHR system are physically located in different quadrants of the reactor building, and are supplied from independent and redundant electrical divisions. Further discussion on protection 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 instrumentation is presented in Section 7.3.1.1.1. A process diagram and process 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 valves above the suction line design pressure, or above the discharge line design pressure with the pump 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). 5.4-37

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 The normal shutdown cooling mode of RHR loop B can be aligned to return a portion of the cooling flow back into the reactor vessel via the RCIC head spray nozzle. The LPCS system may be cross tied with the RHR system to provide 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 vessel 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 proper system function. 5.4.7.2.2 Equipment and Component Description

a. System main pumps The RHR main system pumps are motor-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). IDesign pressure for the pump suction structure is 220 psig with a temperature range from 40°F to 360°F. Design pressure for the pump discharge structure is 500 psig. I 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 steel 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) hydrostatic tests of pressure 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) functional tests, (c) periodic 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 reduced coincident with reduced outage times).

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COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

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 experience 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 shell side and 7400 gpm (rated) on the tube side (service water side). Rated inlet temperature is 95°F tube side.

  .Design

___ temperature__ _ _ range of both shell and 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, based on compliance with the ASME III, Class 2, code. Design pressure is 500 psig on both sides. 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 conventional gate, globe, and check valves designed for nuclear service. The injection valves, 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 valves 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. I The minimum flow valve controls meet IEEE-279 requirements. I l To prevent loss of vessel inventory to the suppression pool when operating shutdown cooling or RHR/FPC assist mode, the minimum flow valve is not 5.4-39

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 d. l permitted to open. Administrative controls ensure that the valve is returned to normal status following the conclusion of shutdown cooling. Restricting orifices J 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. A restricting orifice is necessary in the system test line to prevent excessive runout during SPC and test modes and in the main discharge line to prevent excessive runout for LPCI C system. 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 location 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 sections described in Figure 5.4-16.

The route includes suppression pool suction strainers, suction piping, RHR pumps, discharge piping, injection valves, 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 pool return lines. Containment spray components are the same 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 Codes and Classifications See Section 3.2. LDCN-16-004 5.4-40

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 5.4.7.2.5 Reliability Considerations The RHR system has included the redundancy requirements of Section 5.4.7.1.5. Two redundant loops have been provided to remove 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 capable 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 and cooling water flow established 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 RHR-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 valves to radwaste are then closed and the RHR pump is started. The cooldown rate is controlled by adjusting the heat exchanger outlet valve and heat exchanger bypass valve to achieve the desired temperature of the water returning to the reactor vessel while maintaining the total flow at approximately 7450 gpm. If prewarming valves were accidentally left open following initiation 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 level specified in the Technical 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 RPV 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 automatically 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 I l Thermal performance of the RHR heat exchangers is based on the capability to remove enough sensible and decay heat from the reactor system to reduce the bulk reactor coolant temperature 5.4-41

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 to 125°F within 25 hours after control rod insertion, 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 temperature. 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 With 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) clean steam systems that use the main condenser as the heat sink when nuclear steam pressure is insufficient to maintain steam air ejector performance, (b) the fouling of the heat exchangers, (c) operator use of one or two cooling loops, (d) coolant water temperature, and (e) system flushing time. Since the exchangers are designed for the fouled condition with relatively high service water temperature, 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 conditions 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 residual 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 each 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, pressures, cooldown rates, and reaction times required to perform all system functions as specified 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 requirements as specified above using both the offsite power and standby emergency power. Preliminary heat exchanger performance was evaluated by operating in the pool cooling mode, but a vessel cooldown was used for the final check due to the small temperature differences available with pool cooling (see Section 14.2). 5.4-42

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 5.4.8 REACTOR WATER CLEANUP SYSTEM The reactor water cleanup (RWCU) system is an auxiliary system, a small part of which is part of the RCPB up to and including the outermost containment isolation valve. The other portions of the system are not part of the RCPB and are isolated 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 system from the RCPB, and

d. Prevents loss of liquid reactivity control material from the reactor vessel during standby liquid control (SLC) system operation.

5.4.8.1.2 Power Generation 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 piping and vessel during periods when the main recirculation pumps are unavailable,

d. Minimizes cleanup system heat loss, and

e. Enables the major portion of the RWCU system to be serviced during reactor operation.

5.4-43

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 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. IThe system takes suction from the inlet 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 operated 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 system is located in the reactor building. This equipment includes the pumps and the regenerative and nonregenerative heat exchangers. Filter-demineralizers and supporting equipment are located in the radwaste building. The entire system is connected by associated valves and piping; controls and instrumentation provide proper system operation. IDesign data for the major pieces of equipment are presented in Table 5.4-5. Reactor water is cooled in the regenerative and nonregenerative heat exchangers, filtered, demineralized, and returned to the reactor pressure vessel through the shell side of the regenerative heat exchanger. The system pump is capable of producing a nominal 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-demineralizers 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 cools the process further by transferring 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. I 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. IEach strainer and filter-demineralizer vessel has a control room alarm that is energized by high differential pressure. Further increase in differential pressure will isolate the filter-demineralizer. IThe backwash and precoat cycle for a filter-demineralizer is automatic to prevent operational errors such as inadvertent openings of valves that would initiate a backwash or contaminate reactor water with resins. The filter-demineralizer piping 5.4-44

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 configuration is arranged to ensure that transfers are complete and crud traps are avoided. A bypass line is provided around the filter-demineralizers. 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 provided in the common influent header and in each effluent line of the filter-demineralizers for continuous indication and recording of system conductivity. High conductivity is annunciated in the control room. IThe 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 the SLC system and high nonregenerative heat exchanger outlet water temperature. I 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 treatment system and FPC and cleanup system maintains reactor water quality during all reactor operating modes (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 temperature design conditions are shown in Table 5.4-5. The process containing components (piping, valves, vessels, 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 heat 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. 5.4-45

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 5.4.8.4 Demineralizer Resins Regulatory Guide 1.56 compliance is described in Section 1.8. 5.4.8.5 Reactor Water Cleanup Water Chemistry 5.4.8.5.1 Analytical Methods Chemical analyses methods used for determination of conductivity, pH, and chloride content of primary coolant are as follows: Conductivity measured in accordance to ASTM-D-1125 pH measured in accordance to ASTM-D-1293 Chloride determined by ion chromatography in accordance with the vendors operating manual 5.4.8.5.2 Relationship of Filter-Demineralizer Condition to Water Chemistry The filter-demineralizer condition during normal power operation is related to inlet conductivity and water volume processed through the unit. The inlet conductivity is related to impurity concentration through the equivalent conductance of the constituents of the process fluid. System flow rates are measured and recorded to determine quantity of water processed. Periodically, an On-Line NobleChem application will be performed, which injects platinum into the reactor coolant, resulting in a microscopic layer of the noble metal to be deposited onto the reactor internals. Conductivity instrumentation is calibrated against laboratory flow cells in accordance with ASTM-D-1125. The alarm setpoints for the conductivity instrumentation 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 discussed 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 data indicates resin breakthrough or the allowable pressure drop is exceeded, the filter-demineralizer is regenerated. LDCN-10-010 5.4-46

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 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 feedwater 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 radioactivity in excess of the guideline values in published regulations, and

b. With suitable accesses to permit IST and inspections.

5.4.9.2 Power Generation 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 reactor 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 reactor vessel. Each 24-in. line includes three containment isolation valves consisting of one check valve inside the drywell and one motor-operated gate valve and one check valve outside the containment. The I design pressure and temperature of the feedwater piping between the reactor and maintenance valve is 1300 psig and 575°F. I The Seismic Category I design requirements are placed on the feedwater piping from the reactor through the outboard isolation valve and connected piping up to and including the first isolation valve in the connected piping. The materials used in the piping are in accordance with the applicable design code and supplementary requirements described in Section 3.2. The feedwater system is further described in Sections 7.7.1, 7.7.2, and 10.4.7. LDCN-04-002 5.4-47

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 5.4.9.4 Safety Evaluation Differential pressure on reactor internals under the assumed accident condition of a ruptured steam line is limited by the use of flow restrictors and by the use of four main steam lines. All main steam and feedwater piping 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 with 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 internal pressure/temperature loading 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. Compliances with ASME Codes are discussed in Section 5.2.1. 5.4.12.2 Description Line valves furnished are manufactured standard types, designed 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 components, are designed to endure the 40-year plant life under the environmental conditions applicable to the particular system when appropriate maintenance is periodically performed. 5.4-48

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Power operators have been sized to operate successfully under the maximum differential pressure determined in the design specification 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 examination requirements of Section III of the ASME Code. To minimize internal and external leakage past seating surfaces, maximum allowable leakage rates are stated in the design specifications 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 exercised when appropriate. Motors used with valve actuators are furnished in accordance with applicable industry standards. Each motor actuator has been assembled, factory tested 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 close) 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 which could prevent the actuator from unseating the valve (Generic Letter 95-07 Program). Tests verified no mechanical damage to valve components during full stroking 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.

5.4-49

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 Preoperational and operational testing performed on the installed valves consists of total circuit check out and performance tests to verify design basis capability including speed requirements at specified differential pressure. 5.4.13 SAFETY AND RELIEF VALVES A listing of the safety and relief valves is provided in Table 5.4-6. 5.4.13.1 Safety Design Bases Overpressure protection is provided at isolatable portions of systems in accordance with the rules set forth in the ASME Code, Section III for Class 1, 2, and 3 components. 5.4.13.2 Description Pressure relief valves are designed and constructed in accordance with the same code class as that of the line valves in the system. The design criteria, design loading, and design 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 provisions are to be made for inline testing of pressure relief valves, other than set pressure and leakage. Certified set pressures and relieving capacities are stamped 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 stamped tag will be attached indicating the new pressure. 5.4.14 COMPONENT AND PIPING SUPPORTS Support elements are provided for those components included in the RCPB and the connected systems. 5.4-50

COLUMBIA GENERATING STATION Amendment 56 FINAL SAFETY ANALYSIS REPORT December 2001 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 analysis for Class 1, 2, and 3 component and piping supports within the ASME boundary of jurisdiction conform with the appropriate requirements of ASME Section III, Subsection NF. Outside the ASME boundary steel structures conform to the AISC manual of Steel Construction. Spacing and size of pipe support elements were based on the piping analysis performed in accordance with ASME Section III and further described in Section 3.7. Standard manufacturer hanger types were used and fabricated of materials per ASME Section III, Subsection NF. 5.4.14.2 Description The use and location or rigid-type 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 support system has been rigorously evaluated with all due consideration for extreme loading conditions and satisfaction of conservative design allowable stresses. This demonstration of structural adequacy combined with a comprehensive testing and inspection program (see Section 5.4.14.3) constitutes the safety evaluation basis for these passive support elements. 5.4.14.3 Inspection and Testing After completion of the installation and balancing of a support system, all hanger elements were visually examined to ensure that they were in correct adjustment to their cold setting position. On initial hot startup operations, thermal growth was observed and it was confirmed that all spring-type hangers and 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 and 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. 5.4-51

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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., Effectiveness of Core Standby Cooling Systems for General Electric Boiling Water Reactors, 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 Department, 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 Water Reactor Power Uprate - Volume I, NEDC-31984P, General Electric Company. 5.4-5 Reactor Core Isolation Cooling System (RCIC), Design Basis Document, Section 315. LDCN-06-054 5.4-52

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 Table 5.4-1 Reactor Coolant Pressure Boundary Pump and Valve Descriptiona Location Active/Inactive Valve Reference Figure Valve Description RHR vessel in Active RHR-V-41A 5.4-15 Active RHR-V-41B 5.4-15 Active RHR-V-41C 5.4-15 (E12F041A, B, C) Active RHR-V-42A 5.4-15 Active RHR-V-42B 5.4-15 Active RHR-V-42C 5.4-15 (E12F042A, B, C) Inactive RHR-V-111A 5.4-15 Inactive RHR-V-111B 5.4-15 Inactive RHR-V-111C 5.4-15 (E12F111A, B, C) RHR/recirculation Active RHR-V-50A 5.4-15 line in Active RHR-V-50B 5.4-15 (E12F050A, B) Active RHR-V-53A 5.4-15 Active RHR-V-53B 5.4-15 (E12F053A, B) Inactive RHR-V-112A 5.4-15 Inactive RHR-V-112B 5.4-15 D (E12F112A,B) Inactive RHR-V-123A 5.4-15 Inactive RHR-V-123B 5.4-15 (E12F099A, B) Head spray Active RHR-V-19 (E12F019) 5.4-15 Active RHR-V-23 (E12F023) 5.4-15 RHR shutdown Active RHR-V-8 (E12F008) 5.4-15 cooling suction Active RHR-V-9 (E12F009) 5.4-15 Inactive RHR-V-113 (E12F113) 5.4-15 RCIC vessel out Active RCIC-V-8 (E51F008) 5.4-11 Active RCIC-V-63 (E51F063) 5.4-11 Active RCIC-V-64 (E51F064) 5.4-11 Active RCIC-V-76 (E51F0076) 5.4-11 LDCN-98-113 5.4-53

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 Table 5.4-1 Reactor Coolant Pressure Boundary Pump and Valve Descriptiona (Continued) Location Active/Inactive Valve Reference Figure (Nuclear boiler) Reactor vessel head Inactive MS-V-1 (B22F001) 10.3-2 Inactive MS-V-2 (B22F002) 10.3-2 Feedwater in Active RFW-V-10A 10.3-2 Active RFW-V-10B 10.3-2 (B22F010A, B) Inactive RFW-V-11A 10.3-2 Inactive RFW-V-11B 10.3-2 (B22F011A, B) Active RFW-V-32A 10.3-2 Active RFW-V-32B 10.3-2 (B22F032A, B) Active RFW-V-65A 10.3-2 Active RFW-V-65B 10.3-2 (B22F065A, B) Safety relief Active MS-RV-2A 10.3-2 Active MS-RV-3A 10.3-2 Active MS-RV-2D 10.3-2 Active MS-RV-2C 10.3-2 Active MS-RV-1B 10.3-2 Active MS-RV-2B 10.3-2 Active MS-RV-3C 10.3-2 Active MS-RV-3B 10.3-2 (B22F013A-H) Active MS-RV-1A 10.3-2 Active MS-RV-1D 10.3-2 Active MS-RV-1C 10.3-2 Active MS-RV-4C 10.3-2 Active MS-RV-5C 10.3-2 (B22F013J-N) Active MS-RV-4D 10.3-2 (B22F013P) Active MS-RV-4B 10.3-2 Active MS-RV-4A 10.3-2 LDCN-98-113 5.4-54

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.4-1 Reactor Coolant Pressure Boundary Pump and Valve Descriptiona (Continued) Location Active/Inactive Valve Reference Figure (B22F013R-S) Active MS-RV-5B 10.3-2 Active MS-RV-3D 10.3-2 (B22F013U-V) Reactor water Inactive RWCU-V-103 5.4-22 cleanup system (G33F103) Line suction Active RWCU-V-1 (G33F001) 5.4-22 Active RWCU-V-4 (G33F004) 5.4-22 Inactive RWCU-V-100 (G33F100) 5.4-22 Inactive RWCU-V-101 5.4-22 Inactive (G33F101) Inactive RWCU-V-102 5.4-22 (G33F102) RWCU-V-106 5.4-22 (G33F106) Line discharge Active RWCU-V-40 5.4-22 (G33F040) Drain to condenser Active MS-V-16 10.3-2 Active (B22F016) MS-V-19 10.3-2 (B22F019) MSIV Active MS-V-22A 10.3-2 Active MS-V-22B 10.3-2 Active MS-V-22C 10.3-2 Active MS-V-22D 10.3-2 Active (B22F022) Active MS-V-28A 10.3-2 Active MS-V-28B 10.3-2 Active MS-V-28C 10.3-2 MS-V-28D 10.3-2 (B22F028) 5.4-55

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Table 5.4-1 Reactor Coolant Pressure Boundary Pump and Valve Descriptiona (Continued) Location Active/Inactive Valve Reference Figure Drain to condenser Active MS-V-67A 10.3-2 (Recirculation) Active MS-V-67B 10.3-2 Active MS-V-67C 10.3-2 Active MS-V-67D (B22F067) 10.3-2 Recirculation pump Inactive RRC-V-23A 5.4-7 suction Inactive RRC-V-23B (B35F023) 5.4-7 Flow control (pump Inactiveb RRC-V-60A 5.4-7 discharge) Inactiveb RRC-V-60B 5.4-7 (B35F060) Inactive RRC-V-67A 5.4-7 Inactive RRC-V-67B 5.4-7 (B35F067) RCIC vessel head in Active RCIC-V-13 (E51F013) 5.4-11 Active RCIC-V-65 (E51F065) 5.4-11 Active RCIC-V-66 (E51F066) 5.4-11 HPCS in Active HPCS-V-4 (E22F005) 6.3-4 Active HPCS-V-5 (E22F004) 6.3-4 Inactive HPCS-V-38 (E22F038) 6.3-4 LPCS in Active LPCS-V-5 (E21F005) 6.3-4 Active LPCS-V-6 (E21F006) 6.3-4 Inactive LPCS-V-51 (E21F051) 6.3-4 Standby liquid control in D Active Active Active Active SLC-V-4A SLC-V-4B SLC-V-6 SLC-V-7 9.3-14 9.3-14 9.3-14 9.3-14 Inactive SLC-V-8 9.3-14 Pump description Recirculation pump Inactive RRC-P-1A 5.4-7 Inactive RRC-P-1B (B35C001) 5.4-7 LDCN-05-009, 06-000 5.4-56

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.4-1 Reactor Coolant Pressure Boundary Pump and Valve Descriptiona (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 operability (e.g., valve opening or closure, pump operation or trip) is not relied on to perform the systems safety function during the transients or accidents. 5.4-57

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 1250/575 suction nozzle 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 106 Total developed head, ft Suction pressure (static), psia D805 1025 Required NPSH, ft 115 Water temperature (maximum), °F 533 Pump brake hp (minimum) 8340 Flow velocity at pump suction (approximate), 41.5 ft/sec Pump motor Voltage rating 6600 Speed, rpm 1780 Motor rating, hp 8900 Phase 3 Frequency 60 Motor rotor inertia (lb-ft2) 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 106 Total I.D., in. 6.4 LDCN-07-011 5.4-58

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.4-2 Reactor Recirculation System Design Characteristics (Continued) Description Diffuser I.D., in. 19.0 Nozzle I.D. (five each), in. 1.3 Diffuser exit velocity, ft/sec 16.2 Jet pump head, ft 88.19 Flow control valvea 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 pump 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 (% rated pressure drop) +/- 4% a Mechanically blocked in the full open position. 5.4-59

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.4-3 Operating Experience of Ingersoll-Rand Emergency Core Cooling Systems Pumpsa,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. b No problems have been reported on these pumps. Pump design principles applied by Ingersoll-Rand to these units are not unique. Assurance of a predictable functional reliability is also provided by a history of design, production, and application of pumps for similar pumping requirements in other nuclear and nonnuclear applications. 5.4-60

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.4-4 Operating Experience of Similar Ingersoll-Rand Pumps for BWR Projects Under Reviewa,b Year Size Range (gpm) Number of Pumps 1963 <4000 12 1964 <3000 24 1965 <5000 32 1966 <4500 39 1967 <5000 39 8000 3 1968 <6500 25 9000 6 11000 9 1969 <6500 39 8000-9000 9 1970 <6500 33 8000 14 12,000 6 1971 <6500 53 9000 3 10,000-12,000 12 1972 <6500 44 8000 18 10,000-12,000 18 1973 <6500 41 8000 8 10,000-13,800 20 1974 <6500 32 8000 2 10,000-13,800 30 1975 <7500 76 8500 18 10,000-13,800 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. 5.4-61

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Table 5.4-5 Reactor Water Cleanup System Equipment Design Data Main Cleanup Recirculation Pumps Number 2 Capacity (each) 100% (@90 bhp) Design temperature, °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 pressure, psig 1420 1420 Tube design temperature, °F 575 575 Filter-Demineralizers Type Pressure precoat Number 2 Design temperature, °F 150 Design pressure, psig 1450 5.4-62

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 Table 5.4-6 Safety and Relief Valves for Piping Systems Connected to the Reactor 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 line RCIC-RV-17 (E51F017) RCIC lube oil cooler supply line RCIC-RV-19T RCIC vacuum tank RCIC-RV-33 (E51F033)a Shutdown cooling supply line RHR-RV-5 (E12F005) Shutdown cooling return 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 exchanger (shell side) RWCU-RV-1 LDCN-17-027 5.4-63

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT November 2017 Table 5.4-6 Safety and Relief Valves for Piping Systems Connected to the Reactor Coolant Pressure Boundary (Continued) RWCU regenerative heat exchanger (tube side) RWCU-RV-3 RWCU blowdown to radwaste system or condenser RWCU-RV-36 (G33F036) 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 installed in a B31.1 system; not subject to Section XI testing and inspection. LDCN-17-027 5.4-64

Amendment 53 November 1998 Suction Flow Driving Flow Recirculation Core Pump Jet Pump Simplified Schematic Recirculation Outlet Recirculation Inlet Discharge Shutoff Valve Flow Control Valve (Note 1) Suction Shutoff Valve Pictorial View Note 1: FCVs Are Mechanically Blocked Full Open. Recirculation System Evaluation and Isometric Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.07 Rev. Figure 5.4-1 Form No. 960690

Amendment 53 November 1998 1,400 110% Speed 1,200 105% Speed 100% Speed 1,000 Dynamic Head - Ft. 800 600 System Resistance 400 200 0 10,000 20,000 30,000 40,000 50,000 60,000 Flow - GPM RRC Pump Dynamic Head-Flow Curve Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.05 Rev. Figure 5.4-2 Form No. 960690

Amendment 53 November 1998 36,000 32,000 er at W 28,000 d ol

                                                                                                                                -C ow                          er 24,000                                                                                         Fl                        at Pump Torque - Ft. Lbs.

0% W F 10 3 5° 20,000 -5 ow ate r Fl 0% oldW 16,000 10 -C w r Flo Wa te 25% 5 35 ° F 12,000 lo w-25 %F 8,000 Breakaway Torque is 4,000 1200 Ft. Lbs. 0 0 200 400 600 800 1000 1200 1400 1600 1800 Pump Speed - RPM RRC Pump Speed - Torque Curve Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.06 Rev. Figure 5.4-3 Form No. 960690

Amendment 53 November 1998 400 NPSH (Ft) 200 NPSH at CL imp. 0 90 Efficiency % 1200 80 Total Dynamic Head (Ft) Head 1000 70 800 60 Efficiency % 600 50 400 40 BHP at 0.755 SP. GR. 10,000 30 5,000 BHP 20 0 10 0 0 10.000 20,000 30,000 40,000 50,000 60,000 70,000 Gallons Per Minute Recirculation Pump Head, Columbia Generating Station NPSH, Flow and Efficiency Curves Final Safety Analysis Report Draw. No. 960690.59 Rev. Figure 5.4-4 Form No. 960690

Amendment 53 November 1998 Throat or Mixing Section Diffuser Driving Nozzle Suction Driving Flow Flow Driving Driving Flow Flow P Pressure Suction Flow P Suction Flow Operating Principle of Jet Pump Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.58 Rev. Figure 5.4-5 Form No. 960690

Amendment 53 November 1998 Normal Water Steam Level Separators Steam Separation Distribution Plenum

                   ,------~

Water Level After Break in Recirculation I Loop Active Core ( I I

                   ~--g __j I

I I Core Flooding Capability of Recirculation System Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.60 Rev. Figure 5.4-6 Form No. 960690

15 14 13 12 11 10 Amendment 66 l"P1(1)-4S-X-40f & 1iQ1E.S_; CONT. FROM ( B/2) l:!..QIE..S__; December 2021 I "P1(1)- 4 S-X- ~ 11 12 COD E BR E.&.K DEFINITIO NS FO R THERs! OWE LLS I ALL ITEM S M,i,,R KED

• ARE FURN IS HED WI TH t,RE SHOWN ON M610, "INSTAL LATION OF ASSOC IATEOEO\J [PM ENT THERl<HJWELLS AND SAMP LE PRO BES" 2 PIP[~ . VALVES, ANO AS SOCIATED cm.l PON ENTS ON lJ INSTR UMENTATIONSONOTED SHAL L BE TH I S DWG. SHAL L BE CLASS IFIED AS FOI._LOWS (BREAK PO INTS ARE INDICATED ON FLOW PIPING AN D VALVESOFS.U BSYSTEMR RC (7)AN D I NSTR Uf.lENT AfOPROC ESS

                                                                                                                                              --------,                                                                                                                                15  SEEVE NOO R DWG81999- F-00l(CV102 8 35-15,5)

I PUla P FO R INTERNA LS INFO RIMTION & FLOW PATH S ON SE[St,[CCATEGO RYI L-1~-- STU FFI NG QUALITY CLASS I 0 COD E GRQ UP 17 FO R SAMP LE FUNCTI ~ & IN STRUM ENTATION AS SOCIATED WITH THE SAMPLE POI NTS SEE DWG. SER IES M607 STEAM & LIQUID SAM PLING FLOW DIAG RAMS AND DWG. S ERI ES 6DA- OO SAM PLE RACKS DETAI LS & FLOW INSTR U~ ENT AND PR OC ESS PI PING AN D VALVE S DIAGRAMS AS NOTED (NOTES CONTINUED ON DWG. 1,530-2) SEIS~IC CATEGO RY II 4) ) QUALITY CLASS II 0 CO DE GROU P D d PU~P SE,O.L ORA! N LI NESA~ INSTRIJMrnT PIP ING Ki NOTED S[ IS~IC CATEGORY I QUALITY CLASS I CO DE GROU P C

4) HAN GER S TO BE DESI GNc D TO SEIS ~JC CATE GO RY I LOAD S.

J ALL INSTR U~ ENT ROOT VALVES NOT LABELED WILL 8[ J/4 " GLOB EVALYES UNL ESSSPECI FICALLYNOTED OTHER\\II SE ALL PIPING SYSTE~ S I DENTIFIED BY THE PREFIX "Pl " &: "PSR" SH ALLB [S U PPLI E A NOINSTAL_L (08YCON TRACTj 220

                                                                                                                                                                                                                                                                                                                                                                                                              ,;;~f VA.t_\/ESSU FFIXED WITH A                     5      DETAI L SH OWS VALVE STEM LEAK-OFF CONNECTION WITH DEN OTE A THRDTTLED we-~*
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T 1@L EJ 1-R608 rna-, ~ ,-, 4"Egi~+:)~~ TO CR SYSTE~ CRD- OPT-8. C12-NODB COO T. ON ~52 8 -2 ( F/3) DWG. ~'.137 SE E TAB LE ** FOR ZON E -------------..I =j=.,-- J/ 4 RRC(5 0)-1 j:i----------CL (OO DYORAIN ) TO HP CS SYSTD. HPCS-D P1S-9. E22-N009 CO NT. ON DWG. ~ 520 (J/7) Ti-£ FOLLOWING VALVES ARE PROVID ED WI TH THISA RRA~ rnENT

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                                                               ~

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                          ~ ~ ~} ~;y~)     RECI RC. PUM P   "8" TE'S SEE (J/7)
                          ~~~} ~;y~2      )RECI RC , PU ~ P "A" TE "S 6      THIS EQUI P~ ENT IS NO R~AL LY CONTRQ LED FR OMTHE MAINCO NTRCl L ROOM.IF THE
                                                                                                                                                                                                                                                                                                                                                                 ~A[N CONTROL ROO ~ MU ST BE VACATED FROMRCC-TE -9A( B3 5- N009A)                                                                                                                                                                                                                                                                                                 THIS CO NTROL POINT ~ AY BE ISOLATED owe. M525-1 ( F/ 9)                                                                                                                                                                                                                                                                                                         ANOCONTRDLT RANSFERREO TO THE REM OTE SHUT-DOWN PAN EL C5 1-P001 SEE DWG. M530-2 FOR RRC MISCE LLAN EO US FROM RC C-TE -80 :5A ( B3 5-NDOJA)                                                                                                                                                                                                                                                                                           SYSTEMS.

PI- EFC-X( PE NET RATIONNO.) Q CON TAIN~ ENT INSTR UMENTATION ROOT VAL\/£ SHALL BE AS E/S-83~-K600 10 AL L INSTR UMENTATIO N ON TH IS DRAWING TO BE I DENTIFI EDBY PREFIX"RRC " ~ LESSSP ECIFICAL LY NOTED OTHERWISE 11 AL L INSTR . LIN ES ARE DESI GNATED BY CCC£ & LI NE f A. EXA~PLE : LIN ES ORIGINATI NG INSID E CONTAI N~ ENT 1/2" PI(1)- 4 S

                                                                                                                                                                                                                                                                                                                                                                    ~

COD E DESIGNATIO N

8. EXAMP LE:CONTINUATIONO FTHEABOVELI NE OUT-SIDE CONTAI N~ ENT IS DESIG NATED AS FOLLOWS.

WITH LI NE NUMB ERSNOTSH OWN.

                                                                                                                                                                                                                                                                                                                                                                     ~                                   ( H22-P021)-

NOTESCONT.AT ZON E (K/4) J/4 RRC 56)- 4S-1 RR C-Y-512(0) (PU~ P SEAL P URGE) RR C-V-617(0) PRIMARY CONTAINMENT A Reactor Recirculation System - P&ID Columbia Generating Station Final Safety Analysis Report Draw. No. M530-1 Rev. 98 Figure 5.4-7.1 Form No. 960690ai

11 10 4 2 Amendment 64 liQIE_S_;_ (C0NT.FR0t.1M530-1) December 2017 SEIS~IC CATEGORY II QUALITYCLASS2

19. PIPING BETWEEN DRIVE COOLING SKID AND HEAT EXCHANGER IS:

RRC-IMD-ASD1A/1 (SEE NOTE 20) CI --------------7 EPN'S SHOWN ARE FOR ONE OF FOUR DRIVE LINEUPS THE AP PLICABLE SUFFIX FOR ALL EPN'S IS AS FOLLOWS: I ~ ' I

                                          ~~-I-~~

GLYCOL RESERVOIR 1 3/8" TUBE

                                                                                                                                                                     ----+--+,~~'--+---<$>  1 1
                                                                            ~"'

CY-S,-1"1 ~

                                                                                  '~---+--,~;,~--rn-,,., I f------11---------.,                                                                                           24. SEE DWG M501 FOR FLO AND AB BREVIATIONS.

G VENDOR LIQUID COOLING SKID INDUCTION MOTOR DRIVES LIQUID COOLING SYSTEM - RRC PUMP ADJUSTABLE SPEED DRIVES (SEE NOTES 20 & 21)

                                                                                                                                                                                                 ----..--R--
                                                                                                                                                    +~--

I I f -~ ,--- ---, ASDROOF ASDROOF C eccc dm ---- ASD BLDG L __ eccc dm 8000-0 8000-0 dm dm RRC AS BLDG. HVAC Reactor Recirculation System - P&ID Columbia Generating Station Final Safety Analysis Report Draw. No. M530-2 Rev. 13 Figure 5.4-7.2 Form No. 960690ai

Amendment 53 November 1998 Reactor Vessel Steam Flow Restrictor Main Steam Line Isolation Valves Test Drains Connection Primary Containment Main Steam Line Flow Restrictor Location Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.61 Rev. Figure 5.4-8 Form No. 960690

Amendment 53 November 1998 Air Cylinder (Closing Piston Inside) MSIV Speed Accum Control Valves Hydraulic Dash Pot Actuator Support And Spring Guide Shaft Closing Spring Spring Seat Member Stem Stem Packing Leak Off Connection (Plugged) Bonnet Bolts Bonnet ow Main Disk Fl Pilot Balancing Pilot Seat Orifice Main Valve Seat Body Main Steam Line Isolation Valve Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.84 Rev. Figure 5.4-9 Form No. 960690

Amendment 53 November 1998 30 NPSH-ft at 625 GPM NPSH-Required 20 Eff.% 10 90 3200 0 EFF% at 625 GPM 80 2800 70 Total Dynamic Head in Feet 2400 60 2000 50 1600 800 HEAD at 625 GPM 40 BHP Required 1200 600 30 800 400 20 BHP at SP. GR 1.0 at 625 GPM 400 200 10 0 0 0 1500 2000 2500 3000 3500 4000 4500 Speed Revolutions Per Minute Witness Test Performance Bingham-Willamette Co. Portland, Oregon RCIC Pump Performance Curve (Constant Flow) Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.55 Rev. Figure 5.4-10 Form No. 960690

15 14 13 7 4 Amendment 65

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PRESSURE TEST ( CONNECTION RCIC-V-759 ~I:_~

                                                                                  ~

RCIC-V-67 ES1-f"()67 RCIC 20.~~:ai~~~ii-66 F\HICf IHST"'-1..ED. RCIC-SPV-66 (LOCATro !H [R-7\)JSOE,l,CTI\IATEDANDSPAREO[N PIJ,C[. [ SMS " 3/8-Pl{1)-ST-(!R- 21.~~~rnl~NOOFL=,Q'~

                                                                                                                                                                               )-Sf- (1R-82)-2                                                                                                                                                                                                                                                 PERMN"PUCAIIL.£Pf'M.
                     =:..,()ff{l(/~)f-                               53)-

NOT"EJolSEEHOTE12 22. SEI DWG M50I FOR fl.OW DIM:RAM l.£COIDS, SYMBOLS ANO Al!BREV!Al!ONS. RCIC-V-10

             ~~118~5-:'~:~

u!?ot:

23. RCIC-RMS--fl!SI HAS llllN PUaD !N CMRRIDE Ym 1 REFERENCES TO CONTRACT NUMBERS, ~YF'£R(C1Hll7-0lNGI.DW le21-1(B/6) 5 SUCH AS 2 15, 206, 220, FOUH0 ! N THE OISCIW!OEPflfSSlft:1111~.

l'RC[C{::~~~ NOTtS ON THIS DRAWING REFER TO FSAR FIG. RCIC-V-60J{O) 6"RCIC(2)-1-1 S"IICJC(2) 1 OR!GlNAL CONSTRUCTION OESlGH

                                                 ~/4"11clc(52) 1                                                                                                                                                                                                                                                          REOOIREMENTS.

1RCIC-1

                                                                                                                                                                                                                                                                                                                             ~~~SI~              ~~Q~~c:~r:J
                                                                                                                                                                                                                                                                                                                             = l~~~g:~ :?c~u.Cf~

A RCIC System - P&ID Columbia Generating Station Final Safety Analysis Report Draw. No. M519 Rev. 103 Figure 5.4-11 Form No. 960690ai

2 3 s 7 8 II 10 11 12 Amendment 59 15, MAXIMUM LINEAR LENGTH BETWEEN POSITIONS @ AND @ EQUALS GO FEET. THE INTERNAL CROSS-SECTIONAL AREA OF THE VACUUM BREAKER PIPING THAT IS SHARED

12. DESIGN PRESSURES AND TEI\PERATURES GIVEN ARE THE BASIS FOR DESIGN OF GE SUPPLIED EQUIPMENT, ESTIMATED LINE SIZES ARE FOR INFORMATION ONLY. ACTUAL December 2007 LINE SIZES AS DETERIIINED BY PIPING DESIGNER, SHALL MEET THE PROCESS DATA (5EE NOTE 12? 13) BY THE RCIC AND RHR SHALL BE EQUAL TO OR GREATER THAN THE COMBINED INTERNAL HYDRAULIC REQUIREI\ENTS.

Q 19tt.lw-20A 2DA-I CROSS-SECTIONAL AREAS OF THE INDIVIDUAL RCIC AND RHR VACUUM BREAKER LINES. MPL IT£M.N9 :E5l-l0'2.0

                                                                                                                                                 ~~/i~: :i:r:EST MODE F AT POSITION LOCATION                1*2 3-11), 111~4 7-e 8-BA BA-"'! 1-12. 12.-13 11-14       17   18-2 19*.19A                     ID-II                                                                                                                                                                                                                                                           l!Dilli A                                                                                                                                          15.                                                                                 13.     "PEAK PRESSURE" IS THE 11AXINUM PRESSURE ANTICIPATED DURING A TRANSIENT PER*

PEAK PRESSURE 9, 10 AND ll ARE BASED UPON A PUMP IOD WITH ALL OF THE CONTRIBUTING ELEI\ENTS Al A 11AXINUM, IT WOUL] BE EX* ]. ATl10SPHERIC PRESSURE OF 14.7 PSIA WAS USED IN CALCULATIONS, PSIG N/A 1481 (481 N/A 1137 1137 \4BI N/A N/A N/A N/A N/A 1481 N/Ajl48l Nj~ 160 PECTED TO OCCUR LESS THAN 1% OF SYSTE"!i OPERATING TIJIIE, WATE'R FLOWS ARE SHOWN-I-N-Gf!f!l,- STEM FLOWS IN 1000 LB/HR,

                                                                                                                                                                                                       ,M:=6i~Dj5 _y 2,

RElDMMENDEC ICO 1500 1500 l'.JO ,'l'JO IZfO 1500 100 100 75 75 100 1500 100 11500 100 15"0 17. RHR ">fMM. C.ONt>f.>\Sll-lt. MOt>f. HAS M.f.N Pe,AC.TIVA-Tc~. DF':ilCN PRE~SU r..:: FLOW VALUES SHOWN IN MODES C & D ARE BASED UPON SUCTION PIPING DES_lGN l, THE MAXIMUl'I POOL WATER TEMPERATURE FOR CONTINUOUS SYSTEM OPERATION WILL NOT DESICN TEMPtRATURE 'F 170 170 575 170 m <;7) 170 170 !7U 250 1qo 190 170 1701110 17' 267 IB. ~~&c"ci:-'l\'oi~~S~l~ENmgf~;~y~~tr FORRPU ]4, PERIIITTING THE MINIMUM REQUIRED NPSH TO CONTINUE TO BE PROVIDED TO THE RCIC PUMP WHEN THE SUP!'RESSION POOL SUCTION STRAINER IS 50% PLUGGED, EXCEED 14QOf, HOWEVER, DUE TO POTENTIAL SHORT TERP'! OPERATION AT HIGHER TEI\PERATURES, PIPING EXPANSION SHALL BE BASED ON llO'F.

                                                                                                               , I4
                                  " "                                            z ESTIMATED                             G    G    10   4     2     2            I   I /4   2    2                    4      ID                                                                                                                                                                                                                                                             4.        THE UNRECOVERED FLOW NOZZLE PRESSURE DROP OF 4.5 PSI IS A FIXED LOSS LNE JiZE IN.

BETWEEN LOCATIONS Q) AND 0

                                                                                                                                                                                 ~ b r a ~
                                                                                                                                                                                                                      ~   I

• THE PRESSURE AT THI_S LOCAT_ICN DEP£ND~

AND MAY BE VAFi1£D WITHIN TttE fOc.-OwirtG Lii.;!TS.

                                                                                                                                                                                                                                                                                                   ~   PIPING ARRANGEMENT, THE LUBE OIL COOLER PRESSURE DROP OF 3.0 PS! !SA F!XED LOSS BETWEEN LOCATIONS@AND@
                                                                                                                                                                                                                      ~I°'       ~                                                                                                                                                                6.         THE CONTROLLING MODES FOR LINE S[Z!NG AND A.RRANGEMENT ARE:

B 0

Iii~

t',I NIMJM NPSH .4.T PUMP SUCTIO-

• 21 FEET Diec SUCTION FROM COND STORAGE - - - - - - - - l'KlDE A &. B COODENSAff ST0RAGE CONDENSATE STORAGE "' '2 0 W>.XIMJM PUMP TOTAL. OYt-lAMIC '1C:/.I.D 3011o fl:ET FOR MODES A t. C 610 FEET FOR MODES B & D SUCTION FROM SUPPRESSION POOL * * * * - - MODE C & D TANK C< w PUMP DISCHARGE* - - - - - - - - * * * - - - * * * - IIODE C & D 0

TP..NK

                                                                                                                                                                                                                       ~ ~                  MAXIMJM PRESSURE DRoP B£T\.IEEN LDCATIO-                                                                                                                                STEAM SUPPLY-                             - - * * * * * - * * * - - - NODE A & B G)                                             0                                                                                                                                                             ©       ANO   ©-           15 PS1 (SH.NOTE G.)                                                                                                              TURBINE EXHAUST - - - - - -

TEST LINE -

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          - MODE A. & C
                                                                                                                                                                                                                                                                                                                                                                                                                                                                        - - - - - - - - - - MODE F I-IA.X!l*IJM PRESSURE ALLO\.IED - 25 PSIA COOLING SYSTEM- - - - - - - -                               - - - - - - MODE A MAXlt,f,.IM PRESSURE ALLOWED"' 75 PSlA
                                                                                                                                                                                                                                                                                                                                                                                                   ),        SYSTEI\ OPERATION IS POSSIBLE WITH INTERl\£ll!ATE PRESSURES IN THE REACTOR SUFFlCI ENT VACUUM TO PREVENT TURBINE                                                                                                                           VESSEL AND THE SUPPRESSION POOL, HOMEYER, THESE CONDITIONS DO NOT CONTROL SH4rT-::xJT-LEAKAC.E.

PIPE OR VA.LYE SIZING OR SPECIFICATION, AND NO DATA JS SHOWN, C M4Xlt-UM PRESSURE AVAILABLE - 25 PSIA

8. PUMP MINIMUM FLOW REQUIREMENT MAY OCCUR DURING A.NY OPERATING MODE. FLOW MAX114JM PRESSURE AVA!'LA6LE - 65 PSIA REQUIREl'IENT IS 75. GPM MINIMUM, 5EC0.NO_t._RY C0NTAINMOJT SUJ- J- i-.ilNI /-'Nl!):,i,iNt. IU Nt.lUN!"i SuPPRESS;o,** POOL 9, FOR VALVE AND FLOW iNFORi'lATiOi'i, REFER TO THE RHR SYSTEM P&iD MPL El2-1010 RE"ACTOR SUFFICIENT PRESSURE TO RETURN TO COND. STORAGE A.ND PROCESS DIAGRAM MPl E12-1020, 10, DURING SYSTEJ1 STANDBY. EQUIPKENT IS NOT OPERATING. JNTERPIITTENT FLD\tl OC-CURS THROUGH THE STEAM SUPPLY LINE DRAIN TRAP SYSTEI\ AT 1000 PSIA AND IGO'F.

II. HEAD SPRAY NOZZLE PRESSURE DROP IS lil PSI. MODE A ~UCTION f"ROM CONOCNSA1E STORAC:oE R(ACTCP: AT HIGH PRE":1':>URE,SUP?RESSION l'OQ\_ Ai HlGH PRE.S'=i, LOCATION 0 o 1 I B 9 10 11 12 13 14 1s 16 11 I 1s 19 20 D FLOW- SEE NOTE 'Z.

                                                                                                                                                                                                                                                                                           '4.7     * *          *12~5 18                   -      122s      *

• 19 ..9 7~
• 45
• 9.a *I* * ~

EXPEC ED TEMPERATURE. °F 100 100 100 100 110 -]565 ';,AT ~AT 2'28 100 100 ,\00 no llO l'Z.0 j110 100 ,----

                                                                                                                                                                                                                                                            ~~~~~~ '°'.3/4a"%,'°%', '"to"%,                                           -       -lV'1/, 573/, "%, "'/2' "'%a ' o/40 "'%, "%0 ";).(, '%1"%, 1'o/,a -

TO RHR VACUUM MOOE 8 5U(.nc... FROM CONOCNSATE STORtouE REb(_TOR AT LOW PRE~UR.E SUPPRESSION POOL AT HlGH PRE55 BREAKER ,s LOCATION 0 I 2

                                                                                                                                                                                                                                                                                                             '        4      5                 7      a      9       10       II     12
                                                                                                                                                                                                                                                                                                                                                                                              "          14       15     1*        17               19    20 F.:                                                                                                                                                                                                                                                      FLOW -5(.E NOTE             2:   -     bl)Q Cl6 SOD            -         -        a      -    <;::>.30 9.15 9.15         16       re        10      0.1s     -       0.01      ic*      -       0
                                                                                                                                                                                                                                                          -PSIA 14.7
                                                                                                                                                                                                                                                                                                     *

• 178 18 - - 165 19.0 75 45
• 9.a

                                                                                                                                                                                                                                                                                                                                                                                                                                   *

• 100
• X RE°F 100 100 100 IQO 140 - - ,,,., l.~% "%ol1/4o 10%o

                                                                                                                                                                                                                                                                                                                                                    %6 SAT SAT 227 100 100                             100 DO 120                 120      12D             -

NOTE 15) MAX/Mll>J TEVIPER.ATURE °F 1"%,;"o/.., "'%,11'%, 17%0 - -";,'10 "3/4, I"% 11%0 1,%0 1%01103/40 - FROM Vbt:.. PUMP F008 BB M*7 F Fo4o MODE C SUCTION FROM ~'JPPRE':::i'SID"N POOL REAC10R AT k\GH PRES':,URE. '5UPPR.ESSION POOl. AT LOW PRl~

                                                                                                                                                                                                                                                                                                                                                                                              . . ... " **a* *

('J

                                                                                                                                                                                                                                                                                                                                                     - 2.9.51 ,,.., t%, is ZS LOCATION                           I     2                4      0                 7      8              10       II      )2                 14       IS      1*       )7       18       19   20 FLOW -       5H      NOTE 'Z.    -     600     025 600          -         -      600                                                       25        0.15     -      O.CM     '1-5+. -          0
                                                                                                                                                                                                                                                                                                     * *                                            ,.s g~S;':-!',"T~~l'.!I_ P'.::i\A                          l'l.~5 14.1 \9.2 18.8 12.'25                            l.~.6 15                    45 F0fb EXPEC."TEO TEMPERAT\JRE. °F
                                                                                                                                                                                                                                                            ~\iRE°F 140 140
                                                                                                                                                                                                                                                                                                   "%0     11r401'%0 140 *40 040 140
                                                                                                                                                                                                                                                                                                                           "%a "%al?'.., srr"'
                                                                                                                                                                                                                                                                                                                                                           ,,,., z5r:u
                                                                                                                                                                                                                                                                                                                                                           ~AT. SAT. 218 250/10 140 140 140 2'0 160 160
                                                                                                                                                                                                                                                                                                                                                                                    "%,,,%,, "%, "%0 ' ?'40 i~oi 9%o 17%0               1 "o

0) MOOE D SUCTION FROM suPPRESSIOfll POOL REACTOR AT lO'l,j PRESSURE, 51.JPPRES~ION POOL AT LOW Pl'.E.!:6 LOCATION () I I 2 :i 4 S f, B 9 10 11 12. t3 14 t5 I" l"'1 IB 19 'l_Q H FLOW-SEE NOT( l. - \600 lollo 600 - - 600 - 8.40 B.2.5 6.2.5 IG IS:. IS:. Q.t~ - 0,01 II;,+ - 0

                                                                                                                                                                                                                                                            ~~i~G1~-P5lA                     -    I JIE-

• 1?8 14.7 \9.2 IB.6 1~5 *
• lb.5 15
• 45
• 9.8 * *
• DRAIN OUR.llJ~

                                                                                                                                                                                              ~--lfOcl-5~-,;ST;:i~~-~~~~
                                                                                                                                                                                                                                                            ?!:lo NOTEc 17 MOOE. f-1                                         5UCT10N      FROM RHR MEA"'T E)(.C.MANC..LR.5, REA.C."'TOR AT HIGH PRE~~., .::!,UPP.~!:>. FOOL A T ~ P ~ .

Ikno,T10N JI I 1 2. I ~ I 4 I !> I " I 1 Is I g I 10 I 11 I 11. I 1l I 14 I 1s I '" I 11 I 1a I 19 l-zo I21 I

                                                                                                                                                                                                                                                                                                                                                                                                         ,~
                                                                                                                                                                                                                                                                                    ~

FLOW - ;)(E_ NOTE ~ - 300 3% 300[- - 0 - 'l0.15 10.00 '1:0.lll lo lo 0.15 - o.or 11'='+ - 0 "201.3

                                                                                                                                                                                                                                                                                                                                                    ,.o * *                                     *                  *                *I*              *      -

OPERA1lN6 l~.6 75 45

                                                                                                                                                                                                                                                                                                                    /OE5I 14.7                      !015                                                                 9,B                                      1015 PR<:"'"'=i'5URE PSIA E:XPECTEO                        -     140 140 1401 !40                  -       --            SAT     SAT. 218 140 140 140 2,0 1~0 lt:DOl;"'O 140                                                 5/,()
                                                                                                                                                                                                                                                                                                                                              -~;;; lh I'% ,~;,, l"feo .1/4o I3/4, 1'"'.l(o 1/40 1'"%,1"'.3/4o "%,

T£MPER,ATURE °F MAX/MIN TEMPERATuRE °F "°%, '%, I%, '3/4ol%o - - TOTAL LEAIWFF" SEE. NOTE 17 E*Z. SUCflOH FROM RHR He.AT El(.C.MAUGERS, R~Oll. AT LOW -PRt:SS, 5UPPR.~. P00L Al" LOW PCl~SS. FROM TURe,IN[ MOOE

                                                                                                                                                                                               @                                                             LOC.O.TIOJI.I 0

I 2

                                                                                                                                                                                                                                                                                                               '      4       0

• 1

                                                                                                                                                                                                                                                                                                                                                       *

• IQ I) 12 13 14

                                                                                                                                                                                                                                                                                                                                                                                                                   "      16 17      IS
                                                                                                                                                                                                                                                                                                                                                                                                                                                      '9    20     2.1
                                                                                                                                                                                                                                                             ~LOW - ~EE MOTE i                      21!'> 21>1 2.1!'>       -                  0            !5.1~ 5.00 S.00
                                                                                                                                                                                                                                                                                                                                                                                      '"                  '"     0,\5              0.0\
                                                                                                                                                                                                                                                                                                                                                                                                                                              "' +           a   ll"iU*

K 19

                                                                                                                                                                                                                                                                                                     " 140* 140 )40 -                               '"'°      * *                               *                                    *                * --
                                                                                                                                                                                                                                                             ~PERATl_!'I~- l'nlA                                    10,3    14_---;    -      -                              \6.6 -,5                    45                                                       150
                                                                                                                                                                                                                                                                                                                                                                                                                         '""' l'l3/4D ,.,,40 ,.,._.;, - i'o/10 E.X.PECTED TEMPERATU~l: °F                       140                                        - 35& SAT s.r 218                     140 140 140 2'0                                                140          358 F022             FOl9                                                                                                                                                                                                                                                       1°?""°1113/40 '  70/40 '%0 17%o -                    _3s3/4o r7',o '~o ~;.                   "'/,., \'10/401110/4'0 I'%, l'lo/40
                                                                                       ~

rE~1,E~!~RE"F 19 MIN FLOW LINE

                                                                                                                                                                                                                   @                                        MODE ,::-                TEST MODE:          SUCTION FROM CONDENSATE STORAGE                            REACTOR AT HIGH PRESS., SUPPRESS POOL AT LOW PRESS.

O I, w 13

                                                                                                               ~

10 II 12 14 15 16 17 18 19

                                                                                                                                                                                                                                                                                                                                                                                                                         ~-*

LOCATION 2 , I

• 5 6 7 8 9 20

                                                                                                                                                                                                                                                                                                                                      -                                               ,                                                      11:
                                                                                                                                                                                                                                                                                                    "'"" o,1c,I-             -

L

                                                                                        ~

FLOW-SEE \..IOU: 'l.' - 0 - 23.50 ?;1.35 0.15 - 0.01 - i.oo i:J,P :4.~ PS.I

                                                                                                                                                                                                                                                              -.;;'i:._~~~P!)IAi 14.7
                                                                                                                                                                                                                                                              ~:~:f~;'uiu: *J" i100 100 1001- 100 -
                                                                                                                                                                                                                                                                                                             .. !-         14.7        -            1000
                                                                                                                                                                                                                                                                                                                                                                            ',.,. 7>                45 cO                                                                                                                                                                                                                                                        -     S~5 :>AT.                       \CO 100 100 ?30 l'ZO 120 12.0 100 )00
                                                                                                                                                                                                                                                                                                                                              - "'X ""X. '% '1/2."%, ' .%a '% % '% '3/4I'% "%, '%

S'l'~lEM TEST LINE

                                                                                                                                                                                                                                                                                                   'o/.,1 "ZJ - '3/4, -
                                                                                                                                                                                                                                                              ~~t/E3/41.,'.~RE f" I'%   0 RCIC System Process Diagram 2                                                                                                                             Columbia Generating Station Final Safety Analysis Report POOL M

Draw. No. 02E51-04,4,1 Rev. 10 Figure 5.4-12 Form No. 960690ai

Amendment 53 November 1998 NPSH-ft Eff. % 50 100 NPSH at CL Imp. 25 90 0 80 2000 70 Head Total Dynamic Head in Feet 1800 60 1600 50 Eff% 1400 40 1200 30 BHP 1000 20 BHP at SP. GR 1.0 500 10 0 0 0 200 400 600 800 1000 1200 Gallons Per Minute Test Speed RG. 3591-3585 RPM Whitness Test Performance Bingham-Willamette Co. Portland, Oregon. RCIC Pump Performance Curve Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.86 Rev. Figure 5.4-13 Form No. 960690

Amendment 53 November 1998 Measurements for Strainers at Penetration X-33 Rated Flow: 600 gal/min

                                        -r--       -
                                           \.......,'

r ...J J

                               /---
                            /

I I I

                          \
                            \
                              \
                                \

I\ I \ I \ I \ I I I I

                           \         I
                            \      I
                              \.L--,

I [

J

......J I

p Notes:

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: 220°F Typical Strainer Columbia Generating Station Final Safety Analysis Report Draw. No. 960690.87 Rev. Figure 5.4-14 Form No. 960690

Amendment 65

                                                                                                                                                                                                                                                                                                                                                                                      =

15 14 13 12 11 10 4

1. ALI. f'RESSURE & FLOW lHSTRUWENT ROOT VALVES MOT Lo\llEU.ED WILL BE J/4" Gt..OBE VALVES(UNUSSSPEaFtCALl.YNOTEDOTHERWISE).

December 2019 2.. ALL ITEMS ~ED

• ME FURNISHED WrTM ASSOCIAfED EOUIPMOO *

                                                                                                                                                                                                                                                                                                                                                                                      .5. PIPINC, VN..VES, N-10 .\SSOaATEXl COMPONENl'S OH nos                  owe. SIWl. BE CVSSll't(D AS f'tu.OWS. EXCEPT N; STATED IN NOTES IS do 17 (BREAK POINTS ARE l~CAim ON Fl.OW OIJr,GRAM):

A. PIPINCANDVALVESOUTTHROIJGHOUTERMOSl"RE:AC.ISOI..VAL'>5:

                                                                                                                                                                                                                                                                                                                                                                                                       ~~TEGOff1                    l}Ja B. PIPING AND VALVES ll(YDND DUtOIMOST R(AC. lSOl. VAl..\-1;5, 0CCEPT 1'HDS(

LINES D£SIG.AS 3/"RHR(5e}-2:

                                                                                                                                                                                                                                                                                                                                                                                                       ~~noo<<r                      J}m C. INSfM. AIR LINES

• l.[Al(-()F"F" PIPING INSIDC COHT. [SOL VAL'-£$:

SEISMJCCATrGO!!Y I

                                                                                                                                                                                                                                                                                                                                                                                                       ~

COOEGI\OOI' - BI D. INSTR. AIR LINES OOl"S!DE COHTA!NWENT lSOL VALVES: [. E~BEYOHOJ+/-_OFTrsot..VAL"Ddt'EUN£SD£51GNATEDAS 3t;;::lc t~ 58 n*

                                                                                                                                                                                                                                                                                                                                                                                                       ~~                           JI F. Pl~~EOR{irl:-FDR(.:5):
                                                                                                                                                                                                                                                                                                                                                                                                 *HO.NCERS T09EDESIGH£DTOSEISMlCCATECOR"l'IU:,,,.OS.

0EXCEPTASNOTEDOHU81111NSlR. COHN.OIACltWS. SEE Nll1E 12. --z Sl'[C .* SECT. l!IB.I. Tlril!l.f 2 NlllES.

                                                                                                                                                                                                                                                                                                                                                                                      ,. CODE BREN< DEF1NITIONS FOR THERWDmJ..S ME SHOWN ON US1D. 'TNST,1UATION OF THERMDWEUS AND SAMPLE PR08ES."

6. ALI.PIPINCS'l'SIEMSIDENTIFlEDBYTHCl'RlTIX"f'l"stw..t.BESUf'f'UID.t: JNSTAI..L.ED!JY OCMRACTfUD.

7. TI-IISEQl.JIPM(NTJSNORl,,WJ.YCONTROLUllFROUTMCMAJNCONTRDLl!ODM. lfTHEt.lAI.N

                                                                                                                                                                                                                                                                                                                                                                                           ~~TO~ : = ~ C : L c ~!_~fY 9E ISOlAT£D AND COKTROl

9. AIJ.DW M:l(QU,\T( PIPING SURf,ICf N!fA FOR COOLING OF PUMP RHR-P-J.

10. ALI.TEST CONNECTION PIPING WIU. ASSUUE "RATINC"DF SOURCEPIJ>EAND BEIOENTlflED AS J/"11:HR(!>!i) *" ," UNU5S OTI1[1!W!SE NOTED BY SPECIFIC LINE NUMBER.

11. EXCESS F\.OW Cl£CK VAL"D SHilrU. 9E TMlGED AS FDl..l.OWS: Pl

• EFC-X*

cm; ___0 RHR-V-7~ (*-PD£rR.\TION NUMBER). l!!!!) NOTEJ1 CONTAINWOO !~WENTAl\ON ROOT VALVES SH,l,LL BE T ~ AS FOL1.0WS: (**PENETRATION) EXCEPT ffl(R( HOTED OH FACE: or DRAWING. EWPILNT,.,.OIHSTRUMENTSME.PRCFIXEOWITWRHRVNl..ESSOTHCRWISENDTED. C0HTR SP j~ 1* ~ N T ~ . [ / 0 UST FOR lolOTDR WINDING AHO O(NUNC l"OFERATURE El.EM[NtS AND G 2\~ 2.20 ____ ...,~(~)~:

                                                                                                                                                                                                                                                                                                                                                                                                      ~:co~

RH'!-V-PIPIHG, VAL','ES, ,.,.D ASSOCIATED COUPONEHTS ON rnts OWG. SIW..i. BE ClASSIFIEO AS l fa.LOWS(BR(N(POINl"SNIEJ~ICATEDDNTHISD!,1,GRAM): A M.521- (H/\2) (OCAC'TlVAlED) 1m.R-2

                                                                                                                                                                                                                                                                                                                                                                                                 -a- (AsME lll/ 2 WITM EXCEPTlOHS.          stt   PROCl.f!EMOO SPECIFICATION 12023)

(C/1S)YEDR (50)-1

17. ALI. PIPINCOOWNSTR£N.1orT1-£ USflSDI.ATIONVALVEANDOf'EN TOTHEAT\IOSPl£RE

                                                                                                                                                                                                                                                                                                                                                                                           ==~~~~~.t~~~:OWii\~O)                                                                            AS
                                                                                                                                                                                                                                                                                                                                                                                                                 ~2:;:~- ':;:~:>a ALI. INSJRUWENT LI~ AA£. OESIGNot.TED Ir!'            COO[N<j(I      LINE NUMBER.

A. EX,IMPI.£: LI~ ORIGIMTINGOUTSIDCCONTAINWENT.

                                                                                                                                                                                                                                            =~

J"RHR(17) \

                                                                                                                                                                                                                                                                    ~~,1~~-:

RHR-V-6.l,I, J"CON0(152)- 1 [ \2-f06J B. EX.AWPI..E: U'46 ORIGIMTING INSIDE COHTAINMEHT. 1/2-P1(1)- -4S - X106 5---- -Me-~--<

                                                                                                                                                                                                                                                                                                                                                                                                                 ~ T I O l t UNE HUMBER

-=-

M527 -I {f"/8)

          ~

C. EXN,IPU: COHttNUATION or Tl-£ AIIO',{ Ut<<: OUTSIDC CONTAINMt'.HT JS DESIGH.UED AS FOU.OWS (Wmf UNE NUM8£RS NOT SHOWN). 1 [12- 11812'\ ~ ~ y' 12 1 2 1/2-Pl(1 )-ST-XHIB - I COHT.ONOWG.

              !                                                                                                                                                                                                                               ----~~r lil52.7-\ (f"/ 6 )

RHR-V-206 ROIC,'AII.E SPOOL PIECE (RHR- RSP - 1) 19 ALI. ITEMS IN Cll:DSSHATCHED MEA ARE PART OF THE RHR srt:AM CONDENSING l,IOOE YIHlCH HAS 9EEN OE'.ACTIVAim. TMC PIPING. VALVES. AND INSTRUMENTATION M. SHOWN ONTH[Ot,IQW,IAREINSTALUll.lilOTOROPERAlEDVALVESTHATW.VEIIEEH

       &---l--~"~-i-~=:::::::::;:r::;;i l~~-~::-ii~~~=~FLtf:E;=#~A~*

D[-ENEJICIZOI N<<J UX:KO) Cl.DSC) ARE RHR-V-52A

• 8, RHR-V-l1A
• 8, RHR-V-2611

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• HEAT REMOVAL HEAT REMOVAL PCIU'OOL COOLIK6 Ill( ZIO.O X fO BTU/HR (1 HI OPE~ATING) t,. THE M)I STUN INLET PRESSURE SHALL IIE GREATER

                                                                                                                                                                                                                                                                                                                                                          ,_"A*

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                                                                                                                                                                      'P<<SS*fl8IA l,il.1                 IX X X                    X X X X X X                                '><      X      l,il.1                         Ill/                   Ix'   X             27. W.X FLOW ( RI.JNOVT) FO~ R- P-281S 81 00 CPM.

TEMP*F - Z'l5 zqs ~5 2,s 2,s 2,s 2'5 2'5 l.'15 l.'15 2'5 z,s 2"5 - as 125 4.., MArMQ5 *TDN=llil* ~b!'! l!: ~!'! L ~p,nrr THE SUPPLY SYSTEM IS RESPONSIBLE. HEAT REMOVA L PER HX fil.!jJ BTU/ HR (1 HX OPERATING) IEE NOTE 21 '5££ RCIC/11£rll FOR DESIGN CHANGE CONTROL OF THIS DOCUMEMT M Residual Heat Removal System Process Data Columbia Generating Station Final Safety Analysis Report Draw. No. 02E12-04,22,1 Rev. 9 Figure 5.4-17.1 Form No. 960690ai

Amendment 54 April 2000

                                         *                                     *                   * * * * *

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Residual Heat Removal System Process Data Columbia Generating Station Final Safety Analysis Report Draw. No. 02El2-04,22,2 Rev.6 Figure 5.4-17.2 Form No. 960690

Amendment 65 December 2019

                                         -J_                                                                                                         -

1000 - - - - - - - - - - - -...----,----,--....--....----.--~--,---r_-_- _-:-,- ---.---, 900

                   --l __                                                                                                                               -1 800 700 l
    .5 600 altll

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    .s,i  500 i
    ~400 iii
                                                          -                                                                                                              1000 j2 300 750 ll.

c I CD 200 J __ .5 j

500 250 I* 0 o ,.__ ...__-----'1000

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30+/-:oo:----1..---:-:4000+/-----504,oo_ _ __j._-1_ __._:__J_ __,~_.J 0 6000 7000 8000 U. S. Gallons per Minute Te&11 V9 D PERFORMANCE AT RATED CONDITIONS OF 1770 RPM & 1.0000 SP. GR. Flaw (OPM) -2i!!;B..!14-l.9!,l!.t.21/4-~~!t.f-.J.!,!ii.t!Lll.jf-illlZ2Lt!;,--.il!t-UWil~ =ll:u.. - -!tf---1.21l!.L.6.Jl---=:'""-J otal Dynamic Head (fNt)11--.....im/..U..--';!b?.llJ--Ell!>Z..4---':a.z..q_-.!t!!L!l,!___'illj!,Jl.f-__.;!!ll.,:iz.,._-!!!i.!...Lf- = ~--!.!~ Power (BHP),1--...,_._,.~4-PERFORMANCE AT RATED CONDmONS OF 1770 RPM & 1.0000 SP. GR. NPSHR referenced to centerline of suction flange RHR (LPCI) Pump Characteristics Columbia Generating Station (S/N 0473-111) P-2A Final Safety Analysis Report Draw. No. 960690.89 Rev. Figure 5.4-18 Form No. 960690 LDCN-16-004

Amendment 62 December 2013 Brake Horsepower BHP 10 5 0 100 8 90 Efficiency 7 80 70 6 Total Head in Feet x100 60 Efficiency, % 5 Head 50 4 40 40 3 NPSH in Feet 30 30 2 20 20 1 10 NPSHR at C.L. Suction Nozzle 10 0 0 0 0 1 2 3 4 5 6 7 8 Gallons Per Minute x 1000 RHR (LPCI) Pump Characteristics Columbia Generating Station (S/N 0801MP004399-1) P-2B Final Safety Analysis Report Draw. No. 960690.90 Rev. 1 Figure 5.4-19 Form No. 960690FH LDCN-12-036

Amendment 58 December 2005 Brake Horsepower x 100 10 BHP 5 0 8 90 Efficiency 7 80 6 70 Total Head in Feet x 100 5 60 Efficiency, % Head 4 50 40 NPSH in Feet 3 40 30 2 30 20 NPSHR at C.L. Suction Nozzle 1 20 10 0 10 0 0 1 2 3 4 5 6 7 8 Gallons Per Minute x 1000 RHR (LPCI) Pump Characteristics Columbia Generating Station (S/N 0473112) P-2C Final Safety Analysis Report Draw. No. 960690.91 Rev. Figure 5.4-20 Form No. 960690FH LDCN-05-000

Amendment 55 May 2001 600 500 100°F/hr Vessel Water Temperature (°F) 400 Assumed Flush Time 100°F/hr 300 212°F 200 100 Vessel Temperature Versus Time Two Exchangers Available 0 0 1 2 3 4 5 6 7 8 Hours After Control Rods Inserted Vessel Coolant Temperature Versus Time Columbia Generating Station (Two Heat Exchangers Available) Final Safety Analysis Report Draw. No. 960690.88 Rev. Figure 5.4-21 Form No. 960690

Amendment 66 15 14 13 12 11 10 7 6 5 4 LEGEND: 3

                                                                                                                                                                                                                                                                                                                                                                                                     .HllIES:

December 2021

1. ALL VALVES (EXCEPT Tl-lOSE a'I INSTRUMENT 1. AU. ITEMS MARKED

• ARE FURNISHED WITH ASSOCIATED EQUIPMENT.

LINES) SUFfJXED WITH A (V) DENOTE A

                                           ...--------------------------------------------------------------------------------------------------------------------1 4"RFW(l1)-+

3/4-" VENT VN...Vf. EXCEPT AS NOTED. 2. PIPING. VALVES, AND NSSOCIATED COt.lPONENTS ON THIS DRAWING SHALL BE CLASSIFIED NS FOLLOWS, EXCEPT AS STATED IN NOTE 10:

2. AU. VALVES (EXCEPT THOSE ON INSTRUMENT {BREAK POINTS INDICATED ON FLOW DIAGRAM).

UNES) sumxED WITH A (D) DENOTE A 3/4" PIPING AND VALVES OUT THROUGH THE OUTERt.lOST ISOLATION K DRAIN VALVE. VALVES, EXCEPT INSTRUMENT PIPING NS NOTED: J. Al..L VALVES SUFFIXED WITH A (TI-I) DENOTE A SEISMIC CATEGORY: I THROTTLED V/ILVE. QLL'UTY CLASS: I CODE GROUP: A

b. PIPING AND VALVES BEYOND OUTERMOST ISOLATION VALVES IN REH:TOR BUILDING:

SEISMIC CATEGORY: II } TO RWCU-T/SS-601 QUALITY CLASS: II

• ZONE (C/11) CODE GROUP: C

                                                                                                                                                                                                                                                                                                  '1'                                                                                                         INSTRUMENT LINES ANO LEAK OFF PIPING NS NOTED:

SEISMIC CATEGORY: I } QUALITY CLASS: I

• CODE GROUP: B j[-------------- - ----------

d. INSTRUMENT LINES ANO LEAK OFF PIPING AS NOTED:

THERWJ..~ g}.

                                                                                                                                                                                                                                                                                                                                                                                                                                         """"'"--'l.       "1llER..SUlO (LINE "A")

24"RFW(1)-4 f- - - - SEISMIC CATEGORY: QUALITY CLASS: g }e I CODE GROUP: DWG. M529 (G/13) PIPING AND VALVES IN RAOWASTE BUILDING EXCEPT AS NOTED IN I 2f AND 2h. SEISMIC CATEGORY: II QUALITY CLASS: II+ CODE GROUP: 0 + I AU. PIPING, VALVES AND ASSOCIATED EQUIPt.lENT EXCLUDING DEWINERALJZER {CODE GROUP C) IN THE RWCU (SMAU. BORE EACTORI VESSEL PIPES), CF, COND, CPR, MWR AND SA SYSTEMS IN RADWASTE BUILDING: SEISMIC CATEGORY: II QUALITY CLASS: II I CODE GROUP: 0 H I

                                                                                                                                       ~g ~

Q g. PIPING, VALVES, AND ASSOCIATED COMPONENTS REFERRING TO THIS gg~R0~1r: NOTE: I }

• I

                                                                                                                                       ~-,

ftWCU 1011 PIPING AND VALVES BEYOND OUTERMOST ISOLATION VALVES IN gg~J~:~r F100 24"RRC(2)-45 GJJ-f106 RADWASTE BUILDING AND RADWASTE CORRIDOR:

                                                                                                                                     '~    {:

DWG. M530-l1 (8/5) 8 24"RRC{2)-1-S II * }

• DWG. M530-1 (B/13)

TO l£AK DET. SYSTEM LD-SUM-604, ZONE (D/11) Rl'Vl~ I

                                                                                                                            ----- ~li: mo,:

HANGERS TO BE DESIGNED TO SEISMIC CATEGORY I IN SEISMIC AREA, SUCH AS THE Ro.cTOR BUILDING AND THE RADWASTE BUILDING

                              '1' 1

ELEV 521'- 0 1/4 CORRIDOR. HANGERS IN THE RADWASTE BLDG ARE QUALIFIED TO

                                                                                 -:-!:S_-:_1_                             {+"RRC(4)--4S-2:                                                                                                                                                                                                                                                                  SEISMICILCW)ING.
              ~ """" GJ3-R609 I

I CIRCUI.A PUMP RECIRCULATION PUI.IP e EXCEPT NS NOTED ON M619 lNSTRUMENT CONNECTION DIAGRAMS.

                 +------_J                                                                                                                                                                                                                                                                                                                                                                             +    SEE NOTE 12, CONTRACT 215, SECTION 1.5B, TABLE 2 NOTES.

G

              ~                                                                                                                                                                                                                                                                                                                                                                                      J. AU. PIPING SYSTEMS IDENTIFIED BY THIS PREFIX "p1* SHAU. BE SUPPLIED AND INSTALLED BY CONTRACT 220.
              ~""""

lfrs--+ EJ1-K602 -4. DELETED

5. AU. INSTRUMENT ROOT V>LVES t<<lT LABELED WILL BE J/4" GLOBE VALVES UNLESS SPECIFICALLY NOTED OTHERWISE.

6.(DELETEO)

7. EXCESS FLOW CHECK VALVES SHAU. BE TAGGED ,,S FOLl.OWS:

PI-EFC-X {PENETRATION NO.)

8. CONTAINt.lENT INSTRUt.lENTATION ROOT VALVES SHAU. BE TAGGED ,,S FOLLOWS: PI-V-X (PENETRATION).

9. (DELETED) 1O. AU. PIPING DOWN STREAM OF THE LAST ISOLATION VALVE. AND OPEN TO THE ATMOSPHERE WITH THE SUBSYSTEM DESIGNATION "SYSTEM" (50)

THRU (59), SHALL BE CLASSIFIED AS CODE GROUP "D", WITH QUALITY CLASS AND SEISMIC CATEGORY PRO'v1DED BY THE APPLICABLE NOTES IN THIS DRAWING. EXCEPT WHERE THE APPLICABLE NOTES CAU. FOR QUALITY CLASS II+, PIPING SHALL BE QUALITY CLASS II.

11. VALVES RWCU-V-210AAc8 ARE TO BE INSTALLED WITH THEIR FLOW ARROWS POINTED IN THE DIRECTION OF VALVES RWCU-V-2J-4Ml:B.

12. LINE NUMBERS IN PARENTHESES DENOTE RWCU-DM-1A SYSTEM IOENTinCATION.

13. NO UNIQUE LINE NUt.lBERS GIVEN FOR RWCU(AU.)-1 PIPING ,,S THESE ARE RADWASTE LINES.

R'M'.:ll-V-1514(V) RWCU-V-151JM 14. AU. INSTRUMENT LINES ARE DESIGNATED BY CODE AND LINE NUMBER. EXAMPLE, LINES ORIGJNATING OUTSIDE CONTAINMENT. 1/2"f>I(1)-ST - {H22-P021)-M (D)

                                             )-4-2                                                                                                                                                                                                                                                                                                                                                            ~TIO~

J/+"¥sR(53)-4S CONT ON M607-4 (H/10) b. EXAMPLE: LINES ORIGINATING INSIDE CONTAINt.lENT.

                                                                                                                              &--~fisl 1/rPI(1)-4S       -     X106
                                             '                                                                                   ~~                                                       FROt.l: SQRT-602
                                                                                                                                                                                                                                                                                                                                                                                                                ~

CODE DESIGNATION LINE NUMBER EJ~R&2 1A I EJl_oN505A _j- -:S'zONE {G/15)

                                               - - -51SOL A.J,E,Y,W SIGNAL TO RWCU-FCV-33

[i,J_ _ C§:}

                                                                                                                                                      -t-~     ~---,

_ --JFROt.l: SQRT-l!OJ ZONE {H/9) EXAMPLE: CONTINUATION OF THE ABCM: LINE OUTSIDE CONTAINMENT JS DESIGNATED AS FOLLOWS, WITH LINE NUMBERS NOT SHOWN. 1/2"Pl(1)-ST-X106 - (H22-P021) E (B/8) I

                                                                                                                              &-~: f:rw7 ~                                         -

EJ1-R520 EJ1-Kl504 L ~Ot.l: SQRT-605 ZONE {C/7) --------------- CODE DESIGNATION LINE '---v---" NUMBER FROW

15. CODE BREAK DEFINITIONS FOR THERMOWELLS ARE SHOWN ON M510, D

CRD-FS-2A DWG. M523-2 ~~ "INSTAI.I.ATION OF THERMOWELLS AND SAi.iPL£ PROBES." ZONE (H/9)

                                                                               'f'                                                      .,,_,,,,,                                                                                                                                                                                                                                                    16. RWCU-PS-114 CONTN::TS JUMPERED CLOSED TO INDICATE NORMAL PUMP SUCTION PRESSURE.

I FROt.l

                                                                                                                                          .J",..,1,.,..,,~,,,-.. """*

RWCU-DPlS-25 IZONE~1,4.) 17. VALVES RWCU-V-443 AND RWCU-SPV-443 HAVE BEEN DEACTIVATED TO

                                                                  ~-let---

PREVENT INADVERTENT RESIN SPILLS. ONM607-4(0/10) RWCU-V-52JM y-. 18. FOR SAMPLE FUNCTION & INSTRUMENTATION ASSOCIATED WITH THE

                                                                                                                          """"i.

SAMPLE POINTS SEE DWG. SERIES M607 STEN.I & LIQUID SAMPLING PUMP~AG.:5J-t<<l02A I I I

                                                                                                                                                              ~

TI GJJ-R607 J rr=;:.-:-=-=--=-=-:-::_-_-=1 __ FLOW DIAGRAMS AND DWG. SERIES 801.-00 SAMPLE RACKS DETAILS & FLOW DIAGRAt.lS.

                                                                                                                                                              ~         RWCU I 11           ROM R'NCU-TE-19 L                       I INTERLOCK                  I                                                       ...J I I I                                                                                                                                                                                                             111. SLUDGE LEVEL RWCU-LE-!12A AND !128, RWCU-LS-116"1/A.2 AND
                                                          ,---------------~-----------,

RWCU-V-624 ---1J. ~ONE (K/6) RWCU-LS-11681/82 ARE SPARED IN PLACE. THEY HAVE BEEN

                                                                                                                                            ,..,,_,__.., ( V ) ~ C l . ! . l . ~                                                                                                                                                                                                                          HISTORICALLY UNREI..IABL.E. SLUDGE LEVEL IS PRESENTLY MORE ltN/1                T/SS
                                                          !                             ~~/:                         !

RELIABLY DETERMINED AND CONTROLLED BY USING THE PPM (SOLID 1!101 -- 1501 RWCU WASTE PROCESSING SYSTEM). 1 (SEENOTE20) 1 RWCU G3J-N601 C GJJ-K601 I 20. PRIOR TO 1gg.5 RWCU PROCESS PIPING, PUMPS AND VALVES IN

                                                                                                                                                                                           -£ i                                                          i

CLEAN-UP  : BETWEEN RWCU-V-5.A/B AND RWCU-V-40 (BUT NOT INCLUDING THESE RWCU-V-459M TE

RECIRCULATION PUMPS  : VALVES OR SAFETY RELATED INSTRUMENT LINES) WERE ASME 111/3.

(SEE M523-2) RWCU-V-32 IN 1;115 BOC !55-21127-0,I, RECLASSIFIED THESE VALVES, PUMPS, AND PROCESS PIPING TO ANSI 831.1. FROt.l 2013 THESE VALVES, PUMPS, J/4"RWcU(~)-+-2 BYPASS LINE AND PROCESS PIPING HAVE BEEN RECLASSIFIED ASME lll/3 SEE NOTE 25 (REF AR 282022). 6"RWCU(3)-4-1(CL.J) PUMPIB 21. SEE DWG t.!501 FOR FLOW DIAGRAt.l LEGENDS, SYMBOLS AND INlERLOCK REFERENCES TO CON"l"RACT NUMBERS, I RWCU-V-109 'f' SUCH NS 215, 2~. 220, FOUND IN THE ABBREVIA NS, I FROM ~ NOTES ON THIS ORA.WING REFER TO

22. RELIEF VALVES RWCU-RV-.:56 AND RWCU-RV-26A/8 ARE ASME SECTION I

ORIGINAL CONSTRUCTION DESIGN VIII QUALITY CLASS II. L!..J RWCU-V-110 I ,~(F/14) REQUIREMENTS. 2J. RWCU-V-3" AND RWCU-V-J5 UPSTREAM DISC/WEDGE IS DRILLED

~GI CURRENT DESIGN REQUIREMENTS ARE

AH 28 1-- fRMsl DOCUMENTED IN THE STATION DESIGN (0.25" D!At.lETER :1:0.005") TO PREVENT PRESSURE LOCKING.

J, 1""0 SPEClFICATIONS AND ACTIVE CONTRACT SPECIFICATIONS WHICH STILL APPLY. 24. PER EC 15262, THESE VALVES, PUMPS & PROCESS PIPING LOCATED IN B  : FROM CRD-FS-2B I THE RAOWASTE BLDG HAVE BEEN RECLASSIFIED TO ANSI BJ1.1

DWG. M52J-2 I 1 (REF AR 282022).

t_ ___zoNE (c/9) ~~ ----------~ 6"cPR(28)-1

                                                                                                                                                                                                                   ~g~~?"w,.,.,."""T-----'""1-'-il11'5~in----===~-!-!?-C::::::J--~--=='-'--'""'-<"*_""        .....__,,---<::i------"'

25. PER EC 18434 A BYPASS LINE AROUND RWCU-V-.:52 IS INSTM..LED BETWEEN RWCU-Pl-8 AND RWCU-PS-1J WITHIN E-IR-P002. REFER TO CV! 02H22-05,26.

4"RWCU(60)-J-28 {S~JN~J20) (SEEN0T£20) 5"RWcU{S)-J-2 IS*RWCu 8 -1

                                                                                                                                                                                                                                                                 ,,,,,..,-J"IIWCU(5)-1 A

4"CPRJ4 -1 Reactor Water Cleanup System - P&ID Columbia Generating Station Final Safety Analysis Report Draw. No. M523-1 Rev. 124 Figure 5.4-22.1 Form No. 960690ai

15 14 13 12 11 10 8 4 Amendment 65 December 2019

                                                                                                                                                                                                                                                                          ~  NOTES ANO LECEND SEE M52J-1.

1/2"RWCU( l ) I

                                                                                                                                              * "RWCU(1) I CHEMICAL CLEAN I NG CONNECTION RWCU- ODC- 1A RWCu - v - ng    RWCU - \1- 760 J/*"RWCU(59) l

__J ____+_,_~ ::_--0-- ;;:,cc~-':.,-';,".;:;,.;-- -- 1 l/ 4 " 2 l/2"RCC(29)-1 ;g,.r~~c(i!i- ~525- 2 (D/8) H CRD - V- 50&,,

                                                                                                                                 <~fN~Tr762~)
                                                                                                                            '"ii':~~-~-:,~

112* cR0(50) - 4s G l /2"EOR( l )-1 r-=- " 1/2"[0R(1) -1 I 2"EOR(1)-1 J"EDR' r DWG M5J7 (f/10) RWC U PUM P ROOM IA 4"RWCU(J)-*-S 4~W';~iri~~~NG COl<IN[CT:U-ODC-29 Jj RWCU() 1/2"CRD(51) - 4S RWCu-v-1JB CHEMICAL CLEAN ING CONN[CTl:cu -ODC-1 9 5 4"RWCU(57)-.t- RWCU-V-?SS RWCU- V- 75 6 D

                                                                                                                                                                                                       )/ 4"RWCU(5 7) 6 CRD - \1-51 0B CRD - V- 503B C

J"CORY DWG M5J7 (f/9) Reactor Water Cleanup System - P&ID A Columbia Generating Station Final Safety Analysis Report Draw. No. M523-2 Rev. 9 Figure 5.4-22.2 Form No. 960690ai

15 14 12 J"COl\0 (10)-1 nr>- 11

                                                                                                                                                               ~ i!i;               --1 E====l-
                                                                                                                                                                             *~~~~~~~~~___j I'

10 3"SA(1._)_;.1.(<::;;

                                                                                                                                                                                                                                 . <e_;;Sa:,N>;.,a SC;.<J_ _ _ _ _           --{),,,1--------!----,-.._-----'+"""'"+-+...,,,

1 SA-1~ RWCU-J, 2"RWCU{51)-J 3 TE 2 e 2"RWCU(5 1)-1 2 Amendment 66 December 2021 2 *~wR( 66)-I (C Hrn lCAL CLEANING IN) ~=--=--==~--r-:-::::~-~~-i--::::~':::::::---r:=-::--:=--.- EL.4 72 '-g "

                                                                                                                                                                ----ii 2* ~wR(66)-1 SEE DWG. M5.34 (E/1) l;:'
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1. POSITIONS 28 & 29 IIIIICATE Cl.EAIIIP CmlDITIOIIS 111TH VARIOOS RBCCII INLET TOO'EIIATIIRES.

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Amendment 55 May 2001 600 500 100°F/hr Vessel Water Temperature (°F) 400 Assumed Flush Time 300 212°F 200 100 0 0 1 2 3 4 5 6 7 8 Hours After Control Rods Inserted Vessel Coolant Temperature Versus Time Columbia Generating Station (One Heat Exchanger Available) Final Safety Analysis Report Draw. No. 960690.92 Rev. Figure 5.4-25 Form No. 960690

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES TABLE OF CONTENTS Section Page 6.1 ENGINEERED SAFETY FEATURE MATERIALS................................ 6.1-2 6.1.1 METALLIC MATERIALS ............................................................ 6.1-2 6.1.1.1 Materials Selection and Fabrication ................................................ 6.1-2 6.1.1.1.1 Material Specifications ............................................................. 6.1-2 6.1.1.1.2 Compatibility of Construction Materials with Core Cooling Water and Containment Sprays ................................................................. 6.1-2 6.1.1.1.3 Controls for Austenitic Stainless Steel .......................................... 6.1-2 6.1.1.2 Composition, Compatibility, and Stability of Containment and Core Spray Coolants .................................................................. 6.1-3 6.1.2 ORGANIC MATERIALS .............................................................. 6.1-4 6.1.3 POSTACCIDENT CHEMISTRY..................................................... 6.1-5 6.2 CONTAINMENT SYSTEMS............................................................ 6.2-1 6.2.1 CONTAINMENT FUNCTIONAL DESIGN ....................................... 6.2-1 6.2.1.1 Pressure Suppression Containment ................................................. 6.2-1 6.2.1.1.1 Design Basis ......................................................................... 6.2-1 6.2.1.1.2 Design Features ..................................................................... 6.2-2 6.2.1.1.3 Design Evaluation .................................................................. 6.2-5 6.2.1.1.3.1 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 Analysis .................................................... 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 Blowdown ..................................... 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 Assumptions for Long-Term Cooling.................................... 6.2-9a 6.2.1.1.3.3.1.4 Initial Conditions for Accident Analyses ................................ 6.2-10 6.2.1.1.3.3.1.5 Short-Term Accident Response ........................................... 6.2-10 6.2.1.1.3.3.1.6 Long-Term Accident Responses .......................................... 6.2-11 6.2.1.1.3.3.1.7 Chronology 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 Accident Analysis ............................................. 6.2-15 6.2.1.1.3.3.4 Intermediate Size Breaks ..................................................... 6.2-15 6.2.1.1.3.3.5 Small Size Breaks .............................................................. 6.2-16 6.2.1.1.3.3.5.1 Reactor System Blowdown Consideration .............................. 6.2-16 6.2.1.1.3.3.5.2 Containment Response ..................................................... 6.2-16 6.2.1.1.3.3.5.3 Recovery Operations ........................................................ 6.2-17 LDCN-13-052 6-i

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Chapter 6 ENGINEERED SAFETY FEATURES TABLE OF CONTENTS (Continued) Section Page 6.2.1.1.3.3.5.4 Drywell Design Temperature Consideration ........................... 6.2-17 6.2.1.1.3.4 Accident Analysis Models ...................................................... 6.2-17 6.2.1.1.3.4.1 Short-Term Pressurization Model........................................... 6.2-17 6.2.1.1.3.4.2 Long-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 Pool Bypass Effects................................................. 6.2-20 6.2.1.1.5.1 Protection 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 Analytical Assumptions ......................................................... 6.2-21 6.2.1.1.5.4 Analytical 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 Containment 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 Analyses for Postulated Loss-of-Coolant Accidents ................................................................................ 6.2-29 6.2.1.3.1 Mass and Energy Release Data................................................... 6.2-29 6.2.1.3.2 Energy Sources...................................................................... 6.2-30 6.2.1.3.3 Reactor Blowdown and Core 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 Cooling 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 LDCN-05-009 6-ii

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Chapter 6 ENGINEERED SAFETY FEATURES TABLE OF CONTENTS (Continued) Section Page 6.2.1.6.4 Vacuum Relief Testing............................................................. 6.2-32 6.2.1.7 Required 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 CONTAINMENT 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 ISOLATION 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 Introduction .......................................................................... 6.2-46 6.2.4.3.2 Evaluation Against General Design Criteria ................................... 6.2-46 6.2.4.3.2.1 Evaluation 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-Pressure 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 Recirculation Pump Seal Water Supply Line ........................... 6.2-50 6.2.4.3.2.1.1.9 Low-Pressure Core Spray Line ........................................... 6.2-50 6.2.4.3.2.1.1.10 Residual Heat Removal Shutdown Cooling Return Lines .......... 6.2-50 LDCN-05-009, 06-064 6-iii

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Chapter 6 ENGINEERED SAFETY FEATURES TABLE OF CONTENTS (Continued) Section Page 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 Recirculation 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 Shutdown Cooling Line ...................... 6.2-51 6.2.4.3.2.1.3 Conclusion on Criterion 55 .................................................. 6.2-51 6.2.4.3.2.2 Evaluation 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-Pressure 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 Isolation 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-Pressure Core Spray, and Residual Heat Removal Relief Valve Discharge Lines ............... 6.2-53 6.2.4.3.2.2.1.5 Fuel Pool Cooling and Cleanup Return Lines.......................... 6.2-54 6.2.4.3.2.2.1.6 Deactivated Residual 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-Pressure Core Spray, Low-Pressure Core Spray, Reactor Core Isolation Cooling, and Residual 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 Suppression 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 Supply, Exhaust, and Inerting Makeup Lines . 6.2-55 6.2.4.3.2.2.3.3 Drywell and Suppression Chamber 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 Building 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 Cooling 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 LDCN-05-009, 06-039, 06-064 6-iv

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Chapter 6 ENGINEERED SAFETY FEATURES TABLE OF CONTENTS (Continued) Section Page 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 Maintenance Supply Line to the Drywell .... 6.2-57 6.2.4.3.2.2.3.9 Demineralized Water Maintenance 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 Conclusion on Criterion 56 .................................................. 6.2-58 6.2.4.3.2.3 Evaluation Against Criterion 57 ............................................... 6.2-58 6.2.4.3.2.4 Evaluation 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 Operator Actions .................................................................... 6.2-59 6.2.4.4 Tests and Inspections ................................................................. 6.2-60 6.2.5 COMBUSTIBLE GAS CONTROL 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 Monitoring System .................. 6.2-62 6.2.5.2.3 Containment 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 Core Cooling System Requirements for Protection from Physical Damage .................................................................... 6.3-4 LDCN-05-009, 06-039, 06-064 6-v

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES TABLE OF CONTENTS (Continued) Section Page 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-Pressure Core Spray......................................................... 6.3-5 6.3.1.2.2 Low-Pressure Core Spray ......................................................... 6.3-5 6.3.1.2.3 Low-Pressure Coolant Injection .................................................. 6.3-5 6.3.1.2.4 Automatic Depressurization System ............................................. 6.3-6 6.3.2 SYSTEM DESIGN ...................................................................... 6.3-6 6.3.2.1 Schematic Piping and Instrumentation Diagrams ................................ 6.3-6 6.3.2.2 Equipment and Component Descriptions .......................................... 6.3-6 6.3.2.2.1 High-Pressure Core Spray System ............................................... 6.3-6 6.3.2.2.2 Automatic Depressurization System ............................................. 6.3-9 6.3.2.2.3 Low-Pressure Core Spray System ............................................... 6.3-9 6.3.2.2.4 Low-Pressure Coolant 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 Suction Strainers .......................... 6.3-14 6.3.2.3 Applicable Codes and Classifications .............................................. 6.3-18 6.3.2.4 Materials Specifications and Compatibility ....................................... 6.3-18 6.3.2.5 System Reliability ..................................................................... 6.3-18 6.3.2.6 Protection Provisions ................................................................. 6.3-19 6.3.2.7 Provisions for Performance Testing................................................ 6.3-19 6.3.2.8 Manual Actions ........................................................................ 6.3-20 6.3.3 EMERGENCY CORE COOLING SYSTEM PERFORMANCE EVALUATION .......................................................................... 6.3-20 6.3.3.1 Emergency Core Cooling System Bases for Technical Specifications ....... 6.3-21 6.3.3.2 Acceptance Criteria for Emergency Core Cooling System Performance .... 6.3-21 6.3.3.3 Single Failure Considerations ....................................................... 6.3-22 6.3.3.4 System Performance During the Accident ........................................ 6.3-22 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 Accident 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 LDCN-10-004, 15-011 6-vi

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES TABLE OF CONTENTS (Continued) Section Page 6.3.3.7.2 DELETED. .......................................................................... 6.3-27 6.3.3.8 Loss-of-Coolant Accident Analysis Conclusions................................. 6.3-28 6.3.4 TESTS AND INSPECTIONS ......................................................... 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-Pressure 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 Core Spray Testing ............................................... 6.3-30 6.3.4.2.4 Low-Pressure Coolant Injection Testing ........................................ 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 Envelope ..................................... 6.4-2 6.4.2.2 Ventilation System Design ........................................................... 6.4-2 6.4.2.3 Leaktightness ........................................................................... 6.4-2 6.4.2.4 Interaction With Other Zones and Pressure Containing Equipment .......... 6.4-2 6.4.2.5 Shielding Design....................................................................... 6.4-3 6.4.3 SYSTEM OPERATIONAL PROCEDURES ....................................... 6.4-3 6.4.4 DESIGN EVALUATION .............................................................. 6.4-4 6.4.4.1 Radiological Protection ............................................................... 6.4-4 6.4.4.2 Toxic Gas Protection ................................................................. 6.4-4 6.4.4.2.1 Chlorine .............................................................................. 6.4-4 6.4.4.2.2 Sodium 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 INSTRUMENTATION REQUIREMENTS ........................................ 6.4-9 6.

4.7 REFERENCES

........................................................................... 6.4-9 LDCN-10-004, 15-011                              6-vii

COLUMBIA GENERATING STATION Amendment 60 FINAL SAFETY ANALYSIS REPORT December 2009 Chapter 6 ENGINEERED SAFETY FEATURES TABLE OF CONTENTS (Continued) Section Page 6.5 FISSION PRODUCT REMOVAL AND CONTROL SYSTEMS................. 6.5-1 6.5.1 ENGINEERED SAFETY FEATURE 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 Control (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 6-viii

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Chapter 6 ENGINEERED SAFETY FEATURES LIST OF TABLES Number Title Page 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 Initial 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 Long-Term Primary Containment Response Summary ............................................................. 6.2-76 6.2-7 Energy Balance for Design Basis Recirculation Line Break Accident .......................................................................... 6.2-77 6.2-8 Accident Chronology Design Basis Recirculation 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 LDCN-05-009, 06-039, 06-064 6-ix

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 Chapter 6 ENGINEERED SAFETY FEATURES LIST OF TABLES (Continued) Number Title Page 6.2-12 Secondary Containment Design and Performance Data .................. 6.2-83 6.2-13 DELETED (Replaced 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 DELETED 6.2-18 DELETED 6.2-19 Assumptions and Initial Conditions For Negative Pressure Design Evaluation ............................................................. 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. Recirculation 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. Recirculation Line Break ................................. 6.2-118 6.2-25 Flow Path Data for the Case of a 6-in. RCIC Line Break ............... 6.2-119 LDCN-20-010 6-x

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES LIST OF TABLES (Continued) Number Title Page 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 Suction Line Break HPCS DG Failure (Appendix K) ............................................ 6.3-45 6.3-4b Event Scenario for 0.07 ft2 Recirculation Suction Line Break HPCS DG Failure (Appendix K) ............................................ 6.3-46 6.3-5 ECCS Performance Analysis Results ........................................ 6.3-47 6.5-1 Standby Gas Treatment System Component Description Per Unit ..... 6.5-9 LDCN-10-004, 15-011 6-xi

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES LIST OF FIGURES Number Title 6.2-1 Typical 24 in. Downcomer Vent with Jet Deflector 6.2-2 Diagram of the Recirculation 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 Break (Initial Containment Pressure 2 psig) 6.2-5 Drywell Floor P Response for Recirculation Line 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 Cases A, B, and C - Original Rated Power 6.2-9 Suppression Pool Temperature Response, Long-Term Response - Original Rated Power 6.2-10 Containment Pressure Response - Case C Uprated Power 6.2-11 Drywell Temperature Response - Case C Uprated Power 6.2-12 Suppression Pool Temperature Response - Case C Uprated Power 6.2-13 Residual Heat 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 6-xii

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES LIST OF FIGURES (Continued) Number Title 6.2-16 Bounding Temperature Response - Main Steam Line Break Original Rated Power 6.2-17 Pressure Response - Recirculation Line Break (0.1 ft2) Original Rated Power 6.2-18 Temperature Response - Recirculation Line Break (0.1 ft2) 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 A x = 0.050 _t 6.2-22 Containment Transient for A JI K 0.0045 ft2 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 Region from 6 in. RCIC Line Break 6.2-26 Absolute Pressure in Lower Region 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 6-xiii

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES LIST OF FIGURES (Continued) Number Title 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 Temperature Transient 6.2-35 Short-Term Post-LOCA Secondary Containment Pressure Transient 6.2-36 Notes on Type C Testing 6.2-37 Isolation Valve Arrangement for Penetrations X-53, X-66, X-17A, and X-17B 6.2-38 Isolation Valve Arrangement 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 Arrangement for Penetrations 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 Arrangement 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 Arrangement for Penetrations X-65, X-25A, and X-25B 6.2-44 Isolation Valve Arrangement for Penetration X-100 6.2-45 Isolation Valve Arrangement for Penetrations X-18A, X-18B, X-18C, X-18D, X-3, and X-67 6-xiv

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Chapter 6 ENGINEERED SAFETY FEATURES LIST OF FIGURES (Continued) Number Title 6.2-46 Isolation Valve Arrangement for Penetrations X-20, X-14, X-23, and X-24 6.2-47 Isolation Valve Arrangement for Penetrations X-92, X-12A, X-12B, X-12C, X-6, and X-8 6.2-48 Isolation Valve Arrangement for Penetrations X-19A, X-19B, and X-13 6.2-49 Isolation Valve Arrangement 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 Penetrations X-47 and X-48 6.2-52 Isolation Valve Arrangement for Penetrations X-66, X-67, X-119, and X-64 6.2-53 Isolation Valve Arrangement for Penetrations X-42D, 54Aa, 54Bf, 61F, 62F, 69C, 78D, 78E, and 82E 6.2-54 Isolation Valve Arrangement for Penetrations X-85A, X-29A, X-85C, X-29C, X-72F, and X-73E 6.2-55 Isolation Valve Arrangement for Penetrations X-5 and X-93 6.2-56 Isolation Valve Arrangement for Penetrations 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 Penetrations X-94 and X-95 6.2-60 DELETED 6-xv

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 Chapter 6 ENGINEERED SAFETY FEATURES LIST OF FIGURES (Continued) Number Title 6.2-60A Isolation Valve Arrangement for Penetration X-58 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 Maximum Local Oxidation Versus Break Area - Hanford Original Rated Power LDCN-15-033 6-xvi

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 Chapter 6 ENGINEERED SAFETY FEATURES The engineered safety features (ESF) of this plant are those systems provided to mitigate the consequences of postulated 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, fission 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 consequences 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.

6.1-1

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 6.1 ENGINEERED SAFETY FEATURE MATERIALS Materials used in the engineered safety feature (ESF) components have been evaluated to ensure that material interactions will not occur that could potentially impair operation. Materials have been selected to withstand the environmental conditions encountered during normal operation and postulated accidents. Their compatibility with core and containment spray solutions has been considered and the effects of radiolytic decomposition products have been evaluated. Coatings used on exterior surfaces within the primary containment are suitable for the environmental conditions expected. Nonmetallic thermal insulation 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 Selection 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 coolant 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 construction 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 will occur on the ESF construction materials from allowable contaminant levels in this high purity water. 6.1.1.1.3 Controls for Austenitic Stainless Steel

a. Control of the use of sensitized stainless steel Wrought austenitic stainless steels that have been heated to temperatures over 800°F by means other than welding or thermal cutting are either resolution 6.1-2

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 annealed or otherwise demonstrated to be unsensitized in accordance with Regulatory Guide 1.44, Control of the 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 strength 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-worked 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 nonpressure retaining function and the controlled chemistry and pool temperature of the suppression pool.

d. Thermal insulation requirements All thermal insulation materials in ESF systems were selected, procured, tested, stored, and installed in accordance with Regulatory Guide 1.36, Revision 0.

The leachable concentrations of chlorides, 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. Certified 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. 6.1-3

COLUMBIA GENERATING STATION Amendment 58 FINAL SAFETY ANALYSIS REPORT December 2005 The quality of the water stored in the condensate storage tanks is maintained as follows: Conductivity* 1 S/cm at 25°C Chlorides 0.05 ppm pH* 6 to 8 at 25°C Boron (as BO3) 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 demineralization 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 exist 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 bearings are grease lubricated. Equipment, piping, and primary surfaces are provided with various coatings including galvanized zinc and aluminum. A minimal amount of hydrogen is liberated from zinc paint, galvanized, radiolytic and thermal decomposition of organic materials. Since Columbia Generating Station (CGS) is an oxygen control plant with an inerted containment, the hydrogen concentration is not flammable. Therefore, the minimal amount of hydrogen potentially generated by organic materials 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 (inorganic zinc). Approximately 4000 ft2 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 substrate. Regardless, the design of the ECCS strainers assumes the complete failure of the 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 CO2. LDCN-05-002 6.1-4

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 Facilities. In addition, the coatings and coating systems used meet the requirements of ANSI 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 ft2 of unqualified organic paint in the drywell. Under certain postaccident conditions, the unqualified 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 failure of the unqualified coatings, their transport to the wetwell, and their eventual entrainment on the strainer beds. 6.1.3 POSTACCIDENT CHEMISTRY Since the water chemistry conditions of the reactor 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 requires 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 discussed in the dose consequences analysis in Section 15.6.5. LDCN-05-009 6.1-5

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 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 LDCN-07-013 6.1-7

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 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 LDCN-14-018 6.1-8

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 Table 6.1-1 Engineered Safety Features Systems and Related Systems Component Materials (Continued) Component Form Material Specification (A/SA)a 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 Bar Alloy steel 540 B23/B24 Class 3 Standby liquid control pump Fluid cylinder Forging Stainless steel 182 Grade F304 Cylinder head, valve cover, and Plate Stainless steel 240 Type 304 stuffing box flange plate Cylinder head extension, valve Shapes Stainless steel 479 Type 304 stop, and stuffing box 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 LDCN-19-012 6.1-9

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Table 6.1-1 Engineered Safety Features Systems and Related Systems Component Materials (Continued) Component Form Material Specification (A/SA)a 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 6.1-10

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Table 6.1-1 Engineered Safety Features Systems and Related Systems Component Materials (Continued) Component Form Material Specification (A/SA)a 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 Section III pressure boundary item. 6.1-11

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2 CONTAINMENT SYSTEMS 6.2.1 CONTAINMENT FUNCTIONAL DESIGN 6.2.1.1 Pressure Suppression Containment 6.2.1.1.1 Design Basis The pressure suppression containment system, including subcompartments, meets the following functional capabilities:

a. The containment has the capability to maintain its functional integrity 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 further 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 design 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 will withstand coincident fluid jet forces associated with the flow from the postulated rupture of any pipe within the containment;

d. The containment design permits removal of fuel assemblies from the reactor core after the postulated LOCA;

e. The containment system is protected from or designed to withstand missiles from internal sources and excessive motion of pipes which could directly or indirectly endanger the integrity of the containment;

f. The containment system provides means to channel the flow from postulated pipe ruptures in the drywell to the 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 containment and its penetrations; and

h. The containment system, which includes the wetwell-to-drywell and the reactor building-to-wetwell vacuum breaker systems, can withstand the maximum LDCN-05-009 6.2-1

COLUMBIA GENERATING STATION Amendment 53 FINAL SAFETY ANALYSIS REPORT November 1998 calculated external pressure on the containment 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 could result from a postulated LOCA. The design ensures that the capability of the containment and other engineered safety feature (ESF) equipment which mitigate the consequences of an accident are not impaired by the dynamic effects of the accident. The design provisions are discussed in Section 3.8.2.

The capability of the primary steel containment vessel to withstand the hydrodynamic effects of safety/relief valve (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 discussed 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 water is sufficient such that operator action is not required for at least 10 minutes immediately 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 for core cooling.

c. Negative loading The primary containment is designed for the following negative loadings:

l

1. A drywell pressure of 2.0 psi below reactor building pressure, l

2. A wetwell pressure of 2.0 psi below reactor building pressure, and 6.2-2

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 t3. 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 j building-to-wetwell (RB-WW) vacuum breaker lines are sized to ensure that negative loadings are not exceeded. The vacuum breaker 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 differential allowed) the drywell pressure may be no less than 2 psi below the reactor building pressure.

d. Environmental conditions The means to maintain the required environmental conditions inside the primary containment during normal operation is discussed in Section 6.2.1. With the exception of energy removal from the suppression pool, there are no requirements for environmental controls during a LOCA. All equipment required to mitigate the consequences of an accident is designed to perform the required functions for the required duration of time in the accident environment.

The equipment accident environment 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 has been used to expedite the replacement of damaged reflective insulation panels when as low as is reasonably achievable (ALARA) considerations apply.

Reflective metal insulation panels used for the pipes are typically 2 ft long, 3 in. to 4 in. thick, and cover half of the pipes circumference. These panels have 24-gauge stainless steel sheets 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 inservice 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 LDCN-99-000 6.2-3

COLUMBIA GENERATING STATION Amendment 54 FINAL SAFETY ANALYSIS REPORT April 2000 weaker than the panels; therefore, 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 mass insulation that may be blown off constitute a credible debris source within the primary containment following a LOCA and seismic event. Equipment within 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 against 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 large 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 deflector stiffener plates rather than be swept through the downcomers into the suppression pool. Insulation fibers and bits of foil liberated by the rupture has a higher potential of reaching the suppression pool, either during the immediate 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 following 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 dislodged by a pipe rupture event is transported to the wetwell. The higher transport percentage, 76%, is used when dislodged insulation is below drywell grating that would hinder the transport of insulation to the wetwell; and

3. All metallic and fibrous insulation 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 LDCN-99-000 6.2-4

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 suppression pool following a LOCA. Based 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 Section 6.3.2.2.6. 6.2.1.1.3 Design Evaluation 6.2.1.1.3.1 Summary Evaluation. The key design parameters 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 line. Both accidents are evaluated. The most severe drywell temperature condition (peak temperature and duration) occurs for a small primary system rupture above the reactor water level that results in the blowdown of reactor steam to the drywell (small steam break). To demonstrate 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 intermediate 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 operation (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 SLO occurred at the maximum power/flow condition of 73.8% power/64.3% core flow. This peak wetwell pressure decreased by about 1% (0.5 psi) compared to the rated two-loop operation pressure. The diaphragm floor download and pool swell velocity evaluated at the worst power/flow condition during SLO were found to be bounded by the rated power analysis. The analytical results and method of analysis utilized to determine the seismic sloshing effects in the wetwell are discussed in Section 3.8.2. 6.2.1.1.3.2 Containment 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 pressure suppression vent system. LDCN-16-005 6.2-5

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 The downcomer loss coefficient is 2.77. This value was used in the assessment of the limiting containment performance analysis. The nonlimiting events not reanalyzed 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 performed to experimentally determine 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 PSAM 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 velocity (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 purposes during post blowdown long-term accident operation. Performance parameters given include 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 may impact suppression pool temperature. The analysis concludes that, when only one RHR heat exchanger is operable, two LPCI pumps and the LPCS pump must be secured. 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 functional evaluation was initially based on the consideration of several postulated accident conditions resulting in release of reactor coolant to the containment. These accidents include

a. An instantaneous guillotine rupture of a recirculation line,

b. An instantaneous guillotine rupture of a main steam line,

c. An intermediate size liquid line rupture, and LDCN-13-052 6.2-6

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017

d. A small size steam line rupture.

The containment response to the main steam line, intermediate liquid line, and small size steam line breaks, were bounded by the recirculation line break. As part of the evaluations to support the reactor power uprate to 3486 MWth (References 6.2-32, 6.2-33, and 6.2-35), only the recirculation line rupture (Case C), the bounding event for containment response, was reanalyzed. The containment 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 evaluate 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 associated 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 description of the analytical models and assumptions for this event. 6.2.1.1.3.3.1.1 Assumptions for Reactor Blowdown. The response of the reactor coolant system during the blowdown period of the accident is analyzed using the following assumptions:

a. The initial conditions for the recirculation line break accident are such that the system energy is maximized and the system mass is minimized. That is

1. For the nonlimiting events which were 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 uprate to 3629 MWt and bounds a power uprate to 3544 MWt (current).

3. For the containment analysis performed to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS), the reactor is operating at 3556 MWt.

LDCN-16-005 6.2-7

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 This power corresponds to 100.34% of 3544 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 were not reanalyzed for power uprate, the standby service water (SW) temperature 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 depressurization 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 region. 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 Moodys critical flow model (Reference 6.2-3) assuming liquid only outflow, since this assumption maximizes the energy releases to the drywell. 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, Moodys critical flow model, which assumes annular, isentropic flow, thermodynamic phase equilibrium, and maximizes slip ratio, accurately predicts vessel outflows through small diameter orifices.

Actual rates through larger flow areas, however, are less than the model indicates because of the effects of a near 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 using a conservatively high heat transfer coefficient throughout the depressurization period. The resulting high-energy LDCN-16-005 6.2-8

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 sensible energy of the fuel stored at temperatures 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 the shortest possible time of 3 sec following closure initiation. In actuality, the closure 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 pressure, which maximizes the calculated discharge of high-energy water into the drywell. For the containment analysis performed to evaluate reduced ECCS flow rates (RHR/LPCI and LPCS), MSIV closure was assumed to start 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 instantaneously at time zero. Since feedwater flow tends to depressurize the RPV, thereby reducing the discharge of steam and water into the drywell, this assumption is conservative for the analysis since MSIV closure cuts off 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 vital systems for long-term cooling be supported by onsite power supplies. LDCN-13-052 6.2-9

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2.1.1.3.3.1.2 Assumptions for Containment Pressurization. The pressure response of the containment during the blowdown period of the accident is analyzed using the following assumptions:

a. Thermodynamic equilibrium exists in the drywell and suppression chamber.

Since nearly complete mixing is achieved, the analysis assumes complete mixing;

b. The fluid flowing through the drywell-to-suppression pool vents is formed from a homogeneous mixture of the fluid in the drywell. The use of this assumption results in complete carryover of the drywell air and a higher positive flow rate of liquid droplets which conservatively maximizes vent pressure losses;

c. The fluid flow in the drywell-to-suppression 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 flooding, containment spray, and long-term decay heat removal. The containment pressure and temperature response during this period is analyzed using the following assumptions:

a. The low-pressure coolant injection (LPCI) pumps are 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 accident) all of the LPCI pump flow will be used to flood the core. In response to indications of significant core damage the operators are directed to initiate containment spray to reduce potential radioactivity released; 6.2-9a

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

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 heat 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 containment 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 available 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 uprate 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 Initial Conditions for Accident Analyses. Table 6.2-4 provides the initial reactor coolant system and containment conditions used in the accident response evaluation. The tabulation includes parameters for the reactor, the drywell, the suppression 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 for the containment response 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 recirculation line break are shown in Figures 6.2-3 and 6.2-4, respectively. The suppression chamber is pressurized by the carryover of noncondensables 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 suppression pool water peaks and the suppression chamber pressure stabilizes. The drywell pressure stabilizes at a slightly higher pressure; the 6.2-10

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 difference being equal to the downcomer submergence. During the RPV depressurization phase, most of the noncondensable gases initially in the drywell are forced into the suppression chamber. However, following the depressurization, noncondensables 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 condensed by the relatively cool ECCS water which is beginning to cascade from the break causing the drywell pressure to decrease. The ECCS supplies sufficient core cooling water to control core 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 the 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 thereby causes the drywell to depressurize. Table 6.2-5 provides the peak pressure, temperature, and time parameters for 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 drywell to the suppression pool for condensation of the steam. The pressure differential between the drywell and suppression pool controls this flow. Figure 6.2-6 provides the mass flow versus time relationship through the vent system for this accident. 6.2.1.1.3.3.1.6 Long-Term Accident Responses. To assess the adequacy of the containment following the initial blowdown transient an analysis was made of the long-term temperature and pressure response following the accident. The analysis 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 after 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 operating - with containment spray This case assumes that offsite ac power is available to operate all cooling systems. During the first 600 sec following the pipe 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 cooled before being discharged into the containment spray header. 6.2-11

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 depressurization 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 containment 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 accident 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 and is discharged to the containment spray line. The second LPCI 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 accident 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 pressure response to this set of conditions is shown in Figure 6.2-10. The corresponding drywell 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 temperature response is approximately the same as shown in Figure 6.2-9. Thus, the same amount of energy is 6.2-12

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 containment pressure is higher for the no spray case, the pressure is significantly less than the containment 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 Chronology 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 events for this accident from time zero is provided in Table 6.2-8. 6.2.1.1.3.3.2 Main Steam Line Break. The sequence of events immediately following the rupture of a main steam line between the reactor 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 reactor 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, through 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 isolation valves in the broken line would result in a slightly longer time before the total valve area of the three unbroken lines equals the flow limiter area in the broken line. The effective break 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 based on a bounding analysis of the superheated gas temperature. The short-term peak drywell 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 psia) is unchanged by power uprate, the initial break flow rate for this event is not impacted. This 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 assumed that the water level reaches the vessel steam nozzles 1 sec after the break occurs. The water level rise time of LDCN-13-052 6.2-13

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 quality results in fluid qualities which are considerably lower than would actually occur. 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 consist 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 power. The short-term performance 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 temperature 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 rapid drywell-pressure rise. The peak differential pressure occurs shortly after the vent clearing transient. As the blowdown proceeds, the primary system pressure and fluid inventory 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 suppression chamber pressures will stabilize. The pressure difference corresponds to the hydrostatic pressure of vent submergence. The drywell and suppression pool will remain in this equilibrium condition until the reactor vessel refloods. During this period, the emergency core cooling pumps will be injecting cooling water from the suppression pool into the reactor. This injection of water will eventually flood the reactor vessel to the level of the steam line 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 noncondensable gases from the suppression chamber will flow back into the drywell until the pressure in the two regions equalize. 6.2-14

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2.1.1.3.3.3 Hot Standby Accident Analysis. This section is not applicable to BWR-5. 6.2.1.1.3.3.4 Intermediate Size Breaks. The failure of a recirculation 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 breaks 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 ft2 break below the RPV water level. This break area was chosen as being representative of the intermediate size break area range. These breaks can involve either reactor steam or liquid blowdown. The consequences 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 ft2 break, the drywell pressure increases at approximately 1 psi/sec. This drywell pressure transient is sufficiently slow so that the dynamic effect of the water in the vents is negligible and the vents will clear when the drywell-to-suppression chamber differential pressure is equal to the vent submergence hydrostatic pressure. Figures 6.2-17 and 6.2-18 show the drywell and suppression chamber pressure and temperature response for original rated power conditions at 3323 MWt. The ECCS response is discussed in Section 6.3. Approximately 5 sec after the 0.1 ft2 break occurs, air, steam, and water will start the flow from the drywell to the suppression 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-term pool heatup until the vessel is depressurized and reflooded. The ECCS will be initiated as the result of the 0.1 ft2 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 terminate 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 pressures to equalize in the same manner as following a recirculation line rupture. The subsequent long-term suppression pool and containment heatup transient that follows is essentially the same as for the recirculation line break. 6.2-15

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2.1.1.3.3.5 Small 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 those 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 depressurization of the reactor system. The thermodynamic process associated 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 the drywell pressure will flash approximately one-third of this water to steam and two-thirds will remain as liquid. Both phases will be at saturation conditions corresponding to the drywell pressure. If the primary system rupture is located so that the blowdown flow consists of reactor steam only, the resultant steam temperature in the containment is significantly 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 and the safety equipment in the drywell. For larger steam line breaks, the superheat temperature is nearly the same as for small breaks, but the duration of the high temperature condition for the larger break is less. This is because the larger breaks will depressurize 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 pressure assumed for the original rated analysis (1055 psia) is unchanged by power uprate the initial break flow rate for this event will be unchanged. Assuming the operator action is the same, the event would be terminated in the same manner as for the original rated power analysis. Thus, the small 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. With 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 pressure increase in the drywell will lead to a high drywell pressure 6.2-16

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 signal that will scram the reactor and activate the 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 the 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 gradual pressurization of the 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 increase until the RHR heat exchanger heat removal rate is greater than the decay heat release rate. 6.2.1.1.3.3.5.3 Recovery 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 their 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 drywell will cease and the superheat condition will be terminated. If the plant operators elect to cool down and depressurize the reactor primary system more rapidly than at 100°F/hr, then the drywell superheat 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 temperature. Drywell design temperature requirements are defined by the most limiting environmental conditions assumed to exist inside primary 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-Term 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 the 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 result long-term steaming will not occur. This approach is conservative since removal of energy by steaming would require that more energy LDCN-07-011 6.2-17

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 be retained in the vessel, and therefore, not released to the containment 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 assumed 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 chamber 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 temperature if the sprays are activated, and

d. No credit is taken for heat losses from the primary containment or to the containment internal structure.

6.2.1.1.3.4.4 Energy Balance Consideration. The energy balance in the suppression pool is described in References 6.2-1 and 6.2-2. 6.2.1.1.4 Negative Pressure Design Evaluation Columbia Generating Station does 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 considerations, inadvertent spraying of the drywell is considered more than one single failure or operator error. The simultaneous operation of both containment spray loops after large and small-break LOCA could be a limiting transient for the containment 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 cooling 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. LDCN-14-040 6.2-18

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 The limiting transient for negative containment pressurization is a small-break LOCA with a coincident single failure of an RB-WW vacuum breaker. This 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 small break within the drywell forces the noncondensables into the wetwell airspace, leaving a steam atmosphere 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, the 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 appropriate plant procedures direct the operator to initiate drywell sprays in response to indications 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). LDCN-14-040 6.2-19

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Multiple valve failure is not considered 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 mechanism is considered more probable than failure of the vacuum breakers to open. It should also be noted that a single 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 Protection 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 nondestructive examination methods in accordance with the applicable ASME Codes. The design pressure differential for this boundary is 25 psid, which is substantially greater than conditions during a DBA. Actual peak accident differential pressure across this boundary 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 penetrations can be visually 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 isolation valves which are all normally closed. 6.2.1.1.5.2 Reactor Blowdown Conditions and Operator Response. In the unlikely event of a primary system leak in the drywell accompanied by a simultaneous 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 capacity 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 primary system break sizes which do not cause rapid reactor depressurization but rather have long leakage duration. These break sizes which are less than 0.4 ft2 require operator action to terminate the reactor blowdown if there is a bypass path. There would also be an increase in drywell pressure which leads to drywell venting to the wetwell by means of the downcomers. 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. I Operator action is required to mitigate the consequences of any bypass leakage. Emergency Operating procedures direct initiation of suppression chamber sprays at a chamber pressure l 6.2-20

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 available in the control room allowing the operator to track chamber pressure. Additionally, a two-division system of alarms is provided to alert the operator if the suppression chamber spray initiation value is reached. 6.2.1.1.5.3 Analytical Assumptions. When calculating the allowable leakage capacities for a spectrum of break sizes, the following assumptions are made:

a. Flow through the postulated leakage path 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 the steam entering the suppression chamber free space results in the additional containment pressurization, this is a conservative assumption; and

b. There is no condensation of the leakage flow on either the suppression pool surface or the containment and vent system structures. Since condensation acts to reduce the suppression chamber pressure, this is a conservative 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 Analytical 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 system break area. The area of _J 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 ft2, however, continued reactor blowdown limits the allowable leakage to small values. Burns and Roe, Inc., confirmed the results of the above analysis by GE in Reference 6.2-7. Further evaluation assigned the maximum allowable leakage capacity at A/ K = 0.050 ft2. _t Since a typical geometric loss factor would be three or greater, the maximum allowable flow path would be about 0.1 ft2. 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 6.2-21

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 pool from relief valve discharge. The limiting case was a very small reactor system break which would not automatically result 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 exceeds 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 containment, the reactor pedestal, the diaphragm floor and support columns, and the steel and concrete of the primary containment. Based on this analysis, the allowable bypass leakage used was 0.050 ft2. The drywell pressure transient is shown in Figure 6.2-21 along with the corresponding curves of wetwell pressure, wetwell temperature, and suppression pool temperature for the original rated power condition. The mandated allowable bypass leakage of 0.050 ft2 is above the Technical Specifications containment bypass leakage limits. Periodic testing is performed to confirm that the _f containment bypass leakage does not exceed ( A / K ) = 0.0045 ft2. Figure 6.2-22 presents the resulting containment transient of 0.0045 ft2. The peak containment pressure shown in Figure 6.2-22 is well below the containment 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 suppression 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 tolerance increase to 3%. This evaluation confirmed that there are sufficient conservatism in the suppression 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 Containment 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 containment coolers and two upper containment coolers 6.2-22

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 l J 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 heat producing equipment and the air space is normally less than 95F. However, leakage past the seating surfaces of MSRVs may cause the wetwell air space temperature to increase due to heat transfer from the MSRV tailpipes to the wetwell atmosphere. In this case, the wetwell air space can be periodically cooled 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 reactor operation. The containment purge system is not used to control containment temperature or humidity during reactor operation. To relieve pressure during reactor operation, the operator can establish a flow path from the drywell to the standby gas treatment (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 exhaust valves rather than the purge exhaust valve, flow can be limited to 170 scfm. This flow is adequate for a drywell atmosphere temperature 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 pressure. The 2-in. bypass valves would limit the radioactivity released prior to valve closure 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 way 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 supply duct through two 30-in. normally closed isolation valves into the primary containment. The purged nitrogen is extracted from the drywell through two 30-in. normally closed isolation 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, l LDCN-09-039 6.2-23

COLUMBIA GENERATING STATION Amendment 62 FINAL SAFETY ANALYSIS REPORT December 2013 t the radiation monitors at the exhaust air plenum would cause the reactor building ventilation and primary containment purge systems to isolate. Provision is also made to purge the nitrogen from the suppression chamber section of the I 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 system in the same manner as the drywell purge exhaust. The systems are designed to purge either the drywell or the suppression chamber or the two chambers in series or in parallel. To protect the pressure 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 operation 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 containment 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. IEach 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 signal, or on a containment isolation signal. IIf 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 system permits up to 75 cfh of nitrogen to be added to the containment during reactor operation to compensate for the postulated leakage listed in Table 6.2-1. The 2-in. bypass valves, used for pressure control during operations, 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 valves and are designed to close within 4 sec against the containment 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. LDCN-12-041 6.2-24

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 6.2.1.1.8.3 Post-LOCA. The unit coolers are not required after a LOCA since heat removal is then accomplished by the containment cooling 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 from oxygen control to hydrogen control upon loss of the ability to continue to inert with oxygen 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 containment 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 containment analyzed to determine the effects of subcompartment pressurization are the annulus between the sacrificial 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 single loop operation. Peak subcompartment pressures occur very quickly (during the first few seconds) during the limiting subcompartment pressurization events. Therefore, the pressurization is controlled by the initial break flow rates which 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 respect to subcompartment pressurization was determined to occur at 3702 MWt, 102% of design power limit 3629 MWt; therefore, the controlling parameters with power uprate were compared to the original values at this condition. The comparison shows that there are negligible differences between the controlling parameters for the original conditions used as the basis for the annulus pressurization and drywell head pressurization analyses and the corresponding parameters with power uprate and MELLLA (Reference 6.2-32 and 3.6-24). Therefore, the basis for the subcompartment pressurization loads is not affected by power uprate. LDCN-16-005 6.2-25

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Original Conditions Power Uprate Conditions (at 3463 MWt) (at 3702 MWt) Vessel dome pressure (psia) 1055 1055 Core inlet enthalpy (Btu/lbm) 532 532 Recirculation line break 8900 8900 critical mass flux (lbm/ft2-sec) Feedwater enthalpy 403 406 (Btu/lbm) Feedwater line break critical 19,300 19,200 mass flux (lbm/ft2_sec) The two areas within the primary containment considered to be subcompartments are the area within the sacrificial shield wall and the area above the refueling bulkhead plate at el. 583 ft. Potential pipe breaks within the sacrificial shield wall have been evaluated. 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 sacrificial shield wall, and 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 the design of the shield wall above the base, as stated in NRC letters (References 6.2-12 and 6.2-13). For the MELLLA evaluation 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 sacrificial shield wall, including the time/space dependent forcing functions, are presented in References 6.2-9 through 6.2-11 and 6.2-34. LDCN-10-004 6.2-26

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 These loads were used to produce response spectra for use in evaluating secondary effects such as the dynamic effects on piping systems, equipment, and components attached to the sacrificial shield wall of the RPV. The following changes were made in the original assumptions used in the sacrificial 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 insulation volume which is conservatively assumed not to be available. This approach is conservative and more realistic than other analyses where only the annular 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 occur 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 since it was determined that the small percentage reduction for the feedwater would not warrant the additional calculations; and 6.2-27

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

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. This model, in conjunction with the RELAP4/MOD5 computer program (Reference 6.2-14), was used to calculate the transient and energy 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 rates 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 the 24-in. recirculation line break are shown in Tables 6.2-22 and 6.2-23;

c. The subcompartment analyses for the case 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 the bulkhead plate and shows the sectional views and dimensions of the bulkhead vents;

d. The nodal volume data used for the analysis of a 6-in. RCIC line break in the upper head region and the analysis of a 24-in. recirculation 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 pressure variation in any direction is not expected. The two-node model used for the analyses is considered to be adequate and a sensitivity study is not necessary; 6.2-28

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

f. There are no movable obstructions in the vicinity of the vents. Insulation for piping and components was assumed to remain intact during the accident, and volume of insulation was subtracted from the nodal volumes;

g. The absolute pressure responses as a function 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. recirculation 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 functions 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 containment were included in the basic design. Since these compartments are large and relatively unencumbered, the loads are time-dependent but relatively uniform throughout. The time-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 the refueling bulkhead does not perform a safety-related function 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 shield 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 applied to maximize the energy release to the containment following a LOCA. 6.2.1.3.1 Mass and Energy Release Data Table 6.2-9 provides the mass and enthalpy release data for the recirculation line break. Blowdown flow rates do not change significantly during the 24-hr period following the 6.2-29

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 significantly during the 24-hr period following the accident. Figure 6.2-31 shows the vessel blowdown flow rates for the main steam line break as a function of time after the postulated rupture. This information has been employed in the containment response analyses. 6.2.1.3.2 Energy Sources The reactor coolant system conditions prior to the line break are presented in Tables 6.2-3 and 6.2-4. Reactor blowdown calculations for containment 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 discussed 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. The 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 and 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 and core reflood rates were evaluated with the model described in References 6.2-1 and 6.2-2. 6.2-30

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2.1.3.4 Effects of Metal-Water Reaction The containment systems are designed to accommodate the effects of metal-water reactions and other chemical reactions which may occur following a LOCA. The amount of metal-water reaction which can be accommodated is consistent with the performance objectives of the ECCS. Section 6.2.5 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 Cooling 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 integrity 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. This test is discussed in Section 6.2.6. 6.2.1.6.3 Drywell Bypass Leak Test Tests are conducted, in accordance with the Technical Specifications, to verify that the drywell-wetwell bypass leakage does not exceed an equivalent leakage of A / K equal to _f 0.0045 ft2. This is less than the bypass leakage allowed. 6.2-31

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 monitor containment parameters and to initiate safety functions is discussed in Chapter 7. 6.2.2 RESIDUAL HEAT REMOVAL CONTAINMENT 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, thus maintaining containment integrity 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 bulk temperature of the suppression pool to 204.5°F Iwhen considering the energy additions to the containment following a LOCA. I 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 requirements including the capability to perform its function following an SSE;

d. The system will remain operational during those environmental 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 (NPSH) is maintained on the RHR pumps even with the containment at atmospheric pressure, the suppression pool at a maximum temperature, and postaccident debris entrained on the beds of the suction strainers; and 6.2-32

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

g. Withstands dynamic effect of pipe breaks inside and outside of containment (see Section 3.6).

The primary containment unit coolers provide 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 Containment 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 the 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 achieve 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 automatically initiate containment cooling; however, the SW system is automatically initiated by the same signals which start up the ECCS. The capacity of power sources, including the standby diesels, is sufficient 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 LOCA 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. I The rated containment cooling flow, 7450 gpm, can be achieved through the LPCI line, the drywell spray line, or through the test line and wetwell spray line,Iwhich directs the heat exchanger discharge directly into the suppression pool. Thus, the design allows containment cooling 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. I 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. IIn addition, an electrical interlock prevents actuation of a drywell spray loop until the corresponding LPCI injection valve has been shut. A second electrical 6.2-33

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 may divert the flow directly to the suppression pool by shutting the LPCI injection valve and then opening the test line valve. Preoperational tests were performed to verify individual component operation, individual logic element operation, and system operation up to the 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 the 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 postulated design basis LOCA, the short-term energy release from the reactor primary system will be dumped to the suppression pool. This will cause a pool temperature rise of approximately 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 reactor 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 the plant operators shut the bypass valve on one RHR heat exchanger to start containment heat removal. Once containment cooling has been established, no further operator actions are required.

LDCN-13-052 6.2-34

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Each RHR pump suppression pool suction 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 the strainers, which will entrain additional debris following a LOCA. The potential for the additional accumulation 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 return lines in the suppression pool are shown in Figure 6.2-32. Mixing in the pool is primarily accomplished by the vertical and horizontal displacement between the suction and discharge line for a loop. The structures in the suppression pool act as baffles and improve mixing. Vertical 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 ponds. 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 exchanger isolation valves are normally open, some of the LPCI flow (approximately 40%) will flow through the heat exchanger. It is estimated that for break sizes resulting in RPV depressurization 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 after a large break would result in only a moderate increase in suppression pool temperatures. Summary of Containment Cooling Analysis When calculating the long-term, post-LOCA pool temperature transient, it is assumed that the initial suppression pool temperature is at its maximum value and that the SW temperature is as described in Table 6.2-4 throughout the accident period. These assumptions 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 condition at the time the accident occurs. This conservatively minimizes the heat exchanger heat removal capacity. The resultant suppression pool temperature transient is described in Section 6.2.1 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 evaluate reduced ECCS flow rates (RHR/LPCI and LPCS) are bounded by the power uprate analysis. When evaluating this long-term suppression pool transient, all heat sources in the containment are considered with no credit taken for any heat losses other than through the RHR heat exchanger. These heat sources are discussed in Section 6.2.1. Figure 6.2-13 shows the actual heat removal rate of the RHR heat exchanger. LDCN-13-052 6.2-35

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 GE SC 06-01 addresses the unlikely event of an inoperable RHR heat exchanger 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 timing for this action is detailed in Reference 6.2-42. In the event of an inoperable RHR heat exchanger, operating procedures ensure that the three low pressure pumps not providing operational 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 post-DBA containment temperature transient. LDCN-13-052 6.2-35a

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 6.2.2.4 Tests and Inspections The preoperational test program of the containment cooling 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 the secondary containment structure and the safety-related systems provided to control the ventilation and cleanup of potentially contaminated volumes of the secondary containment structure following a DBA. This section discusses the secondary containment design. The SGT system is used to depressurize and clean the secondary containment atmosphere and is discussed in Section 6.5.1. The secondary containment structure is synonymous with the reactor building. Sufficient openings exist among all areas of the reactor building 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 containment 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 physically and functionally part of the secondary containment during normal operation, expected transients, 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 primary containment. The secondary containment provides an additional barrier to fission product release when primary containment is operable. LDCN-18-025 6.2-36

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 The secondary containment structure, in conjunction 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 together with the reactor building ventilation system during normal operation to maintain building pressure greater than or equal to 0.25 in. of vacuum water gauge as indicated 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 secondary containment during normal and emergency operation. Thus, all the reactor building air is either exhausted through the exhaust air plenum, where it is constantly monitored, or discharged through the filtration units of SGT system. The reactor building pressure control system and the reactor building ventilation system are described in Section 9.4. The secondary containment isolation signals, secondary containment isolation valves, isolation valves for the reactor building ventilation system, SGT system, and reactor building pressure control system are all designed to Seismic Category I, Class 1E requirements. The design bases loads for the SGT system are given in Section 6.5.1. These systems can be periodically inspected and functionally tested. The secondary containment structure houses the refueling and reactor servicing equipment, the new and spent fuel storage facilities, and other reactor auxiliary 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 system, and electrical equipment components. The secondary containment structure protects the equipment from Seismic Category I disturbances, the design basis tornado and tornado-generated 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 and constructed in accordance with the structural design criteria presented in Section 3.8, and provides for low inleakage and outleakage during reactor operation. The building is designed to limit the inleakage rate to 100% of the reactor building free volume per day when maintained at a negative building 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, including gusts of 100 mph at an elevation of 30 ft above grade. The pressure of the design basis wind velocity on the reactor building is discussed in Section 3.3; LDCN-05-009 6.2-37

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

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 design allows for periodic inspections and functional tests of the penetrations, ventilation system (including automatic isolation), pressure control system, and SGT system;

f. The reactor building is designed to withstand applied wind pressures resulting from the design basis tornado. The effects 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 those lines identified as potential bypass leakage paths in Table 6.2-16, are the reactor building pressure control system, the reactor building ventilation isolation system, the isolation signals, and the standby power system. Normal reactor building ventilation system is not required to operate during accident conditions. I The system is automatically 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 associated with the SGT system are fitted with two motor operated butterfly valves in series. The motor operated valves, which are powered LDCN-05-009 6.2-38

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 from the essential power buses, are opened automatically, and the SGT system is started by any of the signals which isolate the secondary containment. Penetrations of the reactor building are designed with leakage characteristics consistent with leakage requirements of the entire building. Entrance to the reactor building is through interlocking double door personnel 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 vehicle door at the east end of the vehicle air lock, and the other interlocked door is the interior person door at the west end of the vehicle air lock. There are also two hatches that are interlocked with the vehicle air lock entrance doors. All entrances to the reactor building are through interlocking 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 indication 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 lock (railroad bay) exterior 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 mitigate fluctuations in reactor building pressure by such factors 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 differential pressure between the reactor building interior and the external atmosphere. The differential 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 indicates the least differential pressure controls the position of the blades in the normal reactor building exhaust fan units. I In the event of reactor building isolation, the reactor building pressure control system controls reactor building pressure by SGT system fan flow. Piping that connects to primary containment and passes through secondary containment is not considered a potential secondary containment bypass leak path if isolated by blind flanges or a rupture disc. LDCN-18-037 6.2-39

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Condensate from the condensate storage tanks can be used to flush ECCS and RHR shutdown cooling lines. Blind flanges are installed in the condensate system 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 secondary containment bypass leak paths. The spool pieces are installed to comply with the piping support 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 flanges at the other end. If connected to the corresponding RHR lines, blind flanges would be necessary to isolate potential secondary containment bypass leak paths. Table 6.2-16 presents a tabulation of primary containment 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 potential 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 building, will be treated by the SGT system. Lines that penetrate primary and secondary containment that normally contain water provide a water seal between the primary containment and the environment upon the primary isolation valve closure. If a break 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 system. Some lines that penetrate both the primary and secondary containment are seismically qualified outside of the secondary containment. These lines are considered closed systems and are not categorized as potential bypass paths. Lines that penetrate the primary and secondary containment are contained in one or more of the categories listed below.

a. Operate post-LOCA at pressure higher than the primary containment pressure or are seismically qualified.

b. Are vented to the secondary containment.

c. Are provided with water seal assessed against primary containment valve leakage characteristics.

Therefore, the primary containment isolation valve leak rate tests and SGT system operability tests are adequate to ensure that bypass leakage will not occur and separate leakage testing of the secondary containment isolation valves is not required. An additional conservative assumption of secondary containment bypass leakage of 0.04% volume per 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 water lines to the dose consequences were negligible. LDCN-05-009 6.2-40

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 The design and construction codes, standards, and guides applied to the buildings and SSCs are discussed in Chapter 3. 6.2.3.3 Design Evaluation The SGT system will maintain the secondary containment at a negative pressure with respect to the external environment following the design basis loss-of-coolant accident. The design flow rate of the exhaust system is based on the following criteria:

a. The rate of in-leakage assumption in based on the 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 Calculation Model The parametric analysis of secondary containment responses following a LOCA were performed using the general purpose thermal-hydraulic computer program GOTHIC (Reference 6.2-39). The GOTHIC program solves conservation of mass, momentum, and energy equations for multi-component, multi-phase flows. The phase balance equations are coupled by mechanistic models for 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 respective 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 reactor building floors (multiple elevations),

e. Room cooler efficiency, and

f. Secondary containment relative humidity.

LDCN-05-009 6.2-41

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2.3.3.2 Results A series of parametric studies were performed to evaluate varying meteorological conditions and heat loads on the drawdown analyses. Representative 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 Approximately parameter volumes totaling 3,500,000 ft3 b) Exhaust rate during drawdown 4800 cfm c) Secondary containment in leakage rate 2430 cfm d) Initial reactor building 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 secondary containment pressure at less than 0.25 inches of vacuum water gauge within 20 minutes. 6.2.3.4 Tests and Inspections. Components of the SGT system are tested periodically to ensure operability. The capability of the SGT system to maintain the secondary containment operability is tested in accordance with Technical Specifications. Tests 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 SGT system and differential pressure measurements of the secondary containment are taken. If during testing the SGT system fails to maintain the secondary containment pressure at 0.25 inches of water gauge or greater below atmospheric pressure at or below an SGT system air flow rate of 2240 cfm, 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 because isolation of the secondary containment necessitates the shutdown of the normal reactor building ventilation system which is required for the operation of non-ESF equipment housed in the secondary containment. LDCN-05-009 6.2-42

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2.3.5 Instrumentation Requirements Secondary containment negative pressure is automatically maintained by the reactor building pressure control system. During 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 instrumentation and controls for the reactor building pressure control system, primary containment and reactor vessel isolation control 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 when the unfiltered release of containment contents cannot be permitted,

b. Capability for rapid closure or isolation 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 lines 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 containment 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 isolation valves and associated piping and penetrations is to Seismic Category I requirements,

g. Containment isolation valves 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 LDCN-05-009 6.2-43

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

h. Containment isolation valve closure limits radiological effects from exceeding established requirements (10 CFR 50.67), including the effects of sudden isolation valve closure.

The primary objective of the containment isolation system is to provide protection against releases of radioactive materials to the environment as a result of accidents occurring to the nuclear boiler system, auxiliary systems, and support systems. This objective is accomplished by automatic isolation of appropriate lines that penetrate the containment system. Actuation of the containment isolation systems is automatically initiated at specific limits. The containment isolation systems, in general, close those fluid lines penetrating containment that support systems not required for emergency operation. Those fluid lines penetrating containment which support ESF systems have remote manual isolation valves which may be closed from the control room. Redundancy and physical separation are required in the electrical and mechanical design to ensure that no single failure in the containment isolation system prevents the system from performing its intended functions. The isolation system is designed to Seismic Category I. Classification 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 are 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 close automatically. LDCN-05-009 6.2-44

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2.4.2 System Design The general criteria governing the design of the containment isolation systems is provided in Sections 3.1.2 and 6.2.4.1. Table 6.2-16 summarizes the containment 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 isolation valves, actuators, and controls 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 evaluation techniques. Isolation valves are designed to be operable under the most adverse environmental conditions (see Section 3.11) such as operation under maximum differential pressures, extreme seismic occurrences, steam laden atmosphere, high temperature, and high humidity. Electrical redundancy is provided for power-operated valves. Power for the actuation of two isolation valves in line (inside and outside of containment) 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 isolation valves within containment receive power from a Division 2 power supply. In general, the supply is ac for Division 2 valves and dc for Division 1 valves depending on the system under consideration. The ability to provide appropriate containment integrity during a station blackout is discussed in Section 1.5.2. The main steam line isolation valves are pneumatic spring-loaded, piston-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 separate and independent action 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 includes consideration of the possible adverse effects of sudden isolation valve closure when the plant systems are functioning under normal operation. 6.2-45

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 materials to the environment. This is accomplished by complete isolation of system lines penetrating the primary containment. Redundancy is provided to satisfy the design requirement that any active failure of a single 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 the event of accident conditions. Instrument lines, in many cases, rely on a single mechanical barrier in the event of accident conditions. These isolation valve arrangements satisfy the requirements specified in GDC 54, 55, 56, and 57, and Regulatory 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 and 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 operable under the most severe operating conditions. Each isolation valve is protected by separation and/or adequate barriers from the consequences of potential missiles. Electrical redundancy is provided in isolation valve arrangements which eliminates dependency on one power source to attain isolation. Electrical cables for isolation valves 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 Against General Design Criteria 6.2.4.3.2.1 Evaluation 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 including the outermost isolation valve. The lines of the RCPB which penetrate the containment include provisions for isolation of the containment, thereby precluding any significant release of radioactivity. Similarly, for lines 6.2-46

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 which do not penetrate the containment but which form a portion of the RCPB, the design ensures that isolation of the reactor 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 isolation 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 isolation 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 booster 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 the vessel is partially depressurized. For this reason, the outermost gate valve does not automatically isolate upon signal from the protection system. The gate valve meets the same environmental and 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 water 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 specifically alert the operator to isolate the feedwater lines other than as described above since the lines both have check valves. However, 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 feedwater flow. No credit is taken for feedwater flow in assessing core and containment response to a LOCA. The applicable generic anticipated transients without scram (ATWS) studies (References 6.2-23 and 6.2-24) assumed the use of turbine driven feed pumps and simulated the loss of steam to the turbine and feedwater flow in the most limiting case in which all main steam lines were 6.2-47

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 isolated. In the ATWS situation, the loss of feedwater flow (or 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. IThe 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. ILong-term leakage control is maintained by this gate valve. I If a LOCA occurred, the gate valve would receive an automatic signal to open. 6.2.4.3.2.1.1.3 Low-Pressure Coolant Injection Lines. ISatisfaction of isolation criteria for the three LPCI injection lines of the RHR system is accomplished by use of remote-manually operated - - gate-valves

               --     and -

check-valves.

                                     -Both-types
                                               - of  - valves
                                                          -are ~  normally

_ closed _____.Iwith I.________, the gate valves receiving an automatic signal to open at the appropriate time Ito 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 pressure, 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 lines. The Hydraulic Control Units (HCUs) and scram discharge headers as well as the hydraulic lines are Seismic I, and are qualified to the appropriate accident environment. The failure 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 the HCUs. The HCU manual isolation valves 101 and 102 are provided for positive isolation in the 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 located in the CRD flange housing automatically 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 LDCN-05-009 6.2-48

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 (CRD-V-524/525) are located at the discharge of the CRD pumps to prevent significant 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 valves and the CRD HCUs, the SGT system will process the effluent prior to release from secondary 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 Report Regarding Integrity of BWR Scram Systems, that although the CRD system represents a departure from GDC 55, the CRD containment isolation provision stated 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. The check valve is located as close as practicable to the RPV. Two remote-manual block valves are utilized as isolation valves located outside the I containment. I The check valve ensures immediate isolation of the containment in the event of a line break. I The block valve on the RHR line receives an automatic isolation signal while the block valve on the RCIC line is remote manually actuated to provide long-term leakage control. I 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. I 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. I 6.2.4.3.2.1.1.7 Reactor Water Cleanup System. The RWCU pumps, heat exchangers, and filter demineralizers are located outside the drywell. IThe return line from the filter demineralizers connects to the feedwater line outside the containment between the block valve and the outside containment feedwater check valve. Isolation of this line is provided by the feedwater system check valve inside the containment, the feedwater system check valve outside the containment,Iand an RWCU motor-operated gate valve Ioutside the containment. The motor-operated gate valve functions as a third isolation valve. LDCN-05-009 6.2-49

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 In support of the RWCU Quality Group classification exception discussed in Section 1.8 (Regulatory Guide 1.26, Revision 3), Iadditional defense in depth isolation, in the event of a RWCU HELB in the Radwaste Building, is provided by valves RWCU-V-5A, RWCU-V-5B, RWCU-V-768, and RWCU-V-769. Valve RWCU-V-5A is the suction side isolation valve for RWCU-P-1A and valve RWCU-V-B is the suction side isolation valve for RWCU-P-1B. The pumps are in a parallel arrangement such that either pump is capable of supplying the RWCU system. As such, both valves are required to close to isolate RPV. These valves isolate the 4" RWCU suction lines to their respective pumps. These valves are motor operated valves capable of being closed from an easily accessible, local control panel outside the RWCU pump room. A small bore line provides a continuous source of cooler water to the RWCU pump suction to ensure adequate net positive suction head available (NPSHa). This line taps off the discharge of the RWCU non-regenerative heat exchanger and directs water to the common RWCU pump suction. Since this line effectively bypasses RWCU-V-5A and RWCU-V-5B, the two 3/4 inch diameter valves RWCU-V-768 and RWCU-V-769 provide defense in depth break isolation. RWCU-V-768 is a Code Group D check valve inline for the small bore pump suction cooling line, while RWCU-V-769 is a Quality Group C manually operated valve downstream of the check valve along the normal cooling flow path (upstream in a postulated break with reverse flow through this line.)I LDCN-16-028 6.2-49A

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 During the postulated LOCA, it may be desirable to restore reactor coolant cleanup. For this reason,Ithe motor-operated gate valve in the RWCU return line does not automatically isolate upon a containment isolation signal. I If reactor coolant cleanup is not required,Ithe return isolation valve RWCU-V-40 can be shut remotely from the control room when the motor-operated feedwater block valves are closed 20 minutes or more after the beginning of a LOCA. I Should a break occur in the reactor water cleanup return line, the check valves would prevent significant loss of inventory and offer immediate isolation, while the outermost isolation valve would provide long-term leakage control. I 6.2.4.3.2.1.1.8 Recirculation Pump Seal Water Supply Line. The recirculation pump seal water line extends from the recirculation pump through the drywell and connects to the CRD supply line outside the primary containment. The seal water line forms a part of the RCPB. The recirculation pump seal 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. IShould this line fail, the flow rate through 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-Pressure Core Spray Line. The LPCS 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. I 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 inside the RPV is less than the design pressure of the piping. 6.2.4.3.2.1.1.10 Residual Heat Removal Shutdown Cooling Return Lines. I The two shutdown cooling return lines inject into 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. I 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 part of the RCPB and penetrate containment are equipped with at least two isolation 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. I 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. The main steam lines extend from the RPV to the I main turbine and condenser system, and penetrate the primary containment. Isolation is afforded inside by a normally-open, fail-close, automatic, air-operated, y-pattern globe valve 6.2-50

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 H j and outside by a similar in-line globe valve paralleled by smaller automatic motor-operated gate valves, one each in the between-MSIV drain line and inIthe MSLC system tap I(isolated - MSLC system is deactivated). The main steam drain line, which 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 the containment. I The RHR steam supply line and RCIC turbine steam line connect to the main steam line inside the drywell and penetrate the primary containment. For these lines, isolation is provided by automatically actuated block valves, two parallel valves inside the containment common 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 deactivated and locked in the closed position. I 6.2.4.3.2.1.2.2 Recirculation System Sample Lines. A 0.75-in. diameter sample line from the recirculation system penetrates the drywell and is designed to ASME, Section III, Class l. A sample probe with a I1/8-in.Idiameter hole is located inside the recirculation line inside the I drywell. In the event of a line break, the probe acts as a restricting orifice and limits the escaping fluid. I Two automatic valves which fail close are provided; one inside and one outside the containment. 6.2.4.3.2.1.2.3 Reactor Water Cleanup System. The RWCU pumps, heat exchangers, and filter demineralizers are located outside the drywell. The supply line to the RWCU system connects to the reactor recirculation system lines on the suction side of the reactor recirculation pumps and to the RPV by means of the RPV drain line. Isolation of the RWCU lines is provided by two automatically actuated motor-operated gate valves. One valve is located inside containment and the other is located outside containment. Both valves are capable of remote manual operation from the control room. I 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-operated 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 Conclusion on Criterion 55. To ensure protection against the consequences of accidents involving the release of radioactive material, pipes which form the RCPB have been shown to provide adequate isolation capabilities. A minimum of two barriers were shown to protect against the release of radioactive materials. LDCN-05-009 6.2-51

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 In addition to meeting the isolation requirements stated in Criterion 55, the pressure retaining components which comprise the RCPB are designed 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 accordance 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 Evaluation Against Criterion 56. Criterion 56 requires that lines which penetrate the containment and communicate with the containment 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 isolation 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 are located outside containment, 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 such as the HCV system. 6.2.4.3.2.2.1 Influent Lines to Suppression Pool. 6.2.4.3.2.2.1.1 Low-Pressure Core Spray, High-Pressure Core Spray, and Residual Heat Removal Test and Minimum Flow Bypass Lines. The LPCS, HPCS, and RHR test lines have test isolation capabilities commensurate with the importance to safety of isolating these lines. Each line has a normally closed, motor-operated 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 containment. 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, paragraph 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, LDCN-15-033 6.2-52

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

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 and 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 conservative design of the piping and valve, conforming to SRP 3.6.2, precludes a breach of piping integrity.

The test return lines are also used for suppression chamber return flow during other modes of operation. In this manner the number of penetrations is reduced, minimizing the potential pathways for radioactive material release. ITypically, pump minimum flow bypass lines join the respective test return lines downstream of the 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 Exhaust, 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 possible. In addition, there is a simple check valve upstream of the gate valve 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 interlocked 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 normally 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 closed 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 heat exchanger relief valve discharge lines to the suppression pool. Two globe valves in each vent line provide the system pressure boundary and are used to control venting during the RHR heat exchanger filling and draining operations. IThe outboard globe valve in each line is and meets the criteria for a containment system isolation valve. IBoth valves are normally closed, remotely controlled motor-operated globe valves. Each vent line is also equipped with a manual block valve and the test connections necessary for Type C testing of the isolation valve. 6.2.4.3.2.2.1.4 Low-Pressure Core Spray, High-Pressure Core Spray, and Residual Heat Removal Relief Valve Discharge Lines. These relief valves discharge to the suppression pool 6.2-53

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 directly. They will not normally lift during operation and, therefore, can be considered as normally closed. 6.2.4.3.2.2.1.5 Fuel Pool Cooling 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. IThe four steam line relief valves (two per train) have been removed and the line flanges are blanked by structural connections. The two parallel-installed drain pot motor-operated globe valves (per train) are deactivated electrically and locked closed Ito 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 condensing mode lines. I 6.2.4.3.2.2.1.7 Process Sampling Suppression Pool Sample Return Line. Dual normally closed remote manual solenoid valves offer containment isolation. The valves are located I outside the containment based on NRC SRP 6.2.4, Section II, paragraph 6.d. 6.2.4.3.2.2.2 Effluent Lines 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 valves which provide assurance of isolating these lines in the event of a break. These valves also provide long-term leakage control. In addition, the suction piping from the suppression chamber is considered an extension of containment since it must be available for long-term usage following a design basis LOCA 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 waterleg pumps) take suction from ECCS pump suppression pool suctions downstream of the isolation 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 Pool Cooling Suction Line. Two normally closed automatic motor-operated gate valves, located outside the containment (based on NRC SRP 6.2.4, Section II, paragraph 6.d), provide containment isolation. LDCN-06-039 6.2-54

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2.4.3.2.2.2.3 PSR Suppression Pool Sample Line. Dual normally-closed remote manual solenoid valves offer containment 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. I 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 been de-energized. The motor operated gate valves have been locked closed, and the electrohydraulic operated valves are de-energized Ispring-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 piping 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 Containment Purge Supply, Exhaust, and Inerting Makeup Lines. The drywell and suppression chamber purge lines have isolation capabilities commensurate 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 are 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 the 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 isolation signal exists as noted in Table 6.2-16. Stainless-steel grills are installed 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 nitrogen 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 nitrogen lines is equipped with two automatic containment isolation valves, located as close as possible to primary containment. 6.2-55

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2.4.3.2.2.3.3 Drywell and Suppression Chamber Air Sampling Lines. The radiation monitor lines penetrate the primary containment and are used for continuously sampling containment air during normal operation as part of the leak detection system. I The supply lines are equipped with two automatic solenoid-operated isolation valves located outside 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 and as close as possible to the primary containment. This normally closed valve receives an automatic isolation signal. 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. I 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, butterfly valve. IThe air operator on the swing check valve is used only for testing. IThe air-operated butterfly valve is controlled by a differential pressure indicating switch which senses the pressure difference between the suppression chamber and the reactor building. When the negative pressure in the suppression chamber exceeds the instrument setpoint, the butterfly valve opens. I 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 damage. The arrangement of valves and instruments is shown in Figure 9.4-8. 6.2.4.3.2.2.3.6 Drywell Spray Lines. The drywell spray lines are equipped with two normally closed, motor-operated gate valves located outside and as close as possible to primary containment. The drywell spray must be manually initiated. I The piping from the outermost isolation valve to the spray ring header is constructed to withstand containment design conditions. 6.2.4.3.2.2.3.7 Reactor Closed Cooling Water Supply and Return Lines. Dual motor-operated automatic gate valves isolate each line, the former 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 normal system flow. Thus, the check valve functions as an 6.2-56

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 located outside the containment and as close as practical to the containment. The air test function 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 I lines consist of a check valve inside the containment and a motor-operated remote-manual globe valve outside the containment. I The globe valves are under the control of the operator who can isolate the single nonsafety-related header should the containment nitrogen (CN) supply be unavailable. The operator can also isolate either or both safety-related headers should either, or both, experience nitrogen supply problems or otherwise 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 threaded pipe cap inside the containment and isolated outside the containment by a locked-closed manual globe valve. 6.2.4.3.2.2.3.9 Demineralized 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 required 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, air-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 valves 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. IUpon receipt of a signal (manually initiated by the operator) this explosive valve will shear the TIP cable and seal the guide tube. 6.2-57

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 When the TIP system is inserted, the ball valve of the selected 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 calibrationIand 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 cable to be retracted and the ball valve to close automatically 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. IThe 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 Criterion 56. To ensure protection against the consequences of accidents involving release of significant amounts of radioactive materials, pipes that penetrate the containment have been demonstrated to provide isolation capabilities in accordance with Criterion 56 or other defined bases. In addition to meeting the above isolation requirements, the pressure retaining components of most of these systems are designed to the same quality standards 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 systems 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, Revision 0. Instrument lines which penetrate the containment from the RCPB are equipped with a restricting orifice located inside the drywell and an excess flow check (EFC) valve located outside and as close as practicable to the containment. Those instrument lines which 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. However, the RCPB instrument line EFC valves close to limit the flow in the respective instrument lines in the event of an instrument line break downstream of the EFC valve outside containment. The instrument lines are Seismic Category I and are assumed to maintain integrity for all accidents except for the instrument line break accident (ILBA) 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 may be used to reset an actuated disc. The bypass valves are periodically verified to be closed. LDCN-13-066 6.2-58

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 The hydrogen/oxygen monitoring lines penetrate primary containment and are used to continuously monitor the containment air during the post-LOCA accident period. These lines are equipped with single solenoid-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 required to remain open during normal operation and postaccident for those DBAs for which containment 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 automatic 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 systems, no distinction is made between mechanically active or passive components. All fluid system components such as valves are considered electrically active whether or not mechanical action is required. Electrical 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 perform 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 system component changes state or fails. Electrically operated valves include those that are electrically piloted but air operated as well as those that are directly operated by an electrical device. In addition, all electrically operated valves that are automatically actuated can also be manually actuated from the main control room. Therefore, a single failure in any electrical system is analyzed regardless of whether the loss of a safety function is caused by a component failing to perform a requisite mechanical motion or a component performing an unnecessary mechanical motion. 6.2.4.3.4 Operator Actions A trip of an isolation control system channel is annunciated 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 steam line tunnel temperature or main steam line excess flow,

c. Control power failure annunciation for each channel, and 6.2-59

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007

d. Annunciation of steam leaks in each of the systems monitored (main steam, reactor water cleanup, and reactor heat removal).

If the primary containment and reactor vessel isolation system does not automatically shut an isolation valve, the isolation 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 determine the need to operate 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 power operated isolation valves are tested remote manually from the main control room. By observing position indicators and/or changes in the affected system operation, the closing ability of a particular isolation valve is demonstrated. A discussion of testing and inspection pertaining 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. I As these valves are outside the containment and accessible, periodic visual inspection is performed in addition to the operational check. Sensor lines emanating from the suppression pool, the suppression 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 discussed 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 postulated LOCA. The RHR system operating in containment spray mode and redundant reactor head area return fans augment the natural processes to mix the containment atmosphere. The oxygen and hydrogen concentrations in the containment atmosphere are monitored by instrumentation discussed in Section 7.5.1.5. To supplement the combustible gas control system, the containment nitrogen inerting system provides a nitrogen atmosphere in primary containment. 6.2-60

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 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 turbulence 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 Icontainment spray system which can be actuated approximately 10 minutes after the postulated LOCA,Iand 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 chamber atmosphere; and 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 fission products (References 6.2-19 and 6.2-20) and it would be uniform throughout the containment. Accordingly, it is extremely unlikely that an atmosphere mixing system would be required. LDCN-20-010 6.2-61

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 However, the RHR system operating in containment spray mode and redundant reactor head area return fans are available to augment these 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 cooling 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 automatically upon reactor scram and are powered from different Class 1E electrical divisions. I 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 plate 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 continuously monitored during normal operation and following the postulated 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%. I If oxygen concentration approaches 4.4% by volume, a visual and audible high-high level alarm initiates in the control room. The hydrogen and oxygen gas analyzers, number and location of sampling points, and instrumentation are discussed in Section 7.5.1.5. Calibration tests are routinely performed to calibrate and verify instrument accuracy against known gas compositions. Two redundant hydrogen and oxygen concentration monitoring systems are provided. 6.2.5.2.3 Containment Purge Containment purge is discussed in Section 6.2.1.1.8. LDCN-06-039 6.2-62

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2.5.3 Design Evaluation The determination of the time-dependent oxygen and hydrogen concentrations in the drywell and suppression chamber atmospheres is based on a two-region model of the primary containment: a drywell and suppression chamber atmosphere. The rate of radiolytic hydrogen and oxygen generation varies linearly with power. The released fission products, excluding noble gases, that are mixed with the coolant are assumed to be swept out of core as the core cooling waters exit 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 oxygen generated from core radiolysis are assumed released to the drywell atmosphere and mix homogeneously. Hydrogen as well as oxygen generated from suppression pool radiolysis are assumed released to the suppression chamber atmosphere and mix homogeneously. The hydrogen and oxygen monitors are accurate at the anticipated concentration in the primary containment. 6.2.5.3.1 Hydrogen and Oxygen Generation In the period immediately after the postulated LOCA, hydrogen can be generated by radiolysis, metal-water, and metallic paint-water reactions. However, in evaluating short-term hydrogen generation, the contribution from radiolysis and metallic paint-water reactions are insignificant in comparison with the hydrogen generated by the metal-water reaction. During the same time period oxygen is generated by radiolysis only. However, the contribution from radiolysis is small compared with the initial 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 occurs. 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 virtually no metal-water reaction occurs and, therefore, hydrogen production by this means is insignificant. 6.2.5.4 Testing and Inspections The RHR drywell spray mode of operation is tested in accordance with Technical Specifications. The head area return fan testing is discussed in Section 9.4.11.4. Testing of the hydrogen and oxygen monitoring is discussed in Section 7.5.1.5.4. LDCN-15-011 6.2-63

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 establish 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 operation. The system is designed to comply with NRC staff position of April 2, 1981, requiring that the GE pressure suppression containment systems identified by Mark I and Mark II, be inerted. 6.2.6 CONTAINMENT LEAKAGE TESTING General Design Criteria 52, 53, and 54 have been met. 6.2.6.1 Containment Leakage Rate Tests The primary containment system is a steel pressure suppression system of the over and under configuration with a designed leakage rate of 0.5% by volume per day at 45 psig. A maximum allowable integrated vessel leak rate of 0.5% by weight per day at 38 psig has been established to limit leakage during and following 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 leakage rate does not exceed the maximum allowable at that reduced pressure. A structural integrity test involving pneumatic pressurization 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 accordance with the ASME Boiler and Pressure Vessel Code, Section III, 1971 Edition through the Summer 1972 Addenda, Subarticle NE-6300. See Section 3.8.2.7 for a description of the test. Testing involves performing 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 valves subject to Type C tests unless otherwise noted. LDCN-05-009 6.2-64

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2.6.2 Special Testing Requirements The secondary containment is tested 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. IFurther 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 Containment Analytical Model, NEDO-10320, March 1971. 6.2-2 James, A. J., The GE Pressure Suppression Containment Analytical Model, Supplement 1, NEDO-10320, May 1971. 6.2-3 Moody, F. J., Maximum Two-Phase Vessel Blowdown from Pipes, Topical Report APED-4824, GE Company. 6.2-4 MK II Containment Dynamic Forcing Functions Information Report (Revision 2), GE and Sargeant and Lundy, NEDO-21061, September 1976. 6.2-5 Plant Design Assessment Report for SRV and LOCA Loads (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 PLECMP) Final Report, GEAP-13197, GE, June 1971. 6.2-7 WPPSS Report, Drywell to Wetwell Leakage Study, WPPSS-74-2-R5, July 1974. (Supply System to NRC, Letter 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 Company, June 1975. 6.2-9 Washington Public Power Supply System, Nuclear Project No. 2, Report No. WPPSS-74-2-R2-A, Sacrificial Shield 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. LDCN-05-009, 06-039 6.2-65

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 6.2-11 Washington Public Power Supply System, Nuclear Project No. 2, Report No. WPPSS-74-2-R2-B, Sacrificial Shield Wall Design Supplemental Information, August 19, 1975. 6.2-12 Letter from R. C. DeYoung, NRC, to J. J. Stein, WPPSS, dated August 13, 1975,

Subject:

Sacrificial Shield Wall Design. 6.2-13 Letter from R. C. DeYoung, NRC, to J. J. Stein, WPPSS, dated October 15, 1975,

Subject:

Sacrificial Shield Wall Design. 6.2-14 ANCR-NUREG-1335, RELAP4/MOD5 - A Computer Program 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 Friction, by I. E. IdelChick, 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 Accident 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, Richland, Washington, July 1971. 6.2-19 J. G. Knudsen and R. K. Hilliard, 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 Containment 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 Experiment Interim Report, BNWL-1244, Battelle Northwest, Richland, Washington, February 1970. 6.2-22 D. K. Sharma, Technical Description Annulus Pressurization Load Adequacy Evaluation, January 1979 (NEDO 24548). 6.2-66

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 6.2-23 Studies of BWR Design for Mitigation of Anticipated Transients Without Scram, NEDO-20626, October 1974. 6.2-24 GE Response to NRC Status Report, GE ATWS Report, and Appendices, June and September, 1976 (Proprietary). 6.2-26 Flow of Fluids Through Valves, Fittings, and Pipe, Technical 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/Energy Report Entitled, Mass and Energy Release for Suppression Pool Temperature Analysis 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 Letter G02-93-180, dated 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. M87076 and M88625), dated 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 Power Uprate Project NSSS Engineering Report, GE-NE-208-17-0993, Revision 1, December 1994. LDCN-13-052 6.2-67

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 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 (Proprietary), 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 CSB 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, Technical 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) Subcompartment (Annulus) Pressurization Loads-Mass and Energy Releases. 6.2-44 GE-Hitachi Nuclear Energy, Safety Analysis Report for Columbia Generating Station Thermal Power Optimization, NEDC-33853P, March 2016. LDCN-16-005 6.2-68

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-1 Containment Design Parameters Suppression Drywell Chamber A. Drywell and Suppression Chamber

1. Internal design pressure, psig 45 45

2. External design pressure, psig 2 2

3. Drywell deck design differential pressure, 25 (downward) psid 6.4 (upward)

4. Design temperature, °F 340 275

5. Net free volume, ft3 (drywell includes 200,540 144,184 vents) maximum

6. Maximum allowable leak rate, %/day 0.5 0.5

7. Suppression chamber free volume, 142,500 minimum, ft3

8. Suppression chamber water volume 112,197 minimum,a ft3

9. Pool cross section area, ft2 5,770

10. Pool free surface cross section area, ft2 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, ft2 309

4. Downcomer maximum submergence, ft 12

5. Downcomer loss factor 2.77 a

This volume does not include the water within the pedestal (10,065 ft3) nor the water 12 ft below the downcomer exits (15,000 ft3) LDCN-13-052 6.2-69

LDCN-13-052 Table 6.2-2 Engineered Safety Systems Information for Containment Response Analyses Value Used in Containment Analysis COLUMBIA GENERATING STATION 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 FINAL SAFETY ANALYSIS REPORT b,d b

4. Spray flow rate, gpm/pump 7450 6713 6713 N/A N/A

5. Spray thermal efficiency, % 100 100 100 N/A N/A 6.2-70 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 b b

4. Spray flow rate, gpm/pump 450 353 353 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 D

7900 7067 b 7067 b 7067 b 6713 Amendment 63 December 2015

LDCN-13-052 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 COLUMBIA GENERATING STATION RHR system inverted U tube, single pass shell, multi pass tubes, vertical mounting

a. Number 2 2 1 1a 1 2

b. Heat transfer area, ft /Unit 7641 7641 7641 7641 7641

c. Overall heat transfer coefficient, 195(fouled) 195 195 195 195 FINAL SAFETY ANALYSIS REPORT Btu/hr ft2 F 400(clean) 6.2-71 d. Standby service water flow rate 7400 7400 7400 N/A N/A per exchanger, gpm

e. RHR heat exchanger K value 414(fouled) N/A N/A 289 f Btu/sec-°F 849(clean)

f. Design service water temperature minimum, °F 32°F 95b 95b 90 f maximum, °F 85°F

g. Containment heat removal 83.23 x 106 capability per loop, using 85°F service water and 165°F pool temperature; Btu/hr Amendment 63 December 2015

LDCN-13-066, 13-052 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 COLUMBIA GENERATING STATION

1. High pressure core spray (HPCS)

a. Number of pumps 1 1 1 1a 1 a

b. Number of lines 1 1 1 1 1

c. Flow rate, gpm 6350 6250 6250 6250a 6250 FINAL SAFETY ANALYSIS REPORT

2. Low pressure core spray (LPCS)

a. Number of pumps 1 1 0 0a 0 a

b. Number of lines 1 1 0 0 0 6.2-71a 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 b b a,b

c. Flow rate, gpm 1 pump 7450 7067 7067 7067 6713 Amendment 63 December 2015

LDCN-13-052 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 COLUMBIA GENERATING STATION

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 FINAL SAFETY ANALYSIS REPORT

1. Total number of safety/relief valves 18a

2. Number actuated on ADS 7a 6.2-71b 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 for 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. Amendment 63 December 2015

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-3 Accident Assumptions and Initial Conditions for Recirculation Line Break A. Effective accident break area (total), ft2 3.106/3.189d B. Components of effective break area:

1. Recirculation line suction nozzle area, ft2 2.508a

2. RWCU cross tie line ft2 0.078a

3. Jet pump nozzles, ft2 0.520a C. Break area/vent area ratio 0.0105/0.0103d D. Primary system energy distributionb

1. Steam and liquid energy, 106 Btu 414/361d

2. Sensible energy, 106 Btu

a. Reactor vessel 106.1/220d

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) 3.5/3.0d

3. Scram time (sec) <1a

4. Liquid carryover, % 100a

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 conservative value used in analysis. e Reactor vessel sensible energy includes reactor internals (less core) and primary system piping. LDCN-13-052 6.2-72

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-4 Initial Conditions Employed in Containment Response Analyses Original Rated Uprated Reduced Power Cases Power 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, ft3 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 water in miscellaneous 121 (a) (a) lines,c ft3

11. Total reactor coolant volume, ft3 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 LDCN-13-052 6.2-73

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-4 Initial Conditions Employed in Containment Response Analyses (Continued) Original Rated Uprated Reduced Power Cases Power ECCS Flow Drywell/ Drywell/ Drywell/ Suppression Suppression Suppression Chamber Chamber 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, ft3 NA/ NA/ NA/

107,850 107,850 107,850

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 6.2-74

Table 6.2-5 LDCN-13-052 Summary of Accident Results for Containment Response to Limiting Line Breaks Original Rated Power Uprated Power Reduced ECCS Flow Recirculation Steam Line Recirculation Recirculation Accident Parameters Line Breaka Breakb Line Break Line Break COLUMBIA GENERATING STATION

1. Peak drywell pressure, psig 34.69 34.0 37.4c,d 35.3c

2. Peak drywell diaphragm floor differential 19.39 19.1 21.7 (f) pressure, psid

3. Time (S) of Peak Pressures, Sec. 19.0 12.0 11.9 (g)

4. Peak drywell temperature, °F 280.2 328 283c 281c

5. Peak suppression chamber pressure, psig 27.3 31.3 30.3 FINAL SAFETY ANALYSIS REPORT

6. Time of peak suppression chamber 55 55 139 (g) pressure, sec.

7. Peak suppression pool temperature during 140 140 146 148.3 6.2-75 blowdown, °F (~100 sec.)

8. Peak suppression pool temperature, long 220 220 204.5 203.8 term, °F

9. Calculated drywell margin, %e 22.9 24.5 16.9 (f)

10. Calculated suppression chamber margin, 38.6 38.0 30.4 24.6

                  %e

11. Calculated deck differential pressure 22.44 23.6 13.2 (f)

Amendment 63 margin, %

12. Energy released to containment at time of 260 204 174 (f) peak pressure, 106 Btu

13. Energy absorbed by passive heat sinks at 0 0 0 0 December 2015 time of peak pressure, 106 Btu

LDCN-13-052 Table 6.2-5 Summary of Accident Results for Containment Response to Limiting Line 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. COLUMBIA GENERATING STATION d The value of Pa to be used for 10 CFR 50 Appendix J testing was conservatively chosen 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. FINAL SAFETY ANALYSIS REPORT 6.2-75a Amendment 63 December 2015

LDCN-13-052 Table 6.2-6 Loss-of-Coolant Accident Long-Term Primary Containment Response Summary LPCI and Service Containment HPCS LPCI and Peak Pool Secondary Case LPCS Water Spray (gal/min) LPCS Temp (F) Peak Pressure Pumps Pumps (gal/min) (gal/min) (psig) A Original rated power COLUMBIA GENERATING STATION 3462 MWt Before 600 seconds 3/1 3 0 6250 21,200/6250 180 7.3 After 600 seconds 3/1 3 14,134 6250 7067/6250 B Original rated power FINAL SAFETY ANALYSIS REPORT 6.2-76 3462 MWt Before 600 seconds 2/0 2 0 6250 14,134/0 220 13.5 After 600 seconds 1/0 2 7067 6250 7067/0 C Original rated power 3462 MWt Before 600 seconds 2/0 2 0 6250 14,134/0 220 18.3 After 600 seconds 1/0 2 0 6250 7067/0 C Uprated power Amendment 63 3702 MWt Before 600 seconds 2/0 2 0 6250 14,134/0 December 2015 204.5 14.3 After 600 seconds 1/0 2 0 6250 7067/0

LDCN-13-052 Table 6.2-6 Loss-of-Coolant Accident Long-Term Primary Containment Response (Continued) LPCI and Service Containment HPCS LPCI and Peak Pool Secondary Case LPCS Water Spray (gal/min) LPCS Temp (F) Peak Pressure Pumps Pumps (gal/min) (gal/min) (psig) COLUMBIA GENERATING STATION C Reduced ECCS Flow 3556 MWt Before 600 seconds 2/0 2 0 6250 13,426/0 203.8 15.9 6.2-76a FINAL SAFETY ANALYSIS REPORT After 600 seconds 1/0 2 0 6250 6713/0 Amendment 63 December 2015

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Table 6.2-7 Energy Balance for Design Basis Recirculation Line Break Accident Time of Peak Pressure Prior to DBA Difference Across End of Time of Peak a (0 sec) Drywell Deck Blowdown Containment Pressure Unit

1) Reactor coolant 414.0 x 106 400 x 106 12.2 x 106 49.4 x 106/44.8 x 106 Btu (vessel & pipe inventory)

2) Fuel and cladding Fuel 34.5 x 106 32.3 x 106 12.3 x 106 4.42 x 106/4.0 x 106 Btu 6 6 6 6 6 Cladding 3.05 x 10 3.05 x 10 2.99 x 10 1.07 x 10 /0.972 x 10 Btu 6 6 6 6 6

3) Core internals, also 91.2 x 10 91.2 x 10 91.2 x 10 34.0 x 10 /57.4 x 10 Btu reactor coolant piping, pumps, and valves

4) Reactor vessel 107 x 106 107 x 106 107 x 106 40 x 106/66.6 x 106 Btu metal

5) Reactor coolant Included in item 3 piping, pumps, and valves

6) Blowdown enthalpy NA 551 NA NA Btu/lbm 6 6 6 6

7) Decay heat 0 0.463 x 10 8.8 x 10 1020 x 10 /222 x 10 Btu

8) Metal-water 0 0 0.01 x 106 0.471 x 106/0.471 x 106 Btu reaction heat

9) Drywell structures 0 0 0 0

10) Drywell air 1.3 x 106 1.6 x 106 0 1.61 x 106/1.41 x 106

11) Drywell steam 0.759 x 106 7.75 x 106 24.8 x 106 8.43 x 106/6.06 x 106

12) Containment air 0.951 x 106 0.951 x 106 2.35 x 106 1.13 x 106/1.24 x 106

13) Containment steam 0.365 x 106 0.365 x 106 1.18 x 106 6.04 x 106/2.9 x 106

14) Suppression pool 639 x 106 629 x 106 1040 x 106 1450 x 106/1200 x 106 water

15) Heat transferred by 0 0 0 818 x 106/289 x 106 heat exchangers a

Values given are for minimum ECCS available and for all ECCS available. The information presented in this table is based on the original design basis conditions and represents the general characteristics of the recirculation line break analysis results. 6.2-77

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Table 6.2-8 Accident Chronology Design Basis Recirculation Line Break Accident Minimum ECCS Time (sec) Original Rated Uprated Power 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 6.2-78

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Table 6.2-9a Reactor Blowdown Data for Recirculation Line Break Original Rated Power Time Steam Flow Liquid Flow Steam Enthalpy Liquid Enthalpy (sec) (lb/sec) (lb/sec) (Btu/lb) (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 ---- ---- 6.2-79

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 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 saturated conditions in vessel. 6.2-80

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Table 6.2-10 Reactor Blowdown Data for Main Steam Line Break Time Steam Flow Liquid Flow Steam Enthalpy Liquid Enthalpy (sec) (lb/sec) (lb/sec) (Btu/lb) (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 ---- ---- 6.2-81

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 Table 6.2-11 Core Decay Heat Following Loss-of-Coolant Accident for Containment Analyses Original Rated Power Uprated Power Time (sec) Normalized Core Heata Normalized Core Heatb 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 reaction and fuel relaxation energy. The measurement uncertainty recapture project did not change the results obtained from the Uprated Power Normalized Core Heat. LDCN-16-005 6.2-82

COLUMBIA GENERATING STATION Amendment 59 FINAL SAFETY ANALYSIS REPORT December 2007 Table 6.2-12 Secondary Containment Design 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 reactor 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 during 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 after a design basis LOCA is discussed in Section 6.2.3.3.1. LDCN-05-009 6.2-83

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 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 Neutron monitoring Electrical penetrations are X-101 A, B, C, and D Control rod position indicator provided with double seals X-102 A and B Thermocouple and RTD and are separately testable. X-103 A, B, C, and D Medium voltage power The test taps and seals are X-104 A, B, C, and D Low voltage power located such that tests of X-105 A, B, C, and D Control and indication the primary can be X-106 C and D neutron monitoring conducted without entry X-107 A and B Low voltage power control into or pressurization of and indication containment II. Personnel And Equipment Access Penetrations X-15 Equipment hatch Separately testable without pressurization of the primary containment. X-16 Personnel access lock X-28 CRD removal hatch X-51 Suppression chamber access hatch X-1A through 1H Inspection ports X27-A through 27F TIP drive flanges N/A Drywell head X-23 EDR-V-18 Inboard flange X-24 FDR-V-15 Inboard flange X-77Aa RRC-V-19 Inboard & outboard flanges RRC-V-20 Inboard flange X-77Ac PSR-V-X77A/1 Inboard & outboard flanges PSR-V-X77A/2 Inboard flange X-77Ad PSR-V-X77A/3 Inboard & outboard flanges PSR-V-X77A/4 Inboard flange LDCN-08-028 6.2-84

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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 Inboard flanges CSP-V-5 X-67 CSP-V-4A Inboard flanges CSP-V-6 X-119 CSP-V-9 Inboard flange LDCN-15-038 6.2-84a

Table 6.2-16 Primary Containment Isolation Valves Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes CRD 185 insert lines 9 4.6-5 55 B -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- Yes 5 4, 48a CRD 185 withdrawal 10 4.6-5 55 B -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- Yes 5 4, 48a lines Air line for 93 6.2-55 56 B -- Pipe cap I -- -- -- -- -- O/C LC -- 2 -- -- No A Cap SB No 5 54 maintenance COLUMBIA GENERATING STATION All inst lines from pri -- -- 56 B -- EF check O Spring EF O O O -- 1/1.5 -- -- -- -- Vlv RB No 5 53 cont All inst lines from pri -- -- 56 B -- Globe O Manual Manual -- -- O O O -- 1/1.5 -- -- -- -- Vlv RB No 5 cont All inst lines from -- -- 55 A -- EF check O Spring EF -- -- O O O -- .75/1 -- -- -- -- Vlv RB No 5 27 RPV All inst lines from -- -- 55 A -- Globe O Manual Manual -- -- O O O -- .75/1 -- -- -- -- Vlv -- No 5 RPV FINAL SAFETY ANALYSIS REPORT 6.2-85 Deacon soltn return 95 6.2-59 56 B -- Pipe cap O -- -- -- -- C C C -- .75 -- -- No W Cap RB No 4 header Deacon soltn supply 94 6.2-59 56 B -- Pipe cap O -- -- -- -- C C C -- .75 -- -- No W Cap RB No 4 header Air line WW-DW vac 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 RVs Air line WW-DW vac 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 RVs 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 Amendment 61 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 December 2011 CIA line A for ADS 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 accum

LDCN-18-030 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes CIA line B for ADS 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 accum CIA line A for ADS 89B 6.2-38 56 B CIA-V-31A Check I Process Process -- -- C C C -- .5 -- -- No A Vlv RB No 5 accum CIA line B for ADS 91 6.2-38 56 B CIA-V-31B Check I Process Process -- -- C C C -- .5 -- -- No A Vlv RB No 5 COLUMBIA GENERATING STATION accum 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 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 FINAL SAFETY ANALYSIS REPORT 6.2-86 6.2-52 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 56 B CSP-V-8 PC check O Process Process -- RM C C C -- 24 -- 16 Yes A Vlv RB No 3 26, 56 6.2-52 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 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 and vent supply 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 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 and vent supply 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 6.2-46 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 Amendment 65 Drywell equip drain 23 6.2-46 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 December 2019 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, 56 SP pool cleanup 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 suction

LDCN-15-033 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes SP pool cleanup 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, 56 suction SP 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, 48a HPCS 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, COLUMBIA GENERATING STATION 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 Manual C 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 Manual C C O/C As is 12 17 9 Yes W Vlv RB No C 56, 48b, 18 FINAL SAFETY ANALYSIS REPORT 6.2-87 HPCS 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 Manual O 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 Manual C C O/C As is 12 27 22 Yes W Vlv RB No C 56,48b, 18, 58 Amendment 64 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 December 2017 MS lines drain inboard 22 6.2-41 55 A MS-V-16 MO gate I ac ac V,G, RM C C C As is 3 25 -- No S Vlv TB Yes M 52, 56, D,P 15 Hardened Containment 6.2-58 56 B HCV-V-1 AO butfy O Air Spring -- RM C C C C 16 -- 33 No A,S Vlv RBx Yes 2 16, 17 Vent 60A Hardened Containment 6.2-58 56 B HCV-V-2 AO butfy O Air Spring -- RM C C C C 16 -- 68 No A,S Vlv RBx Yes 2 16, 17 Vent 60A

LDCN-09-007 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes MS lines drain 22 6.2-41 55 A MS-V-19 MO gate O dc dc V,G, RM C C C As is 3 25 6 No S Vlv TB Yes N 52, 56, outboard D,P 15 MS line A inboard 18A 6.2-45 55 A MS-V-22A AO globe I Air Air/sp V,G, RM O O/C C C 26 3-5 -- No S Vlv TB Yes 2 1, 15, MSIV D,P 56, 63 COLUMBIA GENERATING STATION MS line B inboard 18B 6.2-45 55 A MS-V-22B AO globe I Air Air/sp V,G, RM O O/C C C 26 3-5 -- No S Vlv TB Yes 2 1, 15, MSIV D,P 56, 63 MS line C inboard 18C 6.2-45 55 A MS-V-22C AO globe I Air Air/sp V,G, RM O O/C C C 26 3-5 -- No S Vlv TB Yes 2 1, 15, MSIV D,P 56, 63 MS line D inboard 18D 6.2-45 55 A MS-V-22D AO globe I Air Air/sp V,G, RM O O/C C C 26 3-5 -- No S Vlv TB Yes 2 1, 15, MSIV D,P 56, 63 MS line A outboard 18A 6.2-45 55 A MS-V-28A AO globe O Air Air/sp V,G, RM O O/C C C 26 3-5 4 No S Vlv TB Yes 2 1, 15, MSIV D,P 56, 63 MS line B outboard 18B 6.2-45 55 A MS-V-28B AO globe O Air Air/sp V,G, RM O O/C C C 26 3-5 4 No S Vlv TB Yes 2 1, 15, FINAL SAFETY ANALYSIS REPORT 6.2-88 MSIV D,P 56, 63 MS line C outboard 18C 6.2-45 55 A MS-V-28C AO globe O Air Air/sp V,G, RM O O/C C C 26 3-5 4 No S Vlv TB Yes 2 1, 15, MSIV D,P 56, 63 MS line D outboard 18D 6.2-45 55 A MS-V-28D AO globe O Air Air/sp V,G, RM O O/C C C 26 3-5 4 No S Vlv TB Yes 2 1, 15, MSIV D,P 56, 63 MS line A drain 18A 6.2-45 55 A MS-V-67A MO gate O ac ac V,G, RM C C C As is 1.5 15 5 No S Vlv TB Yes 5 15, 56, isolation D,P 63 MS line B drain 18B 6.2-45 55 A MS-V-67B MO gate O ac ac V,G, RM C C C As is 1.5 15 5 No S Vlv TB Yes 5 15, 56, isolation D,P 63 MS line C drain 18C 6.2-45 55 A MS-V-67C MO gate O ac ac V,G, RM C C C As is 1.5 15 5 No S Vlv TB Yes 5 15, 56, isolation D,P 63 MS line D drain 18D 6.2-45 55 A MS-V-67D MO gate O ac ac V,G, RM C C C As is 1.5 15 5 No S Vlv TB Yes 5 15, 56, isolation D,P 63 MS line A loop 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 isolation MS line B loop 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 isolation Amendment 61 MS line C loop 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 isolation MS line D loop 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 isolation December 2011 Decon soltn supply 94 6.2-59 56 B MWR-V-124 Globe O Manual Manual -- -- LC LC LC -- .75 -- -- No W Cap RB No 5 header

LDCN-17-001 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes Decon soltn return 95 6.2-59 56 B MWR-V-125 Globe O Manual Manual -- -- LC LC LC -- .75 -- -- No W Cap RB No 5 header Rad mon return 72f 6.2-54 56 B PI-V-X72f/l Check I Process Process -- -- O O C -- 1 -- -- No A Vlv RB No 5 (S-SR-20) COLUMBIA GENERATING STATION Rad mon return 73e 6.2-54 56 B PI-V-X73E/1 Check I Process Process -- -- O O C -- 1 -- -- No A Vlv RB No 5 (S-SS-21) 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 FINAL SAFETY ANALYSIS REPORT 6.2-89 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 42d 6.2-53 56 B PI-VX-216 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-50A Air line for 54Bf 6.2-53 56 B PI-VX-218 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-41B Air line for 61f 6.2-53 56 B PI-VX-219 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-41A Air line for 62f 6.2-53 56 B PI-VX-220 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-41C Air line for 69c 6.2-53 56 B PI-VX-221 Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 Amendment 64 RHR-V-50B Rad mon supply 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 (S-SR-20) Rad mon supply 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 December 2017 (S-SR-20) Rad mon return 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 (S-SR-20)

LDCN-15-036 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes Rad mon return 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 (S-SR-21) Rad mon return 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 (S-SR-21) COLUMBIA GENERATING STATION Rad mon return 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 (S-SR-21) 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 FINAL SAFETY ANALYSIS REPORT 6.2-90 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 42d 6.2-53 56 B PI-VX-42d Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-50A Air line for 54Bf 6.2-53 56 B PI-VX-54Bf Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-41B Air line for 61f 6.2-53 56 B PI-VX-61f Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-41A Air line for 62f 6.2-53 56 B PI-VX-62f Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-41C Air line for 69c 6.2-53 56 B PI-VX-69c Globe O Manual Manual -- -- LC LC LC -- 1 -- 7 No A Vlv RB No 5 RHR-V-50B 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, Amendment 63 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 December 2015 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

LDCN-15-036 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes 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 COLUMBIA GENERATING STATION 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, FINAL SAFETY ANALYSIS REPORT 6.2-91 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 Amendment 63 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 December 2015 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

LDCN-08-028 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes RCIC 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 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 COLUMBIA GENERATING STATION vacuum breaker RCIC turb steam 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, supply 52 RHR cond mode steam 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 supply 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, 18 RCIC turb ex and ex 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 vacuum breaker FINAL SAFETY ANALYSIS REPORT 6.2-92 RCIC vacuum pump 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, dis 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 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 bypass RCIC turbine steam 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, supply 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/ -- -- O O/C O/C -- 24 -- 2 No W Vlv TB Yes 3 52, 31 spring RFW line B 17B 6.2-37 55 A RFW-V-32B PC check O Process Process/ -- -- O O/C O/C -- 24 -- 2 No W Vlv TB Yes 3 52, 31 spring RFW line A 17A 6.2-37 55 A RFW-V-65A MO gate O ac ac 31 Manual O O/C O/C As is 24 No 8 No W Vlv TB Yes C 56, 52, Amendment 61 31 n RFW line B 17B 6.2-37 55 A RFW-V-65B MO gate O ac ac 31 Manual O O/C O/C As is 24 No 8 No W Vlv TB Yes C 56, 52, 31 December 2011 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

LDCN-12-020 Table 6.2-16 Primary Containment Isolation Valves (Continued) u Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes 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 COLUMBIA GENERATING STATION 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, FINAL SAFETY ANALYSIS REPORT 6.2-93 48a Pump A and B suction 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, RV 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, Amendment 62 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, December 2013 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

LDCN-08-028 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes RHR 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 COLUMBIA GENERATING STATION 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 FINAL SAFETY ANALYSIS REPORT 6.2-94 SDC 20 6.2-46 55 A RHR-V-209 Check I Process Process -- -- C C -- -- .75 -- -- No W Vlv RB No 5 48b, 18 RHR 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, RM C O/C C As is 6 Std 28 Yes W Vlv RB No C 56, 57, M, R 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, Amendment 61 48b, 18 LPCI 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 December 2011 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

LDCN-19-031 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes LPCI 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 COLUMBIA GENERATING STATION 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, FINAL SAFETY ANALYSIS REPORT 6.2-95 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, RM C O -- As is 12 40 5 Yes W Vlv RB No C 56,48b, U, R 18, 28 SDC return B 19B 6.2-48 55 A RHR-V-53B MO gate O ac ac M, L, RM C O -- As is 12 40 5 Yes W Vlv RB No C 56, 57, U, R 59, 48b, 18 Heat exch vent 117 6.2-39 56 B RHR-V-73A MO globe O 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 6.2-39 56 B RHR-V-73B MO globe O ac ac 39 Manual C 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, RM C O -- As is 20 40 14 Yes W Vlv RB No N 56, 20, M, R 48b, Amendment 65 61, 18 SDC 20 6.2-46 55 A RHR-V-9 MO gate I ac ac L, U, RM C O -- As is 20 40 -- Yes W Vlv RB No N 48b, M, R 56, 61, 18, 20 December 2019 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 --

LDCN-16-042 Table 6.2-16 Primary Containment Isolation Valves (Continued) Valve Close Leak Term Pot Code Gp Valve Pwr to Pwr to Iso sig Back Norm Post Fail Pos Size Time Dist to Leads Proc Bar Zone Bypass SBO Line Description Pent Figure GDC (12) Valve EPN Type Loc Open (5) Close (5) (9) Up Pos (10) SD Pos LOCA (6) (14) (7,11) Pent to ESF Fld (13) (13) Leak (62) Notes RRC 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, 48a COLUMBIA GENERATING STATION RRC 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, 48a RWCU 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, 56 RWCU from reactor 14 6.2-46 55 A RWCU-V-4 MO gate O dc dc A,J,E, RM O O C As is 6 16.25 4 No W Vlv RW Yes 2 51, Y, W 48a, 56 RFW line A 17A/ 6.2-37 55 A RWCU-V-40 MO gate O ac ac 47 Manual O O O/C As is 6 No 24 No W Vlv TB Yes C 56, 52 17B Air line for 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 maintenance FINAL SAFETY ANALYSIS REPORT 6.2-96 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 Shear O -- Exp 43 -- O O O O .375 -- 2 No A Vlv RB No 5 29 Amendment 64 TIP lines 27B -- 56 B TIP-V-8 Exp Shear O -- Exp 43 -- O O O O .375 -- 2 No A Vlv RB No 5 29 TIP lines 27C -- 56 B TIP-V-9 Exp Shear O -- Exp 43 -- O O O O .375 -- 2 No A Vlv RB No 5 29 December 2017

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation Valves (Continued) ISOLATION SIGNAL CODESa Signal Description Ab Reactor vessel low-low water level (Trip level 2) Cb High radiation - main steam line Db Line break - main steam line (steam line tunnel high temperature, high differential temperature or steam line high flow) Eb Reactor water cleanup system high differential flow or high 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 three 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 exhaust plenum high radiation a See notes 30 through 46 for isolation signals generated by the 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 primary 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. LDCN-09-007 6.2-97

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 Table 6.2-16 Primary Containment Isolation Valves (Continued) ABBREVIATIONS/LEGEND Valve Type AO air-operated EHO electrohydraulic operated MO motor-operated PC positive closing SO Solenoid operated Location I inside containment O outside containment Power to Open/Close AC ac electrical power DC dc electrical power EF excess flow pp 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 steam W water Termination Zone CS condensate storage tank RB reactor building RBx reactor building external RW radwaste building SB service building TB turbine building LDCN-15-033 6.2-98

COLUMBIA GENERATING STATION Amendment 65 FINAL SAFETY ANALYSIS REPORT December 2019 Table 6.2-16 Primary Containment Isolation Valves (Continued) NOTES Type C testing is discussed in Figures 6.2-36 through 6.2-60A 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 pressure 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 that allow them to be manually reopened after automatic closure. This 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 opened for test or operating convenience.

3. The air test function 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-56.8-2002, Section 3.2.5). These lines 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 constitute potential Primary Containment Atmospheric pathways during and following a design basis accident (NEI 94-01, Section 6.0, and ANSI/ANS-56.8-2002, Section 3.3.1(1)). See Section 6.2.4.3.2.1.1.4 for additional design information.

5. Alternating current motor-operated valves required for isolation functions are powered from the ac standby power buses. Direct current 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.

LDCN-19-021 6.2-99

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation Valves (Continued) NOTES

7. STD - The close limit is based on a standard minimum closing rate of 12 in. of nominal valve diameter per minute for gate 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 Testing 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 generated by the individual system process control signals or for remote manual closure based on information 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 Position 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 personnel safety are locked, sealed, or otherwise secured in the closed position. Valves 1.5 in. and smaller connected to vents, drains, or test connections must be closed but need not be sealed.

11. The specified closure rates are as required 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 containment leakage which may 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.

LDCN-09-007 6.2-100

COLUMBIA GENERATING STATION Amendment 64 FINAL SAFETY ANALYSIS REPORT December 2017 Table 6.2-16 Primary Containment Isolation Valves (Continued) NOTES

16. Utilizes rupture discs downstream of the PCIVs and upstream of the secondary containment penetration to establish a closed system for compliance with GDC 56.

17. Rupture discs prevent secondary containment bypass leakage.

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 psig (1.5 times containment 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 secondary containment bypass leak path through the condensate system by a blind flange installed on the RHR piping flange. The spool piece, COND-RSP-1, is connected to the condensate 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 shut 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 remotely shut the valve by means of a pneumatic operator. The operating switch is spring-return to neutral so the vacuum breaker function will not be impaired.

LDCN-15-033 6.2-101

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation Valves (Continued) NOTES

27. Instrument lines that penetrate primary containment conform to Regulatory Guide 1.11.

The lines that connect to the reactor pressure boundary include a restricting orifice inside containment, are Seismic Category I and terminate in instruments that are Seismic Category I. The instrument lines also include manual isolation 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 integrity of the lines are continuously demonstrated during plant operations where subject to reactor operating pressure. In addition, all lines are subject to the Type A test pressure on a regular interval. Leaktight integrity 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 secondary containment bypass leak path through the condensate system by a blind flange installed on the RHR piping flange. The spool piece, COND-RSP-2, is connected to the condensate 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 testing to destruction, they are not Type C tested. Technical Specifications surveillance requirements ensure shear valve operability. See subsection 6.2.4.3.2.2.3.11 for a TIP system isolation evaluation against General Design Criterion 56.

30. Deleted.

31. PCRVIS is not desirable since the feedwater 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. 6.2-102

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation 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-manually shut isolation valve RCIC-V-31. The I system would be manually isolated on a reactor building sump high level alarm if RCIC is determined to be the source of leakage in the reactor building.

33. The RCIC minimum flow valve 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. I The RCIC injection valve is open only during RCIC 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 turbine throttle valve is closed following a turbine trip.

35. The RCIC steam exhaust valve, 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 barometric 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 below 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 appropriate reactor building sump.

39. These valves are deactivated. The valves are shown as motor operated, however, the power leads to the motors have been disconnected and the handwheels have been chained and padlocked in the closed position.

6.2-103

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation Valves (Continued) NOTES

40. Normally closed. Signaled to open if reactor building pressure 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 CIA-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-manually shut valve CIA-V-30(A, B) should the nitrogen bottle bank pressure decrease below the alarm setpoint. Isolation check valves CIA-V-31(A, B) provide immediate isolation.

43. The TIP shear valves are remote-manually closed following 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 normally open. Closed during testing.

45. The isolation valve can be remote-manually closed upon indication 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 isolation signals. The valve closure requirement is indicated by a high level alarm in the appropriate 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 valves provide immediate isolation.

48a. Not subject to Type C leak testing, per Primary Containment Leakage Rate Testing Program. Prepared per Option B of 10 CFR 50 Appendix J. 6.2-104

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation Valves (Continued) NOTES 48b. The isolation valve is tested with water. IThe maximum 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 the suppression pool. Valves RCIC-V-110 and RCIC-V-113 serve as an extension 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 based 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 for the potential bypass leak paths will not exceed 0.04 percent of primary containment volume per day.

53. Instrument lines that penetrate primary containment conform to Regulatory Guide 1.11.

These lines include manual isolation 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 extensions of primary containment 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 potential secondary containment bypass leakage paths and are not required to meet the requirements for secondary containment 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.

6.2-105

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation 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 secondary containment bypass leak path through the condensate system by a blind flange installed on the RHR piping flange. The spool piece, COND-RSP-3, is connected to the condensate 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 secondary containment bypass leak path through the condensate system by a blind flange installed on the LPCS piping flange. The spool piece, COND-RSP-5, is connected to the condensate 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 secondary containment bypass leak path through the condensate system by a blind flange installed on the RHR piping flange. The spool piece, COND-RSP-6, is connected to the condensate 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 secondary containment bypass leak path through the condensate system by a blind flange installed on the RHR piping flange of COND-RSP-4.

6.2-106

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation 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 there is no by-pass leakage from the RHR pump suction line to the condensate storage tanks. The condensate system can be used to flush RHR shutdown cooling through a spool piece. The connection creates a potential secondary containment bypass leak path. This penetration is isolated from a potential secondary containment bypass 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 valve 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 closed 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 valve cannot be in a line that communicates directly with the containment atmosphere). 5 Valve is less than 3 in. nominal diameter. 6.2-107

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation 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 identifies how this set of valves was addressed: Criterion Additional Basis for Exclusion C Valve has an in-series 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 containment isolation valves during operation. H Valve is required to provide for HPCS operation. L For the associated penetration, GDC 56 is satisfied by a single isolation valve, connected to the suppression pool with the line submerged and a high integrity closed loop system outside containment. N Valve is required to be closed during power operation (open for brief periods for the purpose of performing a surveillance is acceptable) and the piping outside 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. 6.2-108

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-16 Primary Containment Isolation Valves (Continued) NOTES

63. Leakage rate not included in sum of Type B and C test.

64. These are potential secondary containment bypass leakage paths whenever the railroad bay doors are open. The valves are tested for leakage to ensure requirements for limiting secondary containment bypass leakage are satisfied.

65. Valves RHR-V-134A and RHR-V-134B have been deactivated. Blind flanges CAC-BF-3A and CAC-BF-3B provide containment 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 primary containment. Therefore, 10 CFR 50 Appendix J Type C and hydraulic local leak rate testing is not required.

LDCN-08-028 6.2-109

COLUMBIA GENERATING STATION Amendment 66 FINAL SAFETY ANALYSIS REPORT December 2021 Table 6.2-17 DELETED LDCN-20-010 6.2-110

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 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.

LDCN-14-040 6.2-111

COLUMBIA GENERATING STATION Amendment 63 FINAL SAFETY ANALYSIS REPORT December 2015 Table 6.2-19a Limiting Conditions for Maximum Negative Pressure Differentials Applied to Columbia Generating Station Specifications Maximum Negative Pressure Differential (psid) DW-WW RB-WW DW Hypothetical Event VBs VBs Sprays WW-DW RB-WW DW-RB Remarks (1) Inadvertent spray 7 3 NA - - - Not possible due to activation containment high pressure interlock (2) Small pipe break liquid 7 2 1a 0.57 1.38 1.88 steam 7 2 1a 0.55 0.61 1.11 (3) DBA 7 2 1a 0.55 0.71 1.21 1 RB-WW VB failure 7 3 2 0.67 0.81 1.31 Use of two sprays No VB failure VBs adequate (4) Vented drywell 7 3 NA - - - Included in small with a small pipe break event (2) steam leak (5) Normal heating 7 3 NA - - - Controlled with the and cooling primary containment cycles cooling system a Drywell and wetwell sprays used in event mitigation from one RHR loop only. LDCN-14-040 6.2-112

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-20 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 6-in. RCIC Line* Steam Time Mass Rate Energy Rate (sec) (lb/sec) (Btu/sec x 103) 0.0 398.2 474.694 3.0 398.2 474.694

• Original rated power - Reference 6.2-29.

6.2-113

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-21 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 6-in. RCIC Line* Water Time Mass Rate Energy Rate (sec) (lb/sec) (Btu/sec x 103) 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.

6.2-114

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-21 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 6-in. RCIC Line* Water (Continued) Time Mass Rate Energy Rate (sec) (lb/sec) (Btu/sec x 103) 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.

6.2-115

COLUMBIA GENERATING STATION Amendment 61 FINAL SAFETY ANALYSIS REPORT December 2011 Table 6.2-22 Blowdown Mass/Energy Release Rates for a Double Ended Guillotine Break in 24-in. Recirculation Line* Steam Time Mass Rate Energy Rate (sec) (lb/sec x 103) (Btu/sec x 106) 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}}