ML12011A159

Amendment 61 to Final Safety Analysis Report, Chapter 5, Reactor Coolant System and Connected Systems

ML12011A159
Person / Time
Site:	Columbia
Issue date:	12/14/2011
From:	Energy Northwest
To:	Office of Nuclear Reactor Regulation
References
GO2-11-201
Download: ML12011A159 (217)

Text

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS Section Page 5-i 5.1

SUMMARY

DESCRIPTION............................................................5.1-1

5.1.1 SCHEMATIC

FLOW DIAGRAM...................................................5.

1-3 5.1.2 PIPING AND INSTRUMENTATION DIAGRAM...............................

5.1-3 5.1.3 ELEVATION DRAWING.............................................................5.1-3

5.2 INTEGRITY

OF REACTOR COOLANT PRESSURE BOUNDARY...........5.2-1

5.2.1 COMPLIANCE

WITH CO DES AND CODE CASES...........................5.2-1 5.2.1.1 Compliance with 10 CFR Part 50, Section 50.55a..............................5.2-1 5.2.1.2 Applicable Code Cases...............................................................5.2-1

5.2.2 OVERPRESSURIZATION

PROTECTION........................................5.2-2 5.2.2.1 Design Bases...........................................................................5.2-2 5.2.2.1.1 Safety Design Basis.................................................................5.2-2 5.2.2.1.2 Power Genera tion Design Bases.................................................5.2-2 5.2.2.1.3 Di scussion............................................................................5.2-3 5.2.2.1.4 Safety Valve Capacity..............................................................5.2-3 5.2.2.2 Design Evaluation.....................................................................5.2-4 5.2.2.2.1 Method of Analysis.................................................................5.2-4 5.2.2.2.2 System Design.......................................................................5.2-4 5.2.2.2.3 Evaluati on of Results...............................................................5.2-5 5.2.2.2.3.1 Safety Valve Capacity...........................................................5.2-5 5.2.2.2.3.2 Pressure Dr op in Inlet and Discharge.........................................5.2-6 5.2.2.2.3.3 Reload Speci fic Confirmatory Analysis......................................5.2-6 5.2.2.3 Piping and Instrument Diagrams....................................................5.2-6 5.2.2.4 Equipment and Component Description...........................................5.2-6 5.2.2.4.1 Desc ription...........................................................................5.2-6 5.2.2.4.2 Design Parameters..................................................................5.2-9 5.2.2.4.2.1 Safety/Relief Valve..............................................................5.2-9 5.2.2.5 Mounting of Pressure Relief Devices..............................................5.2-10 5.2.2.6 Applicable Codes and Classification...............................................5.2-10 5.2.2.7 Material Specification................................................................5.2-10 5.2.2.8 Process Instrumentation..............................................................5.2-10 5.2.2.9 System Reliability.....................................................................5.

2-10 5.2.2.10 Inspection and Testing..............................................................5.2-11 5.2.3 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS............5.2-16 5.2.3.1 Material Specifications...............................................................5.2-16 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-02-046 5-ii 5.2.3.2 Compatibility with Reactor Coolant................................................5.2-16 5.2.3.2.1 Pressurized Water Reactor Chemistry of Reactor Coolant..................5.2-16 5.2.3.2.2 Boiling Water Reactor Ch emistry of Reacto r Coolant.......................5.2-16 5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant.............5.2-19 5.2.3.2.4 Compatibility of Constructi on Materials with External Insulation and Reactor Coolant................................................................

5.2-20 5.2.3.3 Fabrication and Processing of Ferritic Materials and Austenitic Stainless Steels.........................................................................5.2-20

5.2.4 INSERVICE

INSPECTION AND TESTING OF THE REACTOR COOLANT PRESSURE BOUNDARY.............................................5.2-21 5.2.4.1 System Boundary Subject to Inspection...........................................5.2-21 5.2.4.2 Arrangement of Systems and Components to Provide Accessibility.........5.2-22 5.2.4.2.1 Reactor Pr essure Vessel...........................................................5.

2-23 5.2.4.2.2 Piping, Pu mps, and Valves.......................................................5.2-24 5.2.4.3 Examination Techniques and Procedures.........................................5.2-24 5.2.4.3.1 Equipment for Inservice Inspection..............................................5.2-24 5.2.4.3.2 Coordination of Inspection Equipment With Access Provisions............5.2-25 5.2.4.3.3 Manual Examination...............................................................5.2-25 5.2.4.4 Inspection Intervals...................................................................5.

2-25 5.2.4.5 Examination Categories and Requirements.......................................5.2-25 5.2.4.6 Evaluation of Examination Results.................................................5.2-25 5.2.4.7 System Leakage and Hydrostatic Pressure Tests................................5.2-26 5.2.4.8 Inservice Inspection Commitment..................................................5.2-26 5.2.4.9 Augmented Inservice Inspecti on to Protect Against Postulated Piping Failures..................................................................................5.2-26 5.2.4.10 Augmented Inservice Inspection of Reactor Pressure Vessel Feedwater Nozzles.................................................................................5.2-27 5.2.4.10.1 Pr eservice Examination..........................................................

5.2-27 5.2.4.10.2 Inservi ce Examination............................................................5.2-27 5.2.4.11 Augmented Inservice Inspec tion for Intergrannular Stress Corrosion Cracking................................................................................5.2-27 5.2.4.12 ASME Section XI Repairs/Replacements........................................5.2-27

5.2.5 DETECTION

OF LEAKAGE THROUGH REACTOR COOLANT PRESSURE BOUNDARY.............................................................

5.2-28 5.2.5.1 Leakage Detection Methods.........................................................5.2-28 5.2.5.1.1 Detection of Abnormal Leakage Within the Primary Containment........5.2-28 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

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

2-34 5.2.5.7 Testing and Calibration...............................................................5.2-34 5.

2.6 REFERENCES

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

5.2-34

5.3 REACTOR

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

5.3-8 5.3.1.7 Reactor Vessel Fasteners.............................................................5.3-8 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-04-033 5-iv 5.3.2 PRESSURE-TEMP ERATURE LIMITS.............................................5.3-9 5.3.2.1 Limit Curves...........................................................................5.3-9 5.3.2.2 Operating Procedures.................................................................5.3-9

5.3.3 REACTOR

VESSEL INTEGRITY...................................................5.3-9 5.3.3.1 Design...................................................................................5.3-10 5.3.3.1.1 Desc ription...........................................................................5.3-10 5.3.3.1.1.1 Reactor Vessel....................................................................5.

3-10 5.3.3.1.1.2 Shroud Support...................................................................5.

3-10 5.3.3.1.1.3 Protec tion of Closure Studs.....................................................5.3-10 5.3.3.1.2 Safety Design Bases................................................................5.3-11 5.3.3.1.3 Power Genera tion Design Basis..................................................5.3-11 5.3.3.1.4 Reactor Ve ssel Design Data......................................................

5.3-11 5.3.3.1.4.1 Vessel Support....................................................................5.

3-12 5.3.3.1.4.2 Control Rod Drive Housings...................................................5.3-12 5.3.3.1.4.2.1 Contro l Rod Drive Return Line.............................................5.3-12 5.3.3.1.4.3 In-Core Ne utron Flux Monitor Housings....................................5.3-12 5.3.3.1.4.4 Reactor Vessel Insulation.......................................................5.3-12 5.3.3.1.4.5 Reactor Vessel Nozzles.........................................................5.3-12 5.3.3.1.4.6 Materials and Inspection........................................................5.3-14 5.3.3.1.4.7 Reactor Vessel Schematic (BWR).............................................5.3-14 5.3.3.2 Material s of Construction............................................................5.3-14 5.3.3.3 Fabr ication Methods..................................................................5.3-15 5.3.3.4 Inspection Requirements.............................................................5.3-15 5.3.3.5 Shipment and Installation............................................................5.3-15 5.3.3.6 Operating Conditions.................................................................5.3-16 5.3.3.7 Inservice Surveillance................................................................5.3-16 5.

3.4 REFERENCES

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

5.3-17 5.4 COMPONENT AND SUBSYSTEM DESIGN.......................................5.4-1

5.4.1 REACTOR

RECIRC ULATION PUMPS...........................................5.4-1 5.4.1.1 Safe ty Design Bases...................................................................5.4-1 5.4.1.2 Power Ge neration Design Bases....................................................5.4-1 5.4.1.3 Description.............................................................................5.4-1 5.4.1.3.1 Recirculation System Cavitation Consideration...............................5.4-5 5.4.1.4 Safety Evaluation......................................................................5.4-5 5.4.1.5 Inspection and Testing................................................................5.4-6 C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-00-056,01-009, 01-025 5-v 5.4.2 STEAM GENERA TORS (PWR).....................................................5.4-6

5.4.3 REACTOR

COOLANT PIPING......................................................5.

4-7 5.4.4 MAIN STEAM LINE FLOW RESTRICTORS....................................5.4-7 5.4.4.1 Safe ty Design Bases...................................................................5.4-7 5.4.4.2 Description.............................................................................5.4-7 5.4.4.3 Safety Evaluation......................................................................5.4-8 5.4.4.4 Inspection and Testing................................................................5.4-8 5.4.5 MAIN STEAM LINE ISOLATION SYSTEM.....................................5.4-9 5.4.5.1 Safe ty Design Bases...................................................................5.4-9 5.4.5.2 Description.............................................................................5.4-10 5.4.5.3 Safety Evaluation......................................................................5.

4-12 5.4.5.4 Inspection and Testing................................................................5.4-13 5.4.6 REACTOR CORE ISOL ATION COOLING SYSTEM..........................5.4-14 5.4.6.1 Design Bases...........................................................................5.4-14 5.4.6.2 System Design.........................................................................5.4-16 5.4.6.2.1 General...............................................................................

5.4-16 5.4.6.2.1.1 Description........................................................................5.

4-16 5.4.6.2.1.2 Diagrams...........................................................................5.4-17 5.4.6.2.1.3 Interlocks..........................................................................5.4-18 5.4.6.2.2 Equipment and Co mponent Description........................................

5.4-19 5.4.6.2.2.1 Design Conditions................................................................5.4-19 5.4.6.2.2.2 Design Parameters...............................................................5.4-20 5.4.6.2.2.3 Overpressure Protection.........................................................5.4-25 5.4.6.2.3 Applicable Codes and Classifications...........................................

5.4-27 5.4.6.2.4 System Reliab ility Considerations...............................................

5.4-27 5.4.6.2.5 System Operation...................................................................5.

4-28 5.4.6.2.5.1 Au tomatic Operation.............................................................5.4-28 5.4.6.2.5.2 Test Loop Operation.............................................................5.4-29 5.4.6.2.5.3 Steam Conden sing (Hot Standby) Operation................................5.4-29 5.4.6.2.5.4 Manual Actions...................................................................5.

4-30 5.4.6.2.5.5 Reactor Core Isolation Cooling Discharge Line Fill System.............5.4-30 5.4.6.3 Performance Evaluation..............................................................5.4-30 5.4.6.4 Preope rational Testing................................................................5.4-30 5.4.6.5 Safety Interfaces.......................................................................5.

4-30 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDCN-04-027 5-vi 5.4.7 RESIDUAL HEAT REMOVAL SYSTEM.........................................5.4-30 5.4.7.1 Design Bases...........................................................................5.4-30 5.4.7.1.1 Functiona l Design Basis...........................................................5.4-31 5.4.7.1.2 Design Basis fo r Isolation of Residual Heat Removal System from Reactor Coolant System...........................................................

5.4-33 5.4.7.1.3 Design Basis for Pr essure Relief Capacity.....................................5.4-33 5.4.7.1.4 Design Basis With Respect to General Design Criterion 5..................5.4-36 5.4.7.1.5 Design Basis for Reliability and Operability...................................

5.4-36 5.4.7.1.6 Design Basis for Protect ion from Physical Damage..........................5.4-37 5.4.7.2 Systems Design........................................................................5.

4-37 5.4.7.2.1 System Diagrams...................................................................5.

4-37 5.4.7.2.2 Equipment and Co mponent Description........................................

5.4-38 5.4.7.2.3 Controls a nd Instrumentation.....................................................

5.4-40 5.4.7.2.4 Applicable Codes and Classifications...........................................

5.4-40 5.4.7.2.5 Reliability Considerations.........................................................

5.4-41 5.4.7.2.6 Manual Action.......................................................................5.

4-41 5.4.7.3 Performance Evaluation..............................................................5.4-41 5.4.7.3.1 Shutdown Cooling With All Components Available..........................5.4-42 5.4.7.3.2 Shutdown Cooling With Most Limiti ng Failure...............................5.4-42 5.4.7.4 Preope rational Testing................................................................5.4-42

5.4.8 REACTOR

WATER CLEANUP SYSTEM........................................5.4-43 5.4.8.1 Design Bases...........................................................................5.4-43 5.4.8.1.1 Safety Design Bases................................................................5.4-43 5.4.8.1.2 Power Genera tion Design Bases.................................................5.4-43 5.4.8.2 System Description....................................................................5.

4-44 5.4.8.3 System Evaluation.....................................................................5.

4-45 5.4.8.4 Demi neralizer Resins.................................................................5.4-46 5.4.8.5 Reactor Water Cleanup Water Chemistry.........................................5.4-46 5.4.8.5.1 Analy tical Methods.................................................................5.

4-46 5.4.8.5.2 Relationship of Filter-Demineralizer Condition to Water Chemistry......5.4-46 5.4.9 MAIN STEAM LINES AND FEEDWATER PIPING...........................

5.4-47 5.4.9.1 Safe ty Design Bases...................................................................5.

4-47 5.4.9.2 Power Ge neration Design Bases....................................................5.4-47 5.4.9.3 Description.............................................................................5.4-47 5.4.9.4 Safety Evaluation......................................................................5.

4-48 5.4.9.5 Inspection and Testing................................................................5.4-48 C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

TABLE OF CONTENTS (Continued)

Section Page LDC N-0 1-0 0 9, 0 1-025 5-vii 5.4.10 PRESSURIZER.........................................................................

5.4-48 5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM..............................

5.4-48 5.4.12 VALVES.................................................................................5.4-48 5.4.12.1 Safety Design Bases.................................................................5.4-48 5.4.12.2 Description............................................................................5.4-48 5.4.12.3 Safety Evaluation....................................................................5.

4-49 5.4.12.4 Inspection and Testing..............................................................5.4-49 5.4.13 SAFETY AND RELIEF VALVES.................................................5.4-50 5.4.13.1 Safety Design Bases.................................................................5.4-50 5.4.13.2 Description............................................................................5.4-50 5.4.13.3 Safety Evaluation....................................................................5.

4-50 5.4.13.4 Inspection and Testing..............................................................5.4-50 5.4.14 COMPONENT AND PIPING SUPPORTS.......................................5.4-50 5.4.14.1 Safety Design Bases.................................................................5.4-51 5.4.14.2 Description............................................................................5.4-51 5.4.14.3 Inspection and Testing..............................................................5.4-51 5.4.15 HIGH-PRESSURE CO RE SPRAY SYSTEM....................................5.4-52 5.4.16 LOW-PRESSURE CORE SPRAY SYSTEM.....................................5.4-52 5.4.17 STANDBY LIQUID CONTROL SYSTEM.......................................5.4-52 5.4.18 REFERENCES.........................................................................

5.4-52

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF TABLES

Number Title Page LDC N-0 2-0 0 0 5-viii 5.2-1 Exceptions to Conform a nce to 10 CFR 50.55a

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

5.2-3 Nuclear Sy s t em Sa f e ty/Relief Setpoints 5.2-39

5.2-4 Systems Which May Ini t iate During Safety Valve

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

5.2-7 Reactor Coolant Press u re Boundary M a terials 5.2-45

5.2-8 Water Sample Locations 5.2-48 5.2-9 IHSI Summary Prior to First Refueling GL 88-01 Category B Welds 5.2-49 5.2-10 IHSI Summary During First Refueling GL 88-01 Category B Welds 5.2-50 5.2-11 Main Steam Isolation Valv es Material Information 5.2-51 5.2-12 Summary of Isolation/Alarm of System Monitored and the Leak Detection Methods Used 5.2-52 5.3-1 10 CFR 50 Appendix G Matrix 5.3-19 5.3-2 Plate Material Cross Reference 5.3-23 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF TABLES (Continued)

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

5.3-25 5.3-5 Weld Material...................................................................5.3-26

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

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

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

5.4-1 Reactor Coolant Pressu re Boundary Pump and Valve Description.......................................................................5.

4-53 5.4-2 Reactor Recirculation System Design Characteristics....................5.4-58

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

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

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

5.4-6 Safety and Relief Valve for Piping Systems Connected to the Reactor Coolant Pressure Boundary.................................

5.4-63 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES

Number Title LDCN-04-005 5-x 5.1-1 Rated Operating Conditions of the Boiling Water Reactor 5.1-2 Coolant Volumes of the Boiling Water Reactor 5.2-1 Simulated Safety Relief Valve Spring Mode Characteristic Used for Capacity Sizing Analysis

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

5.2-3 Peak Vessel Pressure Versus Safety Valve Capacity

5.2-4 Time Response of Pressure Vessel For Pressurization Events

5.2-5 Nuclear Boiler System (P&ID)

5.2-6 Safety/Relief Valve Schematic Elevation

5.2-7 Safety/Relief Valve and Steam Line Schematic

5.2-8 Schematic of Safety Valve With Auxiliary Actuating Device

5.2-9 Safety Valve Lift Versus Time Characteristics

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

5.2-11 Typical BWR Characteris tic MSIV Closure Flux Scram

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

5.3-2 Vessel Beltline Plate and Weld Seam Identification

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

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES (Continued)

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

5.3-6 Feedwater Nozzle

5.3-7 Feedwater Sparger

5.4-1 Recirculation System Evaluation and Isometric

5.4-2 RRC Pump Dynamic Head - Flow Curve

5.4-3 RRC Pump Speed - Torque Curve

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

5.4-5 Operating Principle of Jet Pump

5.4-6 Core Flooding Capability of Recirculation System

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

5.4-8 Main Steam Line Flow Restrictor Location

5.4-9 Main Steam Line Isolation Valve

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

5.4-12 Reactor Core Isolation Cooling System Process Diagram

5.4-13 Reactor Core Isolation Cooling Pump Performance Curve

5.4-14 Typical Strainer

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 Chapter 5

REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

LIST OF FIGURES (Continued)

Number Title LDCN-06-000 5-xii 5.4-15 Residual Heat Removal Syst em - P&ID (Sheets 1 through 4) 5.4-16 Residual Heat Removal System Process Diagram

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

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

5.4-19 Residual Heat Rem oval (LPCI) Pump Characteristics (S/N 0473111) P-2B

5.4-20 Residual Heat Rem oval (LPCI) Pump Characteristics (S/N 0473112) P-2C

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

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

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

5.4-24 Filter/Deminera lization System P&ID

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

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.1-1 Chapter 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS

5.1

SUMMARY

DESCRIPTION

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

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

a. Part of the reactor coolant system, or

b. Connected to the reactor coolant system , up to and including any and all of the following:

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

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

3. The reactor coolant system safety/relief valves.

Section 5.4 discusses the various s ubsystems to the RCPB.

The nuclear system pressure relief system protects the reactor coolant pressure boundary from damage due to overpressure. To protect against overpressure, pr essure-operated relief valves are provided that can discharge steam from the nuclear system to the suppression pool. The pressure relief system also acts to automatically depre ssurize the nuclear system in the event of a loss-of-coolant accident (LOCA) in which the high-pressure core spray (HPCS) system fails to maintain reactor vessel water level. Depressurization of the nuclear system allows the low-pressure core cooling systems to supply enough cooli ng water to adequately cool the fuel.

Section 5.2.5 establishes the limits on nuclear system leakage inside th e drywell so that appropriate action can be taken before the integrity of the nuclear system process barrier is impaired.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.1-2 The reactor vessel and appurtenan ces are described in Section 5.3. The major safety consideration for the reactor vessel is concerned with the ability of the vessel to function as a radioactive material barrier.

Various combinations of loadi ng are considered in the vessel design. The vessel meets the requirements of various applicable codes and criteria. The possibility of brittle fracture is considered, and suitable design, material selection, material surveillance activities, and operational limits are establishe d that avoid conditions where brittle fracture is possible.

The reactor recirculation system provides coolan t flow through the core. Adjustment of the core coolant flow rate changes reactor power output, thus providing a means of following plant load demand without adjusting control rods. The recirculation system is designed to provide a slow coast down of flow so that fuel thermal limits cannot be exceeded as a result of recirculation system malfunctions.

The arrangement of the recircul ation system routing is such that a piping failure cannot compromise the integrity of th e floodable inner volume of the reactor vessel.

Main steam line flow restrictors of the venturi-type are installed in each main steam line inside the primary containment. The restrictors ar e designed to limit the loss-of-coolant resulting from a main steam line break outsi de the primary containment.

The coolant loss is limited so that reactor vessel water level remains above the top of the core during the time required for the main steam isolation valves (MSIVs) to close. This action protects the fuel barrier.

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

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

The residual heat removal (RHR) system includes a number of pumps and heat exchangers that can be used to cool the nuclear system under a variety of situations.

During normal shutdown and reactor servicing, the RHR system removes residual and decay heat. The RHR system allows decay heat to be removed whenever the main heat sink (main conde nser) is not available (e.g., hot standby). One mode of RHR operation allows the rem oval of heat from the primary containment following a LOCA. Another op erational mode of the RHR system is C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 5.1-3 low-pressure coolant injection (LPCI). The LPCI operation is an engineered safety feature for use during a postulated LOCA. This operation is descri bed in Section 6.3. The low-pressure core spray (LPCS) system also provide s protection to the nuclear system.

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

5.1.1 SCHEMATIC

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

5.1.2 PIPING

AND INST RUMENTATION DIAGRAM

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

a. The nuclear boiler, main steam, and feedwater systems shown in Figure 10.3-2 , b. Recirculation system shown in Figure 5.4-7 , c. RCIC system shown in Figure 5.4-11 , d. RHR system shown in Figures 5.4-16 and 5.4-17 , e. Reactor water cleanup system shown in Figure 5.4-22 , f. HPCS system shown in Figure 6.3-4 , g. LPCS system shown in Figure 6.3-4 , and h. Standby liquid control system shown in Figure 9.3-14. 5.1.3 ELEVATION DRAWING

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

108.5 x 10 6 1. Core Inlet

2. Core Outlet

3. Separator Outlet (Steam Dome)

4. Steam Line (2nd Isolation Valve)

5. Feedwater Inlet (Includes RWCU Return Flow)

6. Recirculating Pump Suction

7. Recirculating Pump Discharge 1069 1047 1035 1000 1063 1037 1327 534 550 549 545 421 534 535 528.7 639.91191.0 1191.0 398.5 528.4 529.8 PRESSURE (psia)FLOW (lb/hr)TEMP.( F)ENTHALPY (Btu/lb)108.5 x 10 6*FCV FCV Jet Pump Core Recirculation Pump Driving Flow Main Feed FlowMain Steam Flow Turbine Steam Dryers Steam Separators 7 1 6 5 4 3 2 Note 1 Note 1* Channel Bypass - Nominally 10% Note 1: The FCVs are kept in mechanically blocked full open position.

Note 1 Rated Operating Conditions of theBoiling Water Reactor 900547.44 5.1-1 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.15.0 x 10 6 15.0 x 10 6 15.2 x 10 6 32 x 10 6 32 x 10 6 Columbia Generating StationFinal Safety Analysis Report A. Lower Plenum B. Core C. Upper Plenum and Separators D. Dome (Above Normal Water Level)

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

3) Note1: The FCVs are kept in mechanically blocked full open position.Coolant Volumes of the Boiling Water Reactor 960690.04 5.1-2 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report FCV FCV Jet Pump Core Recirculation Pump Driving Flow Main Feed FlowMain Steam Flow Turbine Steam Dryers Steam Separators Note 1 Note 1 Note 1 B A D F E C C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 5.2-1 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY

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

5.2.1 COMPLIANCE

WITH CODES AND CODE CASES

5.2.1.1 Compliance with 10 CFR Part 50, Section 50.55a Table 3.2-1 shows compliance with the rules of 10 CFR Part 50.55a "Code s and Standards."

The American Society of Mechanical Engineers (ASME) Code edition, applicable addenda, and component dates are in accordance with 10 CFR 50.55a except for those RCPB components listed in Table 5.2-1. The design, fabrication, and testing of the RCPB components listed in Table 5.2-1 were in accordance with the recognized codes and standards in effect at the time th e components were ordered as shown in the table.

The code edition and applicable addenda that would be required by strict interpreta tion of the rules set forth in 10 CFR 50.55a are identified in Table 5.2-1.

Application for Columbia Generating Stati on (CGS) was filed with the Commission in August 1971. At that time a construction perm it was expected before the end of the 1972, but requests for additional seismic data in August 1972 caused the issuance of the construction permit to go beyond the end of the year to Ma rch 19, 1973. As is common practice in the utility industry, Energy Northwest proceeded with the engineering, design, and material and components procurement in anticipation of th e award of a construction permit to meet construction schedules.

Had the construction permit been is sued as initially expected, the requirements of 10 CFR 50.55a would have been met to the letter of the law.

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

5.2.1.2 Applicable Code Cases

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

5.2.2 OVERPRESSURIZATION

PROTECTION

5.2.2.1 Design Bases

Overpressurization protection is provided in conformance with 10 CFR 50, Appendix A, General Design Criterion 15.

5.2.2.1.1 Safety Design Basis

The nuclear pressure-relie f system is designed to

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

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

c. Permit verification of its operability, and

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

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

a. Discharge to the containment suppression pool, and

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 8-1 1 3 5.2-3 b. Correctly reclose following operation so that maximum operational continuity can be obtained.

5.2.2.1.3 Discussion

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

The automatic depressurization capability of the nucl ear system pressure relief system is evaluated in Sections 6.3 and 7.3.

The following detailed criteria are used in selection of SRVs:

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

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

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

The SRV discharge piping is constructed in accordance with the ASME Code,Section III, 1971 Edition through the Winter 1973 Addenda.

5.2.2.1.4 Safety Valve Capacity

The safety valve capacity of this plant is ad equate to limit the primary system pressure, including transients, to the re quirements of the ASME B&PV Code,Section III, 1971 Edition through the Summer 1971 Addenda.

Table 5.2-4 lists the systems which c ould initiate during the safety valve capacity overpressure event.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-029 5.2-4 5.2.2.2 Design Evaluation

5.2.2.2.1 Method of Analysis

To design the pressure protection for the nuclear boiler system, extensive analytical models representing all essential dynamic characteristic s of the system are simulated on a large computing facility. These models include the hydrodynamics of the flow loop, the reactor

kinetics (either a point kinetics or a one-dimensional kinetics simulation of the reactor core dynamics), 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 th at have evolved through extensive experience a nd favorable comparison of analysis with actual boiling water reactor (BWR) test data.

A detailed description of th e models is documented in li censing topical report Reference 5.2-1. Safety/relief valves are simulate d in the nonlinear representation, and the models thereby allow full investigation of the various valve response times, valve cap acities, and actuation setpoints that are available in applicable hardware systems.

The typical capacity characteristic as modeled is represented in Figure 5.2-1 for the spring mode of operation. The associated turbine bypass, turbine control valve (TCV), and main steam isolation valve (MSIV) characteristics are also simulated in the models.

The associated bypass, TCV, main steam isolation character istics, and anticip ated transients without scram (ATWS) pump trip are al so represented fully in the models.

5.2.2.2.2 System Design

The overpressure protection system must ac commodate the most se vere pressurization transient. There are two major transients, the closure of a ll MSIVs and a turbine generator trip with a coincident failure of the turbine steam bypass system valves, that represent the most severe abnormal operational transients resulting in a nuclear system pressure rise. The evaluation of transient behavior with final pl ant configuration has s hown that the isolation valve closure is slightly more severe when credit is taken onl y for indirect derived scrams; therefore, it is used as the overpressure protection basis event and shown in Figure 5.2-2. Table 5.2-5 lists the sequence of events of the vari ous systems assumed to operate during the main steam line isolation closure with flux scram event.

Compliance to ASME Code overpressure prot ection requirements for introduction of GE14 fuel has been conservatively demonstrated fo r the limiting overpressu re event. The GE thermal-hydraulic and nuclear coupled transient code ODYN (Reference 5.2-1) was used to obtain system response and peak vessel pr essure. The setpoi nts are listed in Table 5.2-3. The evaluation, based on reactor ope ration at 102% of uprated po wer, end-of-cycle nuclear

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-029 5.2-5 dynamic parameters, an initial dome pressure of 1050 psia (15 ps ia above the nominal uprated dome 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 1341 psig.

The scram reactivity curve is shown in Figure 5.2-2.

5.2.2.2.3 Evaluation of Results

5.2.2.2.3.1 Safety Valve Capa city. The required SRV capacity is determined by analyzing the pressure rise from an MSIV closure with fl ux scram transient. The plant is assumed to be operating at the turbine-genera tor design conditions at a maxi mum vessel dome pressure of 1050 psia. The analysis hypothetic ally assumes the failure of th e direct MSIV position scram.

The reactor is shut down by the backup, high neutron flux scram.

For the analysis, the spring-action safety valve setpoi nts used are in the range of 1225 to 1256 psia. The ODYN analysis indicates that the design valve capacity is capable of mainta ining adequate margin below the peak ASME Code allowable pre ssure in the nuclear system (1375 psig).

Figure 5.2-2 shows the result of the ODYN anal ysis. The sequen ce of events in Table 5.2-5 , assumed in these analyses, were investigated to meet code requirements and to evaluate the pressure relief system exclusively.

Under Section III of the ASME B&PV Code, credit can be allowed for a scram from the reactor protection system. In addition, credit is also taken for the protection circuits which are

indirectly derived when determ ining the required SRV capacity.

The backup reactor high neutron flux scram is conservatively applied as a design basis in determining the required capacity of the pressure relieving dual purpose SRVs. Application of the direct position scrams in the design basis c ould be used since they qualify as acceptable pressure protection devices when determining the required SRV capacity of nuclear vessels under the provisions of the ASME Code.

The SRVs are operated in a relief mode (pneumatically) at setpoints lower than those specified under the sa fety function. This ensures sufficient margin between anticipated relief mode closing pr essures and valve spring forces for proper seating of the valves.

The 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) pr essure for position scram with 18-valve capacity. Pressures shown for flux scram will result only with multip le failure in the redundant direct scram system.

The time response of the vessel pre ssure to the MSIV tran sient with flux scra m is illustrated in Figure 5.2-4. This shows that the pre ssure at the vessel bottom ex ceeds 1250 psig for less than 7 sec and does not reach the limit of 1375 psig.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-029 5.2-6 5.2.2.2.3.2 Pressure Drop in Inlet and Discharge. Pressure drop in the piping from the reactor vessel to the valves is taken into account in calculati ng the maximum vessel pressures.

Pressure drop in the discharge piping to the suppression pool is limited by proper discharge line sizing to prevent back-p ressure on each SRV from exceed ing 40% of the valve inlet pressure, thus ensuring choked flow in the valve orifice and no reduction of valve capacity due to the discharge piping. Each SRV has its own separate discharge line.

5.2.2.2.3.3 Reload Specific Confirmatory Analysis. The calculated vessel pressure for MSIV inadvertent closure may be dependent upon the fuel design and core loading pattern. Compliance with the ASME upset limit is demons trated by cycle-dependent analysis just prior to the operation of that cycle. The results are reported in Supplem ental Reload Licensing Report (Reference 5.2-11). 5.2.2.3 Piping and Instrumentation Diagrams

See Figure 5.2-5 which shows the schematic location and number of pressure-relieving devices. The schematic arrangement of the SRVs is shown in Figures 5.2-6 and 5.2-7.

5.2.2.4 Equipment and Component Description

5.2.2.4.1 Description

The nuclear pressure relief system consists of SRVs located on the main steam lines between the reactor vessel and the first isol ation valve within the drywell.

Chapter 15 discusses the events which are expected to activate the primary system SRVs. The chapter also summarizes the number of valves e xpected to operate during the initial blowdown of the valves and the expected duration of this first blowdown. For several of the events it is expected that the lowest set SRV will reopen and reclose as gene rated heat drops into the decay heat characteristics. The pressure increase and relief cycl e will continue with lower frequency and shorter relief discharges as the decay heat drops off and until such time as the residual heat removal (RHR) system can dissipat e this heat. The duration of each relief discharge should, in most cases, be less th an 30 sec. Remote manual actuation of the valves from the control room is recommended to minimize the total number of these discharges, with the intent of achieving extended valve seat li fe and reducing cha llenges to the SRV.

A schematic of the main SRV is shown in Figure 5.2-8. It is opened by e ither of two modes of operation:

a. The spring mode of operation which c onsists of direct action of the steam pressure against a spring-loaded disk that will pop open when the valve inlet

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 5.2-7 pressure force exceeds the spring force.

Figure 5.2-9 depicts typical valve lift versus opening time characteristics; and

b. The power-actuated mode of operation which consists of using an auxiliary actuating device consisting of a pneumatic piston/cylinder and mechanical

linkage assembly which opens the valve by overcoming the spring force, even with valve inlet pressure equal to zero psig.

The pneumatic operator is so arra nged that if it malfunctions it will not prevent the valve disk from lifting if steam inlet pressure reaches the spring lift set pressure.

For overpressure SRV operation (self-actuated or spring lift mode), the spring load establishes the safety valve opening setpoint pressure and is set to ope n at setpoints designated in Table 5.2-3. In accordance with the ASME Code, full lift in this mode of operation is attained at a pressure not greater than 3% above the setpoint.

To prevent backpressure from af fecting the spring lift setpoint, each valve is provided with a bellows and balancing piston to c ounteract the effects of any stat ic backpressure which may be present in the discharge line be fore the valve is opened to discharge steam. The bellows isolates steam in the valve disc harge chamber from the valve's internals. If the bellows fails, the balancing piston serves as a functional backup by presenting an effective pi ston area to the back pressure equal to the valve seat area, thus balancing it so there is essentially no net back pressure effect on the setpoint (Figure 5.2-8

).

The safety function of the SRV is a backup to the relief function described below. The spring-loaded valves are desi gned and constructed in accordan ce with ASME III, 1971 Edition, Paragraph NB-7640, as safety valves with auxiliary actuating devices.

Each SRV is provided with its own pneumatic accumulator and inlet check valve to provide high assurance the valve will actuate in the power-actuated (relief) mode when its pneumatic solenoid valve is energized. The pneumatic accumulator has su fficient capacity to provide one SRV actuation at approximate ly 1000 psig valve inlet pressure. Although no credit is taken under ASME Code Section III for overpressure protec tion by the SRVs in their power-actuated mode, power actuation of the SRV will limit peak reactor pressure in the majority of overpressure transients.

Safety/relief valve actuation in the relief mode is initiated by pr essure switches (one per valve) which sense reactor steam space pressure at lower values than the spring mode inlet steam opening pressure. The pressure switches initia te the opening of the SRVs by energizing the pneumatic solenoids (one per valve) at the relief setpoints designated in Table 5.2-3.

When the solenoid is actuated, the delay time, maximum elapsed time between receiving the overpressure signal at the valve actuator and the actual start of valve motion, will not exceed

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 8-1 1 3 5.2-8 0.1 sec. The maximum full stroke opening time will not exceed 0.15 sec with 1000 psig steam at the valve inlet.

The SRVs can be operated in th e power-actuated mode by remote-manual controls from the main control room.

The SRVs are designed to operate to the exte nt required for overpressu re protection in the following accident environments:

a. 340°F for a 3-hr period, at drywell design pressure, b. 320°F for an additional 3-hr period, at drywell design pressure, c. 250°F for an additional 18-hr peri od, at 25 psig drywell pressure, and

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

The automatic depressurization sy stem (ADS) utilizes selected SR Vs for depressurization of the reactor (see Section 6.3). Each of the SRVs utilized for automatic depressuri zation is equipped with an air accumulator and check valve arrangement. These accumulators ensure that the

valves can be held open followi ng failure of the air supply to the accumulators. The designed pneumatic supply to the ADS accumulator is such that, following a failure of the safety-related pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at 70% of design pressure. For a discussion of the noninterruptible air supply to the ADS valves, see Section

9.3.1. Three

ADS SRVs and their associ ated solenoid pilot valves (SPV) are qualified for the full post-LOCA time frame for long-term c ooling. All other SRVs and their SPVs are qualified for 24 hr post-LOCA to provide overpressure protection capability.

The valve position indication (VPI) and the tailpipe temperature indication systems are discussed in Section 7.5.2.

Each SRV discharges steam through a discharge line to a point below the minimum water level in the suppression pool. Safety/relief valve discharge line piping from the SRV to the suppression pool consists of two parts. The first part is attached at one end to the SRV and at

its other end penetrates and is welded to a 28-in. downcomer (considered a pipe anchor). The main steam piping, including this portion of the SRV discharge piping, is analyzed as a complete system. This portion of the SRV discharge line is cl assified as Quality Group C and Seismic Category I down to the jet deflector plate just above the diaphragm floor (through which it is rigidly guided) and Quality Group B and Seismic Cate gory I from the jet deflector plate to the downcomer.

The second part of the SRV discharge piping extends from the downcomer (anchor) to the suppression pool. Because of the anchor on this part of the line, it is physically decoupled from the main steam header and is, therefore, analyzed as a separate piping system. In analyzing this part of the discharge piping in accordance with the requirements of Quality Group B, the following load combination was considered as a minimum:

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 5.2-9 a. Pressure and temperature, b. Dead weight, and

c. Fluid dynamic loads due to SRV operation.

As a part of the preoperational and startup testing of the main steam lines, movement of the SRV discharge lines were inspected w ith negligible vibration observed.

The SRV discharge piping is designed to limit va lve outlet pressure to 40% of maximum valve inlet pressure with the valve open. Water in the line more than a few feet above suppression pool water level would cause excess ive pressure at the valve disc harge when the valve is again opened. For this reason, re dundant 10-in. vacuum relief va lves are provided on each SRV discharge line to prevent drawing an excessive amount of water up into the line as a result of steam condensation following termina tion of relief operation. Each vacuum relief valve pair is situated with the valves in parallel, the discharge being routed to a common tee in the SRV discharge line.

The nuclear pressure relief syst em automatically depressurizes the nuclear system sufficiently to permit the LPCI and LPCS systems to operate as a backup for the HPCS system. Further descriptions of the operation of the automatic depressurization feature are found in Sections 6.3 and 7.3.1.1.1.

5.2.2.4.2 Desi gn Parameters

Table 5.2-6 lists design temperature, pressure, and maximum test pressure for the RCPB components. The specified opera ting transients for components within the RCPB are given in

Section 3.9. Refer to Section 3.7 for discussion of the input criteria for design of Seismic Category I structures, systems, and components.

A summary of the number of cycles for transients used in design and fatigue analysis is listed in Table 3.9-1 and categorized under the appropriat e design condition (i.e., normal, upset, emergency, and faulted).

The design requirements establishe d to protect the principal com ponents of the reactor coolant system against environmental ef fects are discussed in Section 3.11.

5.2.2.4.2.1 Safety/Relief Valve. The discharge area of the valve is 16.117 in.

2 and the coefficient of discharge KD is equal to 0.966, as certified by the National Board of Boiler and Pressure Vessel Inspectors.

The design pressure and temperature of the va lve inlet and outlet are 1250 psig at 575°F and 625 psig at 500°F, respectively.

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 5.2-10 The valves have been designe d to achieve the maximum pr actical number of actuations consistent with state-of-the-art technology. Cyclic testing has de monstrated that the valves are capable of at least 60 actuation cy cles between required maintenance.

See Figure 5.2-8 for a schematic cross section of the valve.

5.2.2.5 Mounting of Pressure Relief Devices

The pressure relief devices are located on the main steam piping headers. The mounting consists of a special contour nozzle and an oversized flange connection. This provides a high

integrity connection that accounts for the thru st, bending, and torsiona l loadings which the main steam pipe and relief valve discharge pipe are subjected to.

In no case will allowable valve flange loads be exceeded nor will the stress at a ny point in the piping exceed code allowables for any specified combination of loads. The design criteria and

analysis methods for considering loads due to SRV discharge is contained in Section 3.9.3.3.

5.2.2.6 Applicable C odes and Classification

The RCPB overpressure protection system is designed to satisfy the requirements of Section III, Subsection NB, of the ASME B&

PV Code. The gene ral requirements for protection against overpressure as given NB-7120 of Section III of the code recognize that RCPB overpressure protection is one function of the reactor protective systems and allows the

integration of pressure relief devices with the protective syst ems of the nuclear reactor. Hence, credit is taken for the scram protective system as a complement ary pressure protection device.

5.2.2.7 Material Specification

Pressure retaining components of SRVs are constructed only from ASME Section III, Class 1 designated materials.

5.2.2.8 Process Instrumentation

Overpressure protection process instru mentation is listed in Table 1 of Figure 5.2-5 and shown in Figure 10.3-2.

5.2.2.9 System Reliability

Overpressure protection system reliability is princi pally a function of the SRVs in their spring-opening mode of ope ration. No credit is taken in th e ASME Code Section III required overpressure protection report for power actuation of the SRVs to provide protection against overpressure.

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 5.2-11 Section 5.2.2.10 discusses the inspection and testing c onducted to ensure hi gh SRV reliability. As demonstrated by the extensive qualification and production testing, the valves are very reliable.

In addition to SRV testing to ensure high SRV quality, an extensive in-depth quality assurance program was followed in the manufacture and production testing of the valves to provide assurance of high quality.

A significant amount of BWR operating experience was been accumu lated on this type of SRV, approximately 150 individual valv e years, only one "stuck-open relief valve" had occurred.

This was due to an air solenoid valve sticking open after it was deener gized, thus holding the SRV open in the power-actuated mode. Proper ma intenance procedures ar e incorporated into the instruction manual to preclude recurrence.

This type of SRV has demonstrated good inservi ce operability similar to that demonstrated by the qualification test program.

In summary, this type of SRV has demonstrated excellent reliability , both in qualification testing and in act ual BWR operation.

5.2.2.10 Inspection and Testing

To verify the design of the SRV used will reliably operate, several SRVs were subjected to qualification test programs. These qualification test programs de monstrated the design of the valve is capable of performi ng its overpressure protection function under normal, upset, emergency, and faulted c onditions and its designated mechanical motion(s) to fulfill its safety function to shut down the plant or mitigate the c onsequence of a postulated event. To ensure that valves to be installed ar e operable, each valve is manuf actured, inspected, and production tested in accordance with quality control procedures to veri fy compliance with both ASME Code and operability assura nce acceptance criteria.

The SRV design used at CGS su ccessfully complete d the following qua lification tests:

a. Life Cycle Test

Following the prequalification production tests, each modified SRV was then subjected to life cycle qua lification tests with satu rated steam conditions, in accordance with GE specification 22A6595. This included approximately 300 relief (power) and safety (pressur e) actuations to demonstrate and characterize each valve for acceptable BWR service. Tests parameters included:

1. Seat tightness/leakage characteristics, C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 5.2-12 2. Set pressure,

3. Opening and closing response time,

4. Blowdown,

5. Safety/relief valve lift-achieving rated flow capacity lift during each activation,

6. Safety/relief valve reclosure without chattering, disc oscillation, or sticking open, and

7. Capability to open without inlet steam when activated on demand.

Test conditions were varied according to facility capability to ensure valve operability across the design limits to which the SRV ma y be subjected while in service. These included temperature, pr essure ramp rates, pneumatic operating pressure, solenoid voltage, inlet pr essure, and the dynamically imposed backpressure.

Test results indicate essen tially zero leakage for both the relief (power) and safety (pressure) modes of SRV opera tion. All valves demonstrated seat-tightness capability to meet the 20 lb/hr specific ation limit under saturated steam conditions. Each valve demons trated safety actuation within the nameplate value plus 1% at a confidence level of 0.95. The response is also linear with ambient temperature in the negative direction; i.e., at temperatures

above 135°F the actual pop pressure is lo wer than the namepl ate value. The temperature correction value is 0.2 psi/

°F for this SRV. Set pressure is

independent of ramp rate variance. Res ponse of the SRV is directly related to the effective differential pr essure force acting to open the SRV; therefore, outlet static pressure at th e exit can be accurately accounted for.

Opening times were as follo ws during the test set up:

Safety actuation time - 0.020 t 0.30 sec Relief actuation time - 0.020 t 0.15 sec Actual installation times could result in a delay time >0.10 sec due to wire lengths and other non-SRV wire losses. Closing times were:

Safety actuation - none, contro lled by blowdown requirement.

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 5.2-13 Relief actuation - time to deenergize solenoid < 0.90 sec disc travel after solenoid < 1.50 sec was deenergized Blowdown within the require d range of 2% to 11% wa s demonstrated. Each SRV is adjusted by full flow testing for acceptable blowdown.

Qualification test results demonstrate the SRV will open to rated capacity lift in either the relief or safety modes of operation when actuated.

The SRV reclosure was demonstrated th roughout the qualifica tion tests without sticking, chatter, or disc oscillation during the closure stroke. When inlet pressure was increased to repressurize to the set pressure, the SRV reactuated to the full open position. The modified SRV w ill open to its full rated capacity lift position when operated in the relief mode with the inlet pressure at zero psig, thus demonstrating its em ergency operability capability.

Six SRVs were included in this life cy cle qualification test program. Test anomalies corrected during th is demonstration do not i nvalidate the adequacy of the test results obtained; the finalized modified SRV design is considered acceptable for BWR main steam applications.

b. Seismic and Moment Transfer Test One valve specimen was subjected to operating basis earthquake (OBE) and safe shutdown earthquake (SSE) accelerations and flange d end connection moment loading with valve inlet pr essurized with saturated st eam. Valve operability was demonstrated during and afte r application of loading. Maximum test loads were 8 x 10 5 in. pound moment at valve inlet and 6 x 10 5 in. pound moment at valve outlet. Seismic accelerations of 5.

0g horizontal and 4.2g vertical are the established maximum for a ny frequency between 5 to 200 Hz unless otherwise specified for a smaller frequency range.

c. Emergency Environmen tal Qualification Test

The solenoid valves and the pneumatic ac tuator assembly were subjected to a test sequence as follows:

1. Thermal aging equivalent to 343°F for 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />,

2. Radiation aging to greater than or equal to 30 x 10 6 rads, C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 5.2-14 3. Mechanical aging for 10 00 cycles (500 per solenoid),

4. Seismic testing as de scribed in item b. above,

5. Exposure to emergency environmental conditions of 340°F at 65 psig decreasing to 250°F at 25 psig for 4 days, and

6. Separate solenoid valve test 340°F, 3 hrs, 45 psig 320°F, 3 hrs, 45 psig 250°F, 18 hrs, 25 psig 200°F, 99 days, 20 psig.

Operability of the actuat or assembly was demons trated during and after exposure to the emergency environment.

d. Low-Pressure Water Discharge Test

Low-pressure water discharge tests as described and reported in GE Report NEDE-24988 to satisfy the requi rements of II.D.1 of NUREG-0737.

Test reports/records of the above qualific ation tests are available for inspection.

Each SRV is production tested at the vendor's shop to ensure , by demonstration, each SRV manufactured will reliably perfor m its required function(s). Th e SRV production test consist of

a. Inlet and outlet hydrostatic tests at sp ecified conditions to satisfy ASME Code requirements,

b. Emergency operability test to verify capability of actuator to open the SRV without inlet pressure applied to the valve,

c. Actuator system leakage test to assure pneumatic leaktightness is compatible with plant air system make-up requirements, d. Nitrogen set pressure and leakage test to rough adjust setpoint and ensure seat quality of seating surface prior to steam tests (optional), e. Set pressure and blowdown test under thermally stabilized and saturated steam conditions,

f. Response time tests to verify relie f opening and closing times under thermally stabilized and saturate d steam conditions, and C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 5.2-15 g. Steam leakage tests to verify leaktightness.

The valves are normally installed as received from the factory providing there is no apparent evidence of damage during transportation, handling, and storage.

For valves stored longer than one year, it is recommended they be recertified to ensure operability. The GE equipment specification requires certification from the va lve manufacturer that de sign and performance requirements have been met.

Testing to satisfy the ASME Code requirements is normally perfor med in situ. Testing can be performed locally or remotely.

The local test method is conducte d using a test fixture that is temporarily mounted on the SRV and then removed on completion of the test. Remote testing is accomplished using a permanently mounted pneumatic head assembly th at is controlled by a remote computer. This method does not require any pe rsonnel entry into the containment for the purpose of testing.

During the startup test program, all of the main steam SRVs were tested for proper operation. These tests include a documentation review to ensure that the valves were properly installed, properly handled during transporta tion, storage, and installation, and were properly maintained as to cleanliness prior to performance of any te sts. In addition, the air accumulator capacity, SRV nameplate set pressure, and capacity were compared with the system design documentation for compliance.

Actual mechanical tests incl uded an operability check of th e SRV discharge line vacuum breakers, actuation of the individual SRVs by each remote manual switch (main control room

and/or remote shutdown panel) to demonstrate full lift, sm ooth stroke, and opening time characteristics, actuation of each SRV in the relief mode by stimulating its pressure switch, and a demonstration that each SRV accumulator (ADS and/or normal) has sufficient capacity to operate the SRV air actuator as required by the system design documentation. Finally, the ADS logic was fully tested for proper performa nce. Note that only the air actuator was exercised during many of the startup tests.

This minimizes valve wear and unnecessary maintenance.

During the power ascension phase of the st artup test program, each SRV was manually actuated at approximately 250 ps ig reactor pressure to demonstrate valve operability. At approximately 50% power each SRV was actuated a second time to measure discharge capacity and to demonstrate that no blockage in the SRV di scharge line existed.

At commercial turnover the scope of SRV testing was governed by ASME B&PV Code Section XI, Article IWV and the Technical Specifications. This article specifies the rules and requirements for inservice testing to verify operational readine ss of the SRVs. This code section is applied to both AD S and non-ADS valves alike.

Supplemental tests of the ADS C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 5.2-16 valves each operating cycle are required by the Technical Specific ations. Applying Section XI, the SRV test schedule (i n part) is as follows:

Time Period Number of Total Elapsed (Cycle) Valves Tested Tested Time (years)

1 6 6 1.5 2 4 10 2.5 3 4 14 3.5 4 4 18 4.5 5 4 4 1.0 6 4 8 2.0 7 4 12 3.0 8 4 16 4.0 9 2 18 5.0 Note that following the return to service of th e testing SRVs, an operability demonstration will be performed in compliance with Section XI, Article IWV-3200.

This combination of the start up test program, Technical Spec ifications surv eillance, and inservice inspection testing satis fies industry standards for SR V operability demonstrations.

Energy Northwest participated in the BW R Owners' Group for TMI concerns on SRV reliability. The final test pr ogram description was submitted to the NRC by the BWR Owners' Group and is endorsed by Energy Northwest.

5.2.3 REACTOR

COOLANT PRESSURE BOUNDARY MATERIALS

5.2.3.1 Material Specifications

Table 5.2-7 lists the principal pressure retaining materials and the appropriate material specifications for the RCPB components.

5.2.3.2 Compatibility with Reactor Coolant 5.2.3.2.1 Pressurized Water Reacto r Chemistry of Reactor Coolant Not applicable to BWRs.

5.2.3.2.2 Boiling Water Reactor Chemistry of Reactor Coolant

Regulatory Guide 1.56 compliance is addressed in Section 1.8.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-03-069 5.2-17 Reactor feedwater (RFW) quality is maintained in accordance with the Licensee Controlled Specifications (LCS) and as described in Section 10.4.6.

Materials in the primary system are primarily austenitic stainles s steel and Zircaloy cladding.

The reactor water chemistry limits are established to provide an environment favorable to these materials. Limits are placed on conductivity and chloride c oncentrations. Conductivity is limited because it can be continuously and relia bly measured and gives an indication of abnormal conditions and the presence of unusual ma terials in the coolant. Chloride limits are specified to prevent stress corrosion cracking of stainless stee

l. For further information, see Reference 5.2-2. Periodically GENE will perform a NobleChem application to create a catalytic layering of noble metals, platinum and rhodium, 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 ra nge. When conductivity becomes abnormal, chloride measurements are made to determine whether or not they are also out of their normal operating values. Conduc tivity could be high due to the presence of a neutral salt, which would not have an effect on pH or chloride. In such a case, high cond uctivity alone is not a cause for shutdown. In some types of water-cooled reactors, conductivities are high because of the purposeful use of additives. In BWRs, however, where no additives which significantly affect conductivity are used a nd where near neutral pH is ma intained, conductiv ity provides a good and prompt measure of the quality of the reactor water. A depleted zinc oxide (DZO) skid is connected to the RFW system which maintains DZO concentration in reactor water. This has a small effect on conductivity. Significant changes in conductivity provide the operator with a warning mechanism so he can investigate and reme dy the condition before reactor water limits are reached. Methods available to the operator for correcting the off-standard condition include ope ration of the reactor cleanup sy stem, reducing the input of impurities, and placing the reactor in the cold shutdown condition.

The major benefit of cold shutdown is to reduce the temperature-depende nt corrosion rates and provide time for the cleanup system to reestablish the purity of the reactor coolant.

During normal plant operation, the dynamic oxygen equilibrium, in the reactor vessel water phase, established by steam-gas stripping and radiol ytic formation (principally) rates, corresponds to a nominal value of approximately 200 ppb (0.2 ppm) of oxygen at rated operating conditions. Slight vari ations around this value have been observed as a result of differences in neutron fl ux density, core-flow, and r ecirculation flow rate.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-02-046,03-069 5.2-18 A reactor water cleanup (RWCU) system is provided for removal of feedwater input impurities plus corrosion and fission products originating from primary sy stem components. The cleanup process consists of filtration a nd ion exchange and serves to maintain a high level of water purity in the reactor coolant.

Additional water input to the reactor vessel or iginates from the control rod drive (CRD) cooling water. The CRD water is of feedwate r quality. Additional filt ration of the CRD water to remove insoluble corrosion products takes place within the CRD system prior to entering the drive mechanisms and reactor vessel.

An iron addition system is used to inject an ir on oxalate/demineralized water solution into the suction line of the condensate booster pumps. The injection flow rate is extremely small when compared to condensate system fl ow rate. This iron injection system will have a negligible affect on the oxygen concentration in the RFW.

A hydrogen injection system is installed across the condensate booster pumps. This hydrogen injection system will have a negligible affect on the oxyge n concentration in the RFW.

No other inputs of water or sources of oxygen are present during normal plant operation.

During plant conditions other than normal ope ration, additional inputs and mechanisms are present as reactor coolant water coul d contain up to 8 ppm dissolved oxygen.

Conductivity of the primary coolant is continuous ly monitored with instruments connected to the reactor water recirculation loop and the RWCU system inlet. The effluent from the RWCU system is also monitored for conductivity on a continuous basis. These measurements provide reasonable surveillance of the reactor coolant.

Grab sample points are provide d at the locations shown in Table 5.2-8, for special measurements such as pH, oxygen, ch loride, and radiochemical content.

The relationship of chloride concentration to specific conduc tance measured at 25°C for chloride compounds such as sodium chloride and hydrochloric acid can be calculated (see Figure 5.2-10). Values for these compounds essentially bracket values of other common chloride salts or mixtures at the same chloride concentration. Surveillance requirements are based on these relationships.

In addition to this program, limits, monitoring, and sampling requirements are established for the condensate, condensate treatment, and feedwa ter system. Thus, a total plant water quality surveillance program is established providing assurance that o ff specification conditions will quickly be detected and corrected.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-023 5.2-19 The sampling frequency establis hed for primary coolant at no rmal conductivity levels is adequate for instrument checks and routine audit purposes. When specific conductance increases and higher chloride c oncentrations are possible or when continuous conductivity monitoring is unavailable, sampling frequency is increased according to LCS.

The primary coolant conductivity monitoring instrumentation, ranges, sensor, and indicator locations are shown in Table 5.2-8. The sampling is coordinated in a reactor sample station especially designed with constant temperature control and samp le conditioning a nd flow control equipment.

Water Purity During a Condensate Leakage

Due to improved water quality limits, any appreci able circulating water inleakage would result in water chemistry conditions outside acceptable limits and require action(s) to return the water quality to within applicable limits for continued plant operation.

5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant

The materials of construction exposed to the reactor coolan t consist of the following:

a. Solution annealed austenitic stainless st eels (both wrought and cast) types 304, 304L, 316 and 316L,

b. Nickel base alloys -

Inconel 600 and Inconel X750 and Inconel 82 and 182 weld metal,

c. Carbon steel and low alloy steel,

d. Some 400 series martens itic stainless steel (all tempered at a minimum of 1100°F), and

e. Cobalt, chromium, nickel, and ir on based alloy hardfacing material

All of these materials of cons truction are generally resistant to stress corrosion in the BWR coolant. General corrosion on all materials, except carbon and low alloy steel, is negligible.

Conservative corrosion allowances are provided for all exposed surfaces of carbon and low alloy steels.

Contaminants in the reactor coolant are cont rolled to very low limits by the reactor water quality specifications. No detrimen tal effects will occur on any of the materials from allowable contaminant levels in the high purity reactor coolant. Radiolytic products in the BWR have no adverse effects on the c onstruction materials.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-20 The recirculation system piping and normally flooded sec tions of the reactor vessel are coated as needed utilizing the GENE NobleChem application process with a microscopic layer of noble metals. This coating serv es to prevent as well as miti gate IGSCC by eliminating the dissolved oxygen at the metal su rface when an amount of hydr ogen gas is added in a molar ratio of greater than 2 to 1 hydrogen to oxygen.

Type 304 stainless steel has been replaced with type 316L stainless steel in the recirculation inlet line safe ends. The bypass lines and the CR D hydraulic return line were eliminated and nozzles capped. The core spra y lines are fabricat ed of carbon steel. The piping components that do not comply with the requirements of the Generic Letter 88-01 (GL 88-01), NRC Position on IGSCC BWR austenitic Stainless Steel Piping, will be subjected to the augmented inspection requirements of GL 88-01 as modified in Energy Northwest response (see Section 5.2.4 and Tables 5.2-9 and 5.2-10). 5.2.3.2.4 Compatibility of Cons truction Materials with Exte rnal Insulation and Reactor Coolant The materials of cons truction exposed to external insulation are

a. Solution annealed austenitic stainless steels (e.g., types 304, 304L, and 316), and

b. Carbon and low alloy steel.

Two types of external insulation are used. Reflective metal in sulation used does not contribute to any surface contamination and has no effect on construction materials. The fibrous

insulation used meets the requirements of Regulat ory Guide 1.36.

DZO and iron are additives in the BWR coolant.

Leakage would expo se materials to high purity demineralized water, DZO, and iron. Exposure to demine ralized water, DZO, and iron would cause no detrimental effects.

5.2.3.3 Fabrication and Proce ssing of Ferritic Materials a nd Austenitic Stainless Steels

Fracture toughness requirements for the ferritic material s used for piping and valves (no ferritic pumps in RCPB) of the RCPB were as follows:

Safety/relief valves were exempted from fracture toughness requirements because Section III of the 1971 ASME B&PV Code did not require impact testing on valves with inlet connections of 6 in. or less nominal pipe size.

Main steam isolation valves were also exempted because the mandatory ASME Code, 1971 Edition through the Winter 1971 Addenda, required brittle fracture testing on ferritic pressure

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-21 boundary components only if re quired in the Design Specificati on. The Design Specification did not require brittle fracture testing because the system temperature is in excess of 250°F at pressure above 20% of the desi gn pressure. Material informa tion pertaining to the MSIVs is contained in Table 5.2-11. Main steam piping was tested in accordance with and met the fr acture toughness requirements of Paragraph NB-230 0 of the 1972 Summer Addenda to ASME Code,Section III.

The ferritic pressure boundary material of the RPV was qua lified by impact testing in accordance with the 1971 Edition of Section III ASME Code and Addenda to and including the Summer 1971 Addenda.

Austenitic stainless steels with a yield strength greater than 90,000 psi are not used.

The degree of compliance with Regulatory Guides 1.31, 1.34, 1.37, 1.43, 1.44, 1.50, 1.66, and 1.71 is addressed in Section 1.8.

5.2.4 INSERVICE

INSPECTION AND TESTING OF THE REACTOR COOLANT PRESSURE BOUNDARY

The structural integrity of AS ME Code Class 1, 2, and 3 components are maintained as required by the ISI program in accordance with 10 CFR 50.55a. With the structural integrity of any component not co nforming to the above re quirements, the structur al integrity will be restored to within its limits or the affected component will be isolated. For Class 1 components, this isolation will be accomplished prior to increasing reactor coolant system temperature more than 50

°F above the minimum temperature required by nil-ductility transition (NDT) considerations.

For Class 2 components, isolation will be accomplished prior to increasing reactor coolant system temperature above 200

°F.

Inservice Inspections are perf ormed in accordance with the requirements of 10 CFR 50.55a subparagraph (g) as described in th e Inservice Inspect ion Program Plan.

5.2.4.1 System Boundary Subject to Inspection

The system boundary subject to in spection is defined in the Inservice Inspection Program Plan. The RPV was examined prior to service in accordance with the requirements of the 1974 Edition of the ASME B&PV Code,Section X I, including the Summer 1975 Addenda. All Class 1 piping, pumps, and valves were examined prior to serv ice in accordance with the requirements of the 1974 Edition of the ASME B&PV Code,Section XI, with Addenda through Summer 1975, including Appendix III from the Winter 1975 Addenda.

The design of the RPV shield wall and external inse rvice inspection system was completed prior to the promulgation of amendments to 10 CFR 50.55a which require the upgrading of the C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-22 utility's inservice inspection code commitment for examina tions subsequent to the baseline examination. The design has allowed some additional access for inspections and coverages anticipated to be required by later codes, where possible. The result of this effort has increased the areas on the RPV available to inservice inspection (approximately 84% of the vessel weld volume is accessible) and has allowed the pipi ng examination to be upgraded to conform to the requirements of the Summer 1975 Addenda to Sec tion XI as far as practical.

The preservice examination was performed on Class 1 components and piping pursuant to the requirements of the 1974 Edition of the ASME B&PV Code,Section XI, including the Summer 1975 Addenda for both the RPV and associated piping, pumps, and va lves. It is described in the Preservice Inspection Program Plan (Reference 5.2-6).

5.2.4.2 Arrangement of Systems and Components to Provide Accessibility

Access for the purpose of inservic e inspection is defined as the design of the plant with the proper clearances for exami nation personnel and/or equipment to perform inservice examinations. The RCPB for the RPV is designed to provide compliance with the provisions for access as required by Subarticle IWA-1500 of the 1974 Edition of the ASME B&PV Code,Section XI, including the Summer 1975 Addenda. The RCPB for piping, pumps, and valves is designed to provide compliance with the provis ions for access as required by Subarticle IWA-1500 of the 1974 Edition of the ASME B&

PV Code,Section XI, with addenda through Summer 1975.

Access is provided for volumetr ic examination of the pressure containing welds from the external surfaces of components and piping by means of remo vable insulation, removable shielding, and permanent tracks for remote inspection devices in areas where personnel access is restricted. The provisions for suitable access for inservice inspection examinations minimizes the time required for th ese inspections and, hence, redu ces the amount of radiation exposure to both plant and examination personnel. Working pla tforms are provided at most strategic locations in the plant which permit re ady access to those area s of the RCPB which are designated as inspection points in the inserv ice inspection program.

Temporary scaffolding will be used as required to gain access for examination.

Energy Northwest retained Southwest Research Institute to provide an independent assessment as to the suitability of plant access provisions for inservice inspection. This overview provided for identification of design modification or inspection technique development needs to ensure maximum practical complian ce with code requirements.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-23 5.2.4.2.1 Reactor Pressure Vessel

Access for inspection of the RPV is as follows:

a. Access to the exterior su rface of the RPV for inservice inspection is provided by removable insulation and shield plugs.

Hinged shield wall plugs around nozzles are used to gain access for nozzle inspection. A minimum annular space of 8.25 in. is provided between the vessel exterior surfa ce and the insulation interior surface to permit the insertion of remotely operated inspection devices between the insulation and the reactor vessel. Th e RPV nozzle insulation is removable. This design allows sufficient clearances for the mounting of a nozzle-to-shell examination device from tracks located either at the nozzle safe-end or at the pipe area. Examina tions that can be pe rformed from these tracks include the required coverage of the nozzle-to-she ll welds and depending on technique, could provid e examination coverage of the nozzle inner radius section and nozzle-to-safe-end weld. Access, geometry and radiation level considerations will determine those nozzl es scheduled for manual examination.

b. The vessel flange area and vessel closure head can be examined during refueling outages using m anual ultrasonic techniques.

With the closure head removed, access is afforded to the upper interior clad surface of the vessel by removal of a steam dryer and steam separ ator assembly. Removal of these components also enables the examination of remaining internal components by remote visual techniques.

The volumetric examinati on of the vessel-to-flange weld and closure head-to-fl ange weld can be performe d by applying the search units directly to the seal surface areas. The vessel-to-flange weld is also

examined from vessel shell surface.

c. The closure head is dry st ored during refueling which facilitates direct manual examination. Removable insulation allo ws examination of the head welds from the outside surface. Reactor vessel nuts and washers are removed to dry storage for examination during refueling.

Selected studs are examined during re fueling in accordance with the Inservice Inspection Program Plan.

d. Openings in the RPV support skirt are provided to permit access to the RPV bottom head for purposes of inservice examination. The examinations performed include volumetric examinations of circumferential welds, portions of the meridional welds, portions of the do llar plate longitudinal welds, and visual examination of accessible penetration welds.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-24 5.2.4.2.2 Piping, Pu mps, and Valves The physical arrangement of piping, pumps, and valves is designed to allow personnel access to welds requiring inservice inspection. Mod ifications to the initial plant design have been incorporated where practicable to provide in spection access on Class 1 piping systems.

Removable insulation is provided on those piping systems requiring inspection. In addition, the placement of pipe hangers and supports with respect to t hose welds requiring inspection have been reviewed and mod ified where necessary to reduc e the amount of plant support required in these areas during inspection. Wo rking platforms are provided to facilitate servicing most of the pumps and valves. Temporar y platforms, scaffolding, and ladders will be provided to gain additional access for piping and some pump and valve examinations. An effort has been made to mini mize the number of fitting-to-fitti ng welds within the inspection boundary. Welds requiring inspecti on are located to permit ultr asonic examinations from at least one side, but where compone nt geometries permit, access fr om both sides of the weld is provided. The surface of welds within the inspection boundary are prepared to permit effective ultrasonic examination.

5.2.4.3 Examination T echniques and Procedures

Examination techniques and proce dures for the preservice examination, including any special technique and procedure, met the requirements of Table IWB-2600 of the 1974 Edition of the ASME B&PV Code,Section XI, including the Summer 1975 Addenda for both the RPV and the associated piping, pump, and valve examinations.

Examination techniques and procedures for inservice inspections are in accordance with the Inservice Inspection Program Plan.

During plant design, an effort was m ade to upgrade the requirement for calibration standards. Where upgrading was not feasible, material of the same P series with similar acoustic characteristics were used.

5.2.4.3.1 Equipment for Inservice Inspection

Access for inservice inspection of the RPV seam welds is accomplishe d through openings in the sacrificial shield. These openings are provided at each nozzle location. Permanently installed tracks between the vessel surface and the insulation can be used for mounting remotely operated devices. Access is also provided for devices that do not require use of these tracks. Remote ultrasonic scanning equipment for examin ation of the nozzle-to-vessel welds will be supported and guided from tracks temporarily mounted on the pipe connected to the nozzle. The examination equipment will provide radial and circumferential motion to the ultrasonic transducer while rotating about the nozzle. Installation of th e equipment will be accomplished through the access openings in the sacrificial shield which are provided at each nozzle location.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-25 5.2.4.3.2 Coordination of Inspection Equipment With Access Provisions Access to areas of the plant requi ring inservice inspection is provi ded to allow use of standard equipment wherever practicable. Design in general provides for free space envelopes both radially and axially from welds to be examin ed so standard manual examination equipment may be utilized. Any special equipment or techniques used will achieve the sensitivities required by the codes.

5.2.4.3.3 Manual Examination In areas where manual ultrasoni c examination is performed, all reportable indications are recorded consistent with current inservice inspection codes in effect. Radiographic techniques may be used where ultrasonic techniques are not practical. In areas where manual surface or direct visual examinations are performed, all recordable indications will be in accordance with the Inservice Inspec tion Program Plan.

5.2.4.4 Inspection Intervals

Inspection intervals are defined in the Inservice Inspection Program Plan.

5.2.4.5 Examination Cate gories and Requirements

Examination categories and require ments for the preser vice inspection ar e defined in the Preservice Inspecti on Program Plan and closely follo w the categories and requirements specified in Tables IWB-2500 and IWB-2600 of the 1974 Edition with Addenda through Summer 1975 of the ASME B&PV Code,Section XI, for the RPV and the associated piping, pumps, and valves.

Examination categories and requirements for inse rvice inspections are in accordance with the requirements of ASME Section XI and are contained in the Inservice Inspection Program Plan.

5.2.4.6 Evaluation of Examination Results

Evaluation of results for the RPV, pump, and valve baseline examinations were conducted in accordance with Article IWB-3000 of the 1974 Ed ition of the ASME B&PV Code,Section XI, including the Summer 1975 Addenda.

Evaluation of examination results for piping baseline examinations were conducted in accordance with Article IWB-3000 of the 1974 Edition of the ASME B&PV Code,Section IX, with Addenda through Winter 1975. Energy Northwest recognized that Section XI had been promulgated as an eff ective code by 10 CFR 50.55a, for the baseline examinations, only through th e Summer 1975 Addenda.

However, Energy Northwest also recognized that even though the code through Summe r 1975 Addenda included evaluation criteria which could be interpreted to apply to pipi ng (Category B-J) welds, the evaluation criteria found in the Winter 1975 Adde nda clearly provides eva luation criteria which C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-26 are applicable to these welds. Energy Northwest was unaware that the NRC staff was opposed to these evaluation criteria and an ticipates that the criteria wh ich will appear in the future codes will be consistent therewith.

Evaluations are performed in accordance with the Inservice Inspection Program Plan.

5.2.4.7 System Leakage and Hydrostatic Pressure Tests

The requirement for baseline hydr ostatic test for the RPV was satisfied by the hydrostatic test performed in accordance with the requirement s of ASME Section III. Similarly, the requirements for the baseline piping system leak age and hydrostatic test s were satisfied by reference to the Section III hydrostatic test report as permitted by ASME Section XI, IWA-5210(b).

Subsequent hydrostatic a nd system leak tests are conduc ted to the code in effect in accordance with the Inservice Inspection Program Plan.

5.2.4.8 Inservice Inspection Commitment

All quality Group A components were examined once prior to startup in accordance with the above requirements. This pre operational examination served to satisfy the requirements of IWB-2100 of the 1974 Edition of the ASME B&PV Code,Section XI, including the Summer 1975 Addenda for the RPV and associated piping, pumps, and valves. Inservice inspection of Columbia Genera ting Station is performed in accordance with the Inservice Inspection Program Plan.

5.2.4.9 Augmented Inservice Inspection to Protect Against Postulated Piping Failures

An augmented Inservice Inspection Program Pl an has been implemented for Columbia Generating Station, on high energy

• Class 1 piping systems whic h penetrate containment for which the effects of postulated pipe breaks would be unacceptable. This program is described in the Inservice Inspection Program Plan.

• High-energy lines include those systems that, during normal plant conditions, are either in operation or maintained pressuri zed and where either the maximu m operating pressure exceeds 275 psig or maximum opera ting temperature exceeds 200

°F. If, for a particular line, the above pressure and temperature limits are not exceeded more than 2%

of the time that the system is in operation, then that line is considered moderate energy and is exempt from the requirement for augmente d inservice inspection.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-27 5.2.4.10 Augmented Inservice Inspection of Reactor Pressure Vessel Feedwater Nozzles 5.2.4.10.1 Preservi ce Examination

Energy Northwest performed a preservice inspection ultrasonic examination of the RFW nozzle inner radii, bore, and sa fe end regions as desc ribed in the Preservi ce Inspection Program Plan.

In addition, a preservice liqui d penetrant examination was perf ormed on the accessible areas of all RFW nozzle inner radius surfaces.

5.2.4.10.2 Inservice Examination

Inservice examinations of RFW nozzles are performed in accordance with the Inservice Inspection Program Plan.

5.2.4.11 Augmented Inservice Inspecti on for Intergranular Stress Corrosion Cracking Energy Northwest performed an ultrasonic examination of all Code Class 1 piping which is considered susceptible to IGSCC. The results are reported in the Preservice Inspection Summary Report (References 5.2-9 and 5.2-10).

GL 88-01 weld categories and augmented insp ection requirements are described in the Inservice Inspecti on Program Plan.

5.2.4.12 ASME Section XI Repairs/Replacements

The repair or modification of N-stamped comp onents will be performed in accordance with the Edition and Addenda of ASME S ection XI defined in the Inservice Inspection Program Plan and in accordance with ASME Section III (Code Edition and Addenda to which the component was fabricated).

Deviations to the above refe renced code edition and addenda as allowed by code will be reviewed by Energy Northwest and authorized on a case-by-case basis.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-11-005 5.2-28 5.2.5 DETECTION OF LEAKAGE THROUGH REACTOR COOLANT PRESSURE BOUNDARY

5.2.5.1 Leakage Detection Methods

The nuclear boiler leak detection system consists of temperatur e, pressure, and flow sensors with associated instrumentation and alarms. This system detects, annuncia tes, and isolates (in certain cases) leakages in the following systems:

a. Main steam lines,

b. RWCU system,

c. RHR system,

d. Reactor core isolation cooling (RCIC) system,

e. Feedwater system,

f. HPCS,

g. LPCS, and

h. Coolant system within the primary containment.

Isolation and/or alarm of affe cted systems and the detection methods used are summarized in Table 5.2-12.

Small leaks (5 gpm and less) are detected by te mperature and pressure changes, drain sump pump activities, floor drain flow monitoring, an d fission product monitoring. Large leaks are also detected by changes in reactor water leve l and changes in flow rates in process lines.

The 5-gpm leakage rate is the limit on unidentified leakage. The leak detection system sensitivity and response is di scussed in Section 7.6.2.4.

Compliance with Regulatory Guide 1.45 is described in Section

1.8. Table

5.2-12 summarizes the actions taken by each le akage detection function. The table shows that those systems which detect gross leakage initiate immediate auto matic isolation. The systems which are capable of detecting small leaks initiate an alarm in the control room. The operator can manually isolate the violated system or take othe r appropriate action.

5.2.5.1.1 Detection of Abnormal Leakage Within the Primary Containment Leaks within the drywell are detected by m onitoring for abnormally high-pressure and temperature within the drywell, high fillup rates of equipment and floor drain sumps, excessive

temperature difference between th e inlet and outlet cooling wate r for the drywell coolers, a decrease in the reactor vessel water level, and high levels of fission products in the drywell atmosphere. Temperatures within the drywell ar e monitored at various elevations. Also the temperature of the inlet and exit ai r to the atmosphere is monitored. Excessive temperatures in C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-29 the drywell, increased drywell drain sump flow rate, and drywell high-pressure are annunciated by alarms in the control room.

Drywell high pressure and low reactor vessel water level will cause automatic primary containment isolation. In addition, low reactor vessel water level will isolate the main steam lines. The systems within the drywell share a common area; therefore, their leakage detection system s are common. Each of the leakage detection systems inside the drywell is designed with a capability of detecting le akage rates less than those established by the Technical Specifications.

5.2.5.1.2 Detection of Abnormal Leakage Outside the Primary Containment

Outside the drywell, the piping within each system monitored for leakage is in compartments or rooms, separate from other systems where feasible, so th at leakage may be detected by area temperature indications. Each leakage detecti on system discussed in the following paragraphs is designed to detect leak rates that are less than thos e established by the Technical Specifications. The method used to monito r for leakage for each RCPB component is described in Table 5.2-12. a. Ambient and differential room ventilation temperature

A differential temperature se nsing system is installed in each room containing equipment that is part of the RCPB.

These rooms are the RCIC, RHR, and the RWCU systems equipment rooms and main steam line tunnel. Temperature sensors are placed in the inlet and outlet ventilation ducts or across room boundaries. Other sensors are installed in the equi pment areas to monitor ambient temperature. A differential temperature monitor reads each set of sensors and/or ambient temperature and initiates an alarm and isolation when the temperature reaches a preset value. Annunciator and remote readouts from temperature sensors are indi cated in the control room.

Spurious isolations of systems due to a relatively sharp drop in outside ambient temperature is highly unlikely. For ex ample, the normal approximate operating differential temperature for the RHR and RCIC pump rooms is 26°F and 32°F respectively. The temperat ure elements are lo cated at the face of the supply and return ductwork in each pump room. The setpoint differential for isolation is 50°F and 55°F for RCIC and RHR to allow for heat released from a predetermined steam leak. Analysis has shown that it would take a 30°F/hr

ambient (outside) temperature decrease for about 2 hr to cause isolation. This magnitude of temperature drop is not supported historically because meteorological data for Hanford has not recorded ch anges of this magnitude.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-30 b. Reactor building sump flow measurement Instrumentation monitors and indicates the amount of leakag e into the reactor building floor drainage system. The normal leakage collected in the system consists of leakage from the RWCU and CRD systems and from other miscellaneous vents and drains.

c. Visual and audible inspection Accessible areas are inspected periodically and the temperature and flow indicators discussed above are monitored regularly as required by the Technical Specifications. Any instrument indication of abnormal leakage will be investigated.

d. Differential flow measur ement (cleanup system only)

Because of the arrangeme nt of the RWCU systems, differential flow measurement provides an accurate leakage detection method. The flow from the reactor vessel is compared w ith the flow back to the vessel. An alarm in the control room and an isolation signal are initiated when higher flow out of the reactor vessel indicates that a leak may exist.

5.2.5.2 Leak Detection Devices

a. Drywell floor drain sump measurement

The normal design leakage collected in the floor drain sump consists of leakage from the CRDs, valve flange leakage, floor drains, closed co oling water system drywell cooling unit drains, and potential valve stem leaks. The floor drain sump collects unidentified leakage.

Design details are given in Section 9.3.3. b. Drywell equipment drain sump

The equipment drain sump collects only id entified leakage.

This sump receives condensate drainage from pump seal leakoff and the reactor vessel head flange vent drain. Collection in excess of background leakage would indicate reactor coolant leakage. Design de tails are given in Section 9.3.3. c. Drywell air sampling

The primary containment radiation monitori ng system is used to supplement the temperature, pressure, and flow variati on method described previously to detect

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-31 leaks in the nuclear system process barrier. This system is described in Sections 11.5 and 7.6. Radiation monitors are useful as leak detection devices because of their sensitivity and rapid response to leaks.

After several weeks of full power operation, a set level of b ackground radiation is established.

Any sudden or unexplained increase in b ackground radiation indicat es a possible primary coolant leak within the primary containment. If an increase is noted, a comparison with other leak detection devices having a relationship to each other is made, particularly the equipment and floor drain flow rate monitors, and the reactor building sump pumps activation on high sump level.

Using the flow rate monitors as a reference, the comparisons provide independent indications of a leak within the primary containment. Th is provides diversity in leak detection.

d. Reactor vessel head closure

The reactor vessel head clos ure is provided with double seals with a leak off connection between seals that is piped to the equipm ent drain sump. Leakage through the first seal is annunciated in the control room. When pressure between the seals increases, an alarm in the control room is actuated. The second seal then operates to contain the vessel pressure.

e. Reactor water recirculation pump seal

Reactor water recirculation pump seal leaks are detected by monitoring the drain line. Leakage, indicated by high flow rate, alarms in the control room.

Leakage is piped to th e equipment drain tank.

f. Safety/relief valves

Tail pipe temperature sensors connected to a multipoint recorder are provided to detect SRV leakage during reactor operation. Safety/relief valve temperature elements are mounted, using a thermowell, in the SR V discharge piping several feet from the valve body. Temperature ri se above ambient is recorded in the main control room.

5.2.5.3 Indication in the Control Room

Details of the leakage detection system indications are included in Section 7.6.1.3.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-32 5.2.5.4 Limits for Reactor Coolant Leakage 5.2.5.4.1 Total Leakage Rate

The total leakage rate consists of all leakage, iden tified and unidentified, that flows to the drywell floor drain and equipment drain sumps.

The total leakage rate li mit is established so that, in the absence of normal ac power with loss of feedwater supply, make-up capabilities are provided by the RCIC system.

The equipment sump and the floor drain sump co llect all leakage. Th e equipment sump is drained by one 50-gpm pump and th e floor drain sump is draine d by two 50-gpm pumps. The total leakage rate limit from inside containm ent is established at 25 gpm, which includes no more than 5 gpm unidentified l eakage. The total l eakage rate limit is lo w enough to prevent overflow of the drywell sumps.

5.2.5.4.2 Normally Expected Leakage Rate

The pump packing glands and other seals in systems that are part of the RCPB and from which normal design leakage is expected , are provided with drains or auxiliary sealing systems. Nuclear system pumps inside th e drywell are equipped with double seals. Leakage from the primary recirculation pump seal s is piped to the equipment drain sump. Leakage in the discharge lines from the main steam SRVs is m onitored by temperature sensors that transmit a signal to the control room. Any temperature increase above the drywe ll ambient temperature detected by these sensors indicates valve leakage.

Thus, the leakage rates from pumps and the re actor vessel head seal are measurable during plant operation. These leakage rates, plus any other leakage rates meas ured while the drywell is open, are defined as identified leakage rates.

The identified leakage is measured continuously and the leakage rate will be calculated and recorded on a frequency of at least once per 12 hr in accordance with the Technical Specifications. The procedures describing how the identified leakage rate is determined include provisions for showing the identified leakage rate has not exceeded the maximum allowable value of 25 gpm, including no mo re than 5 gpm unidentified leakage.

Each equipment leak-off connection has been provided with a temperature element which will identify to the operator that a higher than normal temperature exists at that particular location.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.2-33 5.2.5.5 Unidentified Leak age Inside the Drywell 5.2.5.5.1 Unidentified Leakage Rate

The unidentified leakage rate is the portion of the to tal leakage rate recei ved in the drywell sumps that is not identified as pr eviously described. A threat of significant compromise to the nuclear system process barrier ex ists if the barrier contains a crack that is large enough to propagate rapidly (critical crack length). The unidentified leakage rate limit must be low because of the possibility that most of the unidentified leakage rate might be emitted from a single crack in the nuclear system process barrier.

An allowance for leakage that does not compromise barrier integr ity and is not identifiable is made for normal plant operation.

The unidentified leakage rate limit is established at the 5-gpm rate to allow time for corrective action before the process barrier c ould be significantly compromised.

The following indications are available to the control room operator for evaluating and detecting unidentified leakage:

Drywell pressure recorders, Drywell temperature recorders, Drywell floor drain total flow recorder, Reactor building floor drain sump fillup rate timer, Reactor building floor drain sump pump out rate timer, Drywell cooler cooling water differential temper ature recorder, Reactor vessel water level, and

Drywell atmosphere radiation monitors.

While the indications listed above have no definitive correla tion between their engineering units, they provide an early warn ing of a potential leak to the ope rator. The actual unidentified leak rate is determined by observing the drywell floor drain system flow rate recorders provided in the control room. Since the monitoring is not computerized, a computer failure would not affect indications.

5.2.5.5.2 Length of Through-Wall Flaw Experiments conducte d by GE and Battelle Memorial Ins titute (BMI) permit an analysis of critical crack size and crack opening displacement (References 5.2-4 and 5.2-5). This analysis relates to axially oriented through-wall cracks and provides a realis tic estimate of the leak rate to be expected from a crack of critical size. In every case, the leak rate from a crack of critical size is significantly gr eater than the 5-gpm criterion.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-029,11-005 5.2-34 If either the total or unidentified leak rate limits are exceeded, an orderly shutdown would be initiated and the reactor would be placed in a cold shutdown condition in accordance with the Technical Specifications.

5.2.5.5.3 Criteria to Evaluate the Adequacy and Margin of the Leak Detection System

For process lines that ar e normally open, there are at least two different met hods of detecting abnormal leakage from each system within the nuclear system pr ocess barrier lo cated in the drywell, reactor building, and auxiliary building as shown in Table 5.2-12. The instrumentation is designed so it can be set to provide alarms at established leakage rate limits and isolate the affected system, if necessary. The alarm points are determ ined analytically or based on measurements of appr opriate parameters made duri ng startup and preoperational tests. Some alarm points requi re hot operation data for their determination. Preoperational testing verified proper operation of the instrumentation for the alarm point used.

The unidentified leakage rate limit is based with an adequate margin for contingencies on the crack size large enough to propagate rapidly. The establishe d limit is sufficien tly low so that, even if the entire unidentified leakage rate we re coming from a single crack in the nuclear system process barrier, correctiv e action could be take n before the integrity of the barrier would be threatened with significant compromise.

The leak detection system sensitivity and response tim e is discussed in Section 7.6.2.4 such that an unidentified leakage rate increase of 1 gpm in less than 1 hr will be detected.

5.2.5.6 Safety Interfaces

The balance of plant/GE nuclear steam supply system safety inte rfaces for the leak detection system are the signals from the monitored balance-of-plant equipment and systems that are part of the nuclear system process barrier and associated wiring and cable lying outside the nuclear steam supply equipment. These balance-of-pla nt systems and equipment include the main steam line tunnel, the SRVs, a nd the turbine building sumps.

5.2.5.7 Testing and Calibration

Provisions for testing and calibration of the leak detection syst em are described in Section 7.6.

5.

2.6 REFERENCES

5.2-1 "Qualification of the One-Dimensional Core Transient Model (ODYN) for BWR's," NEDO-24154-A, Vol. 1 and 2, General Electric, August 1986.

5.2-2 J. M. Skarpelos and J. W. Bagg, "Chloride C ontrol in BWR Coolants,"

June 1973, NE DO-10899.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-10-029 5.2-35 5.2-3 W. L. Williams, Corrosi on, Vol. 13, 1957, p. 539t.

5.2-4 GEAP-5620, "Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flows," by M. B. Reynolds, April 1968.

5.2-5 "Investigation and Evalua tion of Cracking in Austeniti c Stainless Steel Piping of Boiling Water Reactor Plants," NUREG-76/067, NRC/PCSG, dated

October 1975.

5.2-6 Washington Public Power Supply Sy stem, 1985, "WNP-2 Preservice Inspection Program Plan," Washington Public Power Supply System, Richland, Washington.

5.2-7 Deleted.

5.2-8 Deleted.

5.2-9 Letter GO2-85-110 from G. C. Sorens on, Supply System, to A. Schwencer, NRC,

Subject:

Nuclear Project No. 2, CPPR-93 Preservice Inspection Program Plan, Amendment No. 4, Su mmary Report Supplement No. 1, NIS-1 Code Data Report, dated February 28, 1985.

5.2-10 Letter GO2-83-401 from G.

D. Bouchay, Supply Syst em, to A. Schwencer, NRC,

Subject:

Nuclear Project No. 2, CPPR-93, Preservice Inspection

Program Plan, Volume No. 4, "Preservice Inspection Summary Report", dated May 3, 1983.

5.2-11 "Supplemental Reload Licensing Report for Columbia" (most recent version referenced in COLR).

Table 5.2-1 Exceptions to Conformance to 10 CFR 50.55a Reactor Coolant Pressure Boundary Components Component Description Quantity Plant Identification System Number Purchase Order Date Code Applied ASME Section III Code Required by 10 CFR 50.55(a)

Component Status C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT Dece m ber 2001 5.2-37Main steam safety

relief valves 18 MS-RV-1 A-D MS-RV-2 A-D MS-RV-3 A-D MS-RV-4 A-D

MS-RV-5 B-C (B22-F013 A-V) April 1971 1971 Edition 1971 Summer Addenda FS a Recirc pumps 2 RRC-P-1A (B35-C001) April 1971 1971 Edition 1971 Summer Addenda FS Recirc gate valves 4 RRC-V-23/

RRC-V-67 (B35-F023/F067) June 1971 1971 Edition 1971 Summer Addenda FS Recirc flow control

valve 2 RRC-V-60 (B35-F060) June 1971 1971 Edition 1971 Summer Addenda FS Recirc piping 1 lot B35-G001 October 1971 1971 Summer Addenda 1971 Winter Addenda FS a FS = Fabricated and Shipped C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-2 Reactor Coolant Pressure Boundary Component Code C a se Interpretations

Number Tit l e Remarks 5.2-38 1. 1332 - Revision 6 Requirements for steel forgi n gs Regulatory Guide 1.85, Revision 6

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

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

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

5. 1141 - Revision 1 Foreign p r oduced steel Regulatory Guide 1.85, Revision 5

6. 1361 - Revision 2 Socket wel d s,Section I I I Regulatory Guide 1.84, Revision 9 7. 1525 Pipe descaled by means other than pickling,Section III

8. 1535 -

Revision 2 Hydrostatic test of Cl ass 1 nuclear valves,Section III Regulatory Guide 1.84, Revision 9 9. 1567 Testing lots of carbon and low alloy steel covered electrodes,Section III Regulatory Guide 1.85, Revision 6 10. 1621 -

Revision 1 Internal and external valve items,Section III, Class 1 Regulatory Guide 1.84, Revision 12 (for 1621-2) 11. 1588 Electro-etching of Section III code symbols Regulatory Guide 1.84, Revision 9 12. 1820 Alternative ultrasonic examination technique Section III, Division 1 Regulatory Guide 1.85, Revision 11 13. N181 Steel castings refined by the argon oxygen decarbonization process Section 3, Division 1 construction

14. 1711 Pressure relief valve, design rules,Section III, Division 1, Class 1, 2, 3

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-3 Nuclear Sy stem Sa f e ty/R elief Setp oints Number of Valves Spring Set Pressure (psig) ASME Rate Capacity at 103% Spring Set Pressure (lb/hr each)

Pressure Setpoint for the Power Actuated Mode (psig) 5.2-39 2 1165 876,500 1091 4 1175 883,950 1101 4 1185 891,380 1111 4 1195 898,800 1121 4 1205 906,250 1131 Note: Seven of the safety/relief valves serve in the automatic dep r essurization function.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-4 Systems Which May Initiate During Safety Valve Capacity Overpressure Event System Initiating/Trip Signal(s) a 5.2-40 Reactor Protection System Reactor trips "OFF" on high flux RCIC "ON" when reactor water level L2 "OFF" when reactor water level L8 HPCS "ON" when reactor water level L2 "OFF" when reactor water level L8 Recirculation system "OFF" when reactor water level L2 "OFF" when reactor pressure 1143 psig RWCU "OFF" when reactor water level L2 a Note: Vessel level trip se ttings L2 and L8 shown in Figure 5.3-3.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Table 5.2-5 Sequence of Events for Figure 5.2-2 Time-Sec Event LDCN-08-035 5.2-41 0 Initiate closure of all main steam isolation valves (MSIV).

0.45 MSIVs reached 85% open and initiate d reactor scram. However, hypothetical failure of this position scram was assumed in this analysis. 1.7 Neutron flux reached the hi gh 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.

4.5 Vessel

bottom pressure reached its peak value.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-6 Design Te m p erature, P r e ssure and Maximum Test

Pressure for RCPB Components

Component Design Temperature ( F) Design Pressure (psig)

Maximum Test Pressure (psig) 5.2-42 Reactor vessel 575 1250 1563 Recircu l ati o n system Pump discharge piping, through

valves 575 1650 (a) Pump discharge piping, beyond

valves 575 1550 (a) Pump suction piping 575 1250 (a) Pump and discharge valves 575 1650 (b)

Suction valves 575 1250 (b)

Flow control valve 575 1675 (a) Vessel drain line 575 1275 (a) Main steam system Main steam line 575 1250 (a) Main steam line valves 575 1250 (b) Residual heat removal system Shutdown s u ction Recirculation header to second isolation valve Piping 575 1250 (a) Valves 575 1250 (b) Pump discharge Reactor ve s s el to s eco n d isolation valve Piping 575 1250 (a) Valves 575 1250 (b)

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-6

Design Te m p erature, P r e ssure and Maximum Test Pressure for RCPB Components (Continued)

Component Design Temperatu r e ( F) Design Pressure (psig)

Maximum Test Pressure (psig) 5.2-43 Shutdown r e turn Recirculation header to second

isolation valve Piping 575 1575 (a) Valves 575 1575 (b) Reactor f e edwater Reactor ve s s el to man u al valve (F011) Piping 575 1300 (a) Valves 575 1300 (b) Reactor co r e iso l ation cooling system Steam to RCIC.

575 1250 (a) Pump turbine Reactor ve s s el to s eco n d isolation valve Piping 575 1250 (a) Valves 575 1250 (b) Pump discharge to reactor 170 1500 (a) Reactor ve s s el to s eco n d isolation valve Piping 575 1500 (a) Valves 575 1500 (b) High-pressure core spray system Outboard containment isolation valve to and including

maintenance valve insi d e containmen t c Piping 575 1250 (a) Valves 575 1250 (b)

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-6 Design Te m p erature, P r e ssure and Maximum Test

Pressure for RCPB Components (Continued)

Component Design Temperature ( F) Design Pressure (psig)

Maximum Test Pressure (psig) 5.2-44 From maintenance val v e to reactor ve ss e l Piping 575 1250 (a) Valves 575 1250 (b) Low-press u re core spray system Outboard i s olation valve to

reactor ve ss e l Piping 575 1250 (a) Valves 575 1250 (b) Standby liquid control Pump discharge to reactor vessel Reactor to second isolation valv e d Piping 150 1400 (a) Valves 150 1400 (b) Reactor water cleanup system Pump suction Recirculation piping t o 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.

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 Table 5.2-7 Reactor Coolant Pressure

Boundary Materials Component Form Material Specif i cati o n (ASTM/ASME)

LDC N-0 0-0 9 6 5.2-45 Reactor vessel Rolled plate Low a lloy steel SA-533 grade B class 1 Heads, shel l s Forgings Welds Low alloy s t eel SA-508 class 2

SFA-5.5 Closure flange Forged ring Welds Low alloy s t eel Low alloy s t eel SA-508 class 2

SFA-5.5 Nozzle safe ends Forgings or Pla t es Stainless steel SA-182, F304 or F316 SA-336, F8 or F8 M

SA-240, 304 or 316 Welds Stainless steel SFA-519, TP-308L or 316L Nozzle s a f e ends Forgings Welds Ni-Cr-Fe Ni-Cr-Fe SB-166 or S B-167 SFA-5.14, TP ERNiC r-3 or SFA-5.11, TP ENCrFe-3 Nozzle safe ends Forgings Carbon steel SA-105 grade 2, SFA-5.18 grade A, or

SFA-5.17 F 70 Nozzle s a f e ends Forgings Austenit i c stain l ess s t eel SA-182 grade F, 316L Cladding Weld overlay Austenitic stain l ess s t eel SFA-5.9 or SFA-5.4

TP-309 with carbon

content on final surface

limit to 0.09% maximum Control rod

drive housings Pipe Forgings Welds Austenit i c stain l ess s t eel Inconel SA-312 type 304

SFA-5.11 type ENiCrFe-3 or

SFA-5.14 type ERNiCr-3

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-7 Reactor Coolant Pressure Boundary Materi als (Continued)

Component Form Material Specification (ASTM/ASME) 5.2-46 In-core housings Pipe Forgings Welds Austenitic stainless steel

Inconel SA-312 type 304

SFA-5.11 type ENiCrFe-3 or

SFA-5.14 type ERNiCr-3

Additional RCPB component materi als and specifications to be used are specified below.

Depending on whether impact test s are required and depending on the lowest service metal temperature when impact tests are required, the following ferritic materials and specifications are used:

Pipe SA-106 grade B and C; SA-333 grade 5; SA-155 grade KCF 70

Valves SA-105 grade II-normalized; SA-350 grade LF1 or LF2 and SA-216 grade WCB, normalized; and SA-352 grade LCB

Fittings GA-105 grade II-normalized; SA-350 grade LF1 or LF2-normalized; SA-234 grade WPB-normalized; and SA-420 grade WPL1

Bolting SA-193 grade B7; and SA-194 grades 7 and 2H

Welding Material Welding materials conform to the applicable SFA specifications listed in ASME B&PV Code Section IIc. Individual selection of filter metals are reviewed for conformity to the ba se materials being welded by the

Consulting Engineers' review of welding procedures.

For those systems or portions of systems such as the reactor recirculation system, which require austenitic stainless steel, the following materials and specifications are used:

Pipe SA-376 type 304; SA-312 type 304; SA-358 type 304 Valves SA-182 grade F-304 and F-316; SA-351 grades CF-3, CF-3M, CF-8 and CF-8M

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-7 Reactor Coolant Pressure Boundary Mater i als (Continued)

5.2-47 Pump SA-182 grade F-304; SA-351 grades CF-8 and CF-8M

Flanges SA-182 grade F-316

Bolting SA-193 grade B7; SA-194 grades 7 and 2H Welding SFA-5.4 (E308-15, E308L-15, E316

-15); SFA-5.9 (ER-308, ER-308L, ER-316)

Fittings SA-182 grade F304; SA-351 grade CF-8; SA-4 03 grade W P-304, 304W

Table 5.2-8 Water Sample Locations C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-09-032 5.2-48 Sample Origin Sensor Location Indicator Location Recorder Location Range mho/cm Low Alarm High Reactor water recirculation loop Sample line Sample station Control room 0-1 0.0 1.0 Reactor water cleanup system inlet Sample line Sample station Control room 0-1 0.0 1.0 Reactor water cleanup system outlets Sample line Sample station Control room 0-0.3 NA 0.15

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-9 IHSI Summary Prior to First Refueling GL 88-01, Category B Welds

Energy Northwest ISI W e ld Number Welds 5.2-49 Stainless steel to s t ainless s t eel 24RRC(2)-A-2 thru 24RRC(2)-A-1 2 11 24RRC(1)-A-13 thru 24RRC(1)-A-22 10 16RRC(1)-A-1 thru 16RRC(1)-A-4 4

12RRC(1)-N2A-1, 1A 2 12RRC(1)-N2B-1, 1A 2 12RRC(1)-N2C-1, 1A 2 12RRC(1)-N2D-1, 1A 2 12RRC(1)-N2E-1, 1A 2 20RRC(6)-1 thru 20RRC(6)-7, 7A, 8 9

4RRC(8)-2A-1, 2 2 4RRC(8)-1A-1, 2 2 12RRC(7)-A-1 thru 12RRC(7)-A-6 6

12RHR(1)-A15 thru 12RHR(1)-A18 4

24RRC(2)-B-2 thru 24RRC(2)-B-10 9

16RRC(1)-B-1 thru 16RRC(1)-B-4 4

24RRC(1)-B-11 thru 24RRC(1)-B-20 10 12RRC(1)-N2F-1, 1A 2 12RRC(1)-N2G-1, 1A 2 12RRC(1)-N2H-1, 1A 2 12RRC(1)-N2J-1, 1A 2 12RRC(1)-N2K-1, 1A 2 4RRC(8)-2B-1, 2 2 4RRC(8)-1B-1, 2 2 12RRC(7)-B-1, 2, 2A thru 12RRC(7)-B-6 7

12RHR(1)-B-11 thru 12RHR(1)-B-13 3

20RHR(2)-1 1 Stainless steel to s t ainless s t eel caps 24RRC(1)-A13/8CAP-1, A20/12 C AP-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 C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-10

IHSI Summary During First Refueling GL 88-01, Category B Welds

Energy Northwest ISI W e ld Number Welds 5.2-50 4RRC(4) A-1 thru 4R R C (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 W e lds 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%.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Table 5.2-11 Main Steam Isola t ion Valves Material Information Item Material Spec Material Type Minimum Design Wall Thickness 5.2-51 Body SA-216 GR WCB 1.58 in. Bonnet SA-105 GR II 7.66 in. Stem disc a SA-105 N/A 1.56 in. Disc piston a SA-105 N/A 3.24 in. Ste m a SA-564 or A-182 Tp 630 H1100

GR F6A C1 3 Bonnet studs SA-540 Class 4 1-5/8 in. diameter Bonnet nuts SA-194 GR 7 1-5/8 in. diameter See Section 5.2.3.3 for fracture toughness response.

Piping connecting the MSIV

Outside diameter 12 in.

Nominal wall thickness =

1.103 in. plus 0.125 in.

a Redesign/replacement mater i als

Table 5.2-12 Summary of Isolation/Alarm of System Monitored and the Leak Detec tion Methods Used C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORTDecember 2011LDCN-11-005 5.2-52 Variable Monitored FUNCTION A A A A/I A/I A A/I A/I A/I A/I A/I A A Source of Leakage

Location High PC F PC Sump High Flow Rate High/PC Air Cooler Condensate Flow a Equip- ment Area High T and T Low Steam Line Pressure RB Sump or Drain High Flow Rate PC Pressure (High) High Flow Rate b RCIC Diaphragm High Exhaust Line Pressure RWCU Flow (High) Reactor Low Water Level High Differential Pressure Fission Products High a Main steam line PC X X X X c X X X X RB X X c X X X RHR PC X X X X X X RB X X X X RCIC steam PC X X X X X X X RB X X X X RCIC water PC X RB X RWCU water PC X X X X b X X X RB hot X X X X X RB cold X X X X Feedwater PC X X X X RB X d X ECCS water PC X X X RB X X Reactor coolant PC X X X X X X RB PC - Primary containment RB - Reactor building RWCU - Reactor water cleanup CCW - Closed cooling water

A - Alarm I - Isolation NOTE: a All systems within the drywell share a common detection system.

b Break downstream of flow element will isolate the system.

c In run mode only.

d Alarm only (steam tunnel).

Simulated Safety Relief Valve Spring Mode Characteristic used for Capacity Sizing Analysis1-2.564.096069 100 80 60 40 20 0 0.96 0.97 0.98 0.99 1.00 1.01 1.02 1.03 1.04 1.05"Opening" Path"Closing" PathCode Approved Capacity Pressure/Pressure Set Point Figure Amendment 53 November 1998Form No. 960690.veR.oN .warD Columbia Generating Station Final Safety Analysis Report Figure Amendment 60 December 2009 Form No. 960690 LDCN-08-035 Draw. No.Rev.950021.16 5.2-2 Columbia Generating Station Final Safety Analysis Report MSIV Closure with Flux Scram -

Nominal Safety Setpoint +3%

6 SRV Out-of-Service0.0100.0200.0 300.00.80.40.0Time (sec)% RatedDome Press Rise (psi)Safety Valve FlowRelief Valve FlowBypass Valve Flow-100.00.0100.0200.00.80.40.0Time (sec)% Rated Level(inch-REF-SEP-SKRT)Vessel Steam FlowTurbine Steam Flow F eedwater Flow-2.0-1.00.01.00.80.40.0Time (sec)Reactivity Components ($)

.Void ReactivityDoppler Reactivity Scram ReactivityTotal Reactivity0.050.0 100.0 150.00.80.40.0Time (sec)% RatedNeutron Flux / 10Avg Surface Heat FluxCore Inlet Flow

Peak Vessel Pressure Versus Safety Valve Capacity 960690.47 5.2-3 1400 1350 1300 1250(psig)40 60 80 100 120Safety Valve Capacity - % NB Rated Steam FlowNumber of Operating Safety Valves 8 10 12 14 16 18MSIV - Flux Scram (REDY)MSIV - Flux Scram (ODYN)

Code Limit(1375 psig)LR W/O BP (ODYN) 1200 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis ReportPeak Vessel Bottom Pressure (psig)

Time Response of Pressure Vessel forPressurization Events 960690.48 5.2-4 1350 1300 1250 120011501100 1050 MSIV Closure -

Flux Scram (ODYN)

MSIV Closure -

Flux Scram (REDY)

LR w/o BP Direct Scram Time (Sec)

Vessel Bottom Pressure (psig)(ODYN)2 4 6 8 10 12 14 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.2-5 22 02B22-04,26,1Nuclear Boiler System - P&IDRev.FigureDraw. No.

Safety/Relief Valve Schematic Elevation 960690.49 5.2-6 Drywell Main Steam LineReactor Vessel Main SteamIsolation ValvesSafety/Relief Valves Suppression Pool Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Flow Restrictor Columbia Generating StationFinal Safety Analysis Report Figure Form No. 960690 Amendment 53November 1998Draw. No.Rev.960690.62Safety/Relief Valve and Steam Line Schematic 5.2-7Reactor Vessel 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 S/R V S/R V S/R V S/R V Main Steam Lines Main Steam IsolationValves Drywell Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.960690.85Schematic of Safety Valve with Auxiliary Actuating Device 5.2-8Setpoint Adjust Screw Bonnet Spindle Balancing Piston Bellows Eductor Blowdown Adjusting Ring Eductor Sleeve Steam Flow Inlet Nozzle Ring Disc Disc Ring Disc Holder Piston-type Pneumatic Actuator AssemblySPVD Linear Variable Differential Transformer (LVDT)Valve Position Indication (VPI) LVDTSet Pressure Verification Device (SPVD) Pneumatic Head SPVD Load Cell"C""B""A" Solenoid/Air ControlValve Assemblies Discharge Nozzle Body Spring Lever Schematic of Crosby 6R10/8R10 Dual-Function Type Spring-Loaded Direct-Acting Safety/Relief Valve Columbia Generating StationFinal Safety Analysis Report FigureSafety Valve Lift Versus Time Characteristics 960690.50 5.2-9 0 50 100Time (Sec)

T 1 = Time at which pressure exceeds the valve set pressure T 1Safety Valve opening characteristicsValve achieves rated capacity at < 103% of set pressureSafety Valve Lift

(% of full open)ValveStroke Time

0.3 Amendment

53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Conductance Versus pH as a Function of ChlorideConcentration of Aqueous Solution at 25 C 960690.51 5.2-10 100 10 1 0.1 0.01 pH (at 25 C)4 5 6 7 8 9 10 Specific Conductance ( mho/cm at 25°C)

0.5 Chloride

(ppm)0.2 0.1 1 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Typical BWR Characteristic MSIV Closure Flux Scram 960690.525.2-11 Change in Initial Pressure (PSI)

Change in Peak Vessel Pressure (PSI) 20 15 10 5 0 0 10 20 30 40 50 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-000 5.3-1 5.3 REACTOR VESSEL

5.3.1 REACTOR

VESSEL MATERIALS

5.3.1.1 Materials Specifications

The materials used in the reactor pressure vessel and appurtena nces are shown in Table 5.2-7 together with the app licable specifications.

5.3.1.2 Special Processes Used for Manufacturing and Fabrication The reactor pressure vessel is primarily constructed from low alloy, high strength steel plate and forgings. Plates are or dered to ASME SA-533, Grade B, Class 1, and forgings to ASME SA-508, Class 2. These materials are me lted to fine grain practice and are supplied in the quenched and tempered conditio

n. Further restrictions incl ude a requirement for vacuum degassing to lower the hydrogen level and impr ove the cleanliness of the low alloy steels.

Studs, nuts, and washers for the main closure flange are ordered to ASME SA-540, Grade B23 or Grade B24. Welding electrodes are low hydrogen type ordered to ASME SFA 5.5.

All plate, forgings, and bolting are 100% u ltrasonically tested and surface examined by magnetic particle methods or li quid penetrant methods in acco rdance with ASME Section III Subsection Nuclear Boiler (NB) standards. Fr acture toughness propertie s are also measured and controlled in accordance with subsection NB requirements.

All fabrication of the reactor pressure vessel is performed in accordance with the General Electric Company (GE) approved dr awings, fabrication procedures , and test procedures. The shells and vessel heads are ma de from formed plates and the flanges and nozzles from forgings. Welding performed to join these vessel components is in accordance with procedures qualified per ASME Section III and IX requirements. Weld test samples are required for each procedure for major vessel full penetration welds.

Tensile and impact tests are performed to determine the properties of the base metal, heat-affected zone (HAZ) and weld metal.

Submerged arc and manual stick electrode welding processes are employed. Electroslag welding is not permitted. Preheat and interp ass temperatures employed for welding of low alloy steel meet or exceed the requirements of ASME Section III, Subsection NB. Postweld heat treatment at 1100°F minimum is a pplied to all low al loy steel welds.

Radiographic examination is performed on all pressure contai ning welds in accordance with requirements of ASME Section III, Subsection NB-5320. In addition, all welds are given a supplemental ultrasonic examination.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-005 5.3-2 The materials, fabrication procedures, and testing me thods used in the c onstruction of boiler water reactor (BWR) reactor pressure vessels meet or exceed requirements of ASME Section III, Class 1 vessels.

5.3.1.3 Special Methods for Nondestructive Examination

The materials and welds on the reactor pressu re vessel were examin ed in accordance with methods prescribed and met the acceptance requirements specified by ASME Boiler and Pressure Vessel (B&PV) Code Section III. In addition, the pressure retaining welds were ultrasonically examined using manual techni ques. The ultrasonic examination method, including calibration, instrument ation, scanning sensitivity, a nd coverage was based on the requirements imposed by ASME Co de Section XI in Appendix I. Acceptance standards were equivalent or more restrictive than required by ASME Code Section XI.

5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels

The degree of compliance with Regulatory Guides 1.31, 1.34, 1.43, 1.44, 1.50, 1.71, and 1.99 is described in Section 1.8.

5.3.1.5 Fracture Toughness

5.3.1.5.1 Compliance w ith Code Requirements

The ferritic pressure boundary mate rial of the reactor pressure vessels was qualified by impact testing in accordance with the 1971 edition of Section III ASME Code and Summer 1971 Addenda. From an operational standpoint, the minimum temperature limits for pressurization defined by the 1998 Edition of Section XI ASME Code and 2000 Addenda, Appendix G, Protection Against Nonductile Failu re, are used as the basis for compliance with ASME Code Section III.

5.3.1.5.2 Compliance with 10 CFR 50 Appendix G

A major condition necessary for full compliance to Appendix G was satisfaction of the

requirements of the Summer 1972 Addenda to Section III. This was not possible with components which were purchased to earlier Code requirements. For the extent of the compliance, see Table 5.3-1. Ferritic material complying w ith 10 CFR 50 Appendix G must ha ve both drop-weight tests and Charpy V-notch (CVN) tests with the CVN specimens oriented transverse to the maximum material working direct ion to establish the RTNDT. The CVN tests must be evaluated against both an absorbed energy and a lateral expansion criteria. The maximum acceptable RT NDT must be determined in accordance with the analytical procedures of ASME Code Section III, Appendix G. Appendix G of 10 CFR 50 requir es a minimum of 75 ft-lb upper shelf CVN

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-005 5.3-3 energy for beltline material. It also requires at least 45 ft-lb CVN energy and 25 mils lateral expansion for bolting material at the lower of the preload or lowest service temperature.

By comparison, material for the Columbia Generating Statio n (CGS) reactor vessels was qualified by either drop-weight tests or longitudinally oriented CVN tests (both not required), confirming that the material nil-ductility transi tion temperature (NDTT) is at least 60°F below the lowest service temperature. When the CVN test was app lied, a 30 ft-lb energy level was used in defining the NDTT. There was no upper shelf CVN energy requirement on the beltline material. The bolting material was qualified to a 30 ft-lb CVN energy requirement at 60°F below the minimum preload temperature.

From the previous comparison it can be seen that the fracture toughness testing performed on the CGS reactor vessel material cannot be shown to comply with 10 CFR 50 Appendix G.

However, to determine operating limits in accordance with 10 CFR 50 Appendix G, estimates of the beltline material RT NDT and the highest RT NDT of all other material were made and are discussed in Section 5.3.1.5.2.2. The method for developing these operating limits is also described therein.

On the basis of the last paragraph on page 19013 of the July 17, 1973, Federal Register, the following is considered an appr opriate method of compliance.

5.3.1.5.2.1 Intent of Proposed Approach. The intent of the prop osed special method of compliance with 10 CFR 50 Appendix G for this vessel is to provide operating limitations on pressure and temperature based on fracture tou ghness. These operating limits ensure that a margin of safety against a nonductile failure of this vessel is very nearly the same as that for a vessel built to the Summer 1972 Addenda.

The specific temperature limits for operation when the core is critical are based on 10 CFR 50 Appendix G, Paragr aph IV, A.2.C.

5.3.1.5.2.2 Operating Limits Based on Fracture Toughness. Operating limits which define minimum reactor vessel metal temperatures versus reactor pre ssure during normal heatup and cooldown and during inservice hydrostatic testi ng were established us ing the methods of Appendix G of Section XI of the ASME B&PV Code, 1998 Edition, 2000 Addenda. The results are shown in Figure 5.3-1.

All the vessel shell and head area s remote from discontinuities plus the feedwater nozzles were evaluated, and the operating limit curves are ba sed on the limiting location. The boltup limits for the flange and adjacent shell region ar e based on a minimum metal temperature of RT NDT +60°F. The maximum through-wall temperatur e gradient from continuous heating or cooling at 100°F/hr was considered. The safety factors applied were as specified in ASME Section XI Appendix G.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-005 5.3-4 For the purpose of setting these operating limits the reference temperature, RT NDT , is determined from the toughness te st data taken in accordance with requirements of the code to which this vessel is designed and manufactured. This tough ness test data, CVN and/or dropweight NDT, is analyzed to permit complian ce with the intent of 10 CFR 50 Appendix G.

Because all toughness tes ting needed for strict compliance with Appendix G was not required at the time of vessel procurement some toughne ss results are not available. For example, longitudinal CVNs, instead of transverse, were tested, usually at a single test temperature of +10°F or -20°F, for absorbed energy. Also, at the time either CVN or NDT testing was permitted; therefore, in many cases both tests were not performed as is currently required. To substitute for this absence of certain data, toughness property corr elations were derived for the vessel materials to operate on the available data to give a conservative estimate of RT NDT compliant with the intent of Appendix G criteria.

These toughness correlations vary , depending upon the specific ma terial analyzed, and were derived from the results of We lding Research Counc il (WRC) Bulletin 217, "Properties of Heavy Section Nuclear Reactor Steels," and from toughness data from the CGS vessel and other reactors. In the case of vessel plate material (SA-533 Grade 8, Class 1), the predicted limiting toughness property is either NDT or transverse CVN 50 ft-lb temperature minus 60°F. NDT values are available for CGS vessel shell plates. The transverse CVN 50 ft-lb transition temperature is estimated from longitudinal CV N data in the following manner. The lowest longitudinal CVN 50 ft-lb value is adjusted to derive a longitudinal CVN 50 ft-lb transition temperature by adding 2°F per ft-lb to the test temperature. If the actual data equals or exceeds 50 ft-lb, the test temperature is used. Once the longitudinal 50 ft-lb temperature is derived, an additional 30°F is added to account for orientati on effects and to estimate the transverse CVN 50 ft-lb temperature minus 60°F, estimated in the preceding manner.

Using the above general approach, an initial RT NDT of 28°F was established for the core beltline region.

For forgings (SA-508 Class 2), the predicted limiting property is the same as for vessel plates. CVN and NDT values are availabl e for the vessel flange, closure head flange, and feedwater nozzle materials for CGS. RT NDT is estimated in the same way as for vessel plate.

For the vessel weld metal th e predicted limiting property is the CVN 50 ft-lb transition temperature minus 60°F, as the NDT values are -50°F or lower for these materials. This temperature is derived in th e same way as for the vessel plate material, except the 30°F addition of orientation effects is omitted since there is no princi pal working direction. When NDT values are available, they are also considered and the RT NDT is taken as the higher of NDT or the 50 ft-lb temperat ure minus 60°F. When NDT is not available, the RTNDT shall not be less than -50°F, since lower values are not supported by the correlation data.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-005 5.3-5 For vessel weld HAZ material the RT NDT is assumed the same as for the base material as ASME Code weld procedure qualification test requirements, and postweld heat treatment indicates this assumption is valid.

Figure 5.3-2 provides a sketch of the reactor ve ssel, including the basic dimensions, all longitudinal and circumferential welds, and all pl ates of the beltline region.

Tables 5.3-2 through 5.3-7 contain the supporting information for Figure 5.3-2, such as piece mark, heat number, and impact data for th e plates and filler material used in the beltline region.

Closure bolting material (SA-540 Grade B24) t oughness test requirement s for CGS were for 30 ft-lb at 60°F below the boltup temperature.

Current code requirements are for 45 ft-lb and 25 mils lateral expansion at the preload or lowest service temperature, including boltup. All CGS closure stud materials meet current requirements at +10°F.

The effect of the main closure flange discontinuity was considered by adding 60°F to the RT NDT to establish the minimum temperature fo r boltup and pressurization. The minimum boltup temperature of 80°F for CGS, which is shown on Figure 5.3-1 , is based on an initial RT NDT of +20°F for the shell plate connec ting to the closure flange forgings.

The effect of the feedwa ter nozzle discontinuities were consid ered by adjusting the results of a BWR/6 reactor discontinuity analysis to the reactor. The ad justment was made by increasing the minimum temperatures required by the diffe rence between the CGS and BWR/6 feedwater nozzle forging RT NDT. The feedwater nozzle adju stment was based on an RT NDT of 0°F.

The reactor vessel closure studs have a minimum Charpy impact energy of 45 ft-lb and 26 mils lateral expansion at 10°F. The lowest service temperature for the closure studs is 10°F.

Vessel irradiation embrittlement of beltline materials, as measured by adjusted reference temperatures and upper shelf en ergies due to increased flux , was evaluated against the requirements of 10 CFR 50 Appendix G. For a predicted fluence of 7.41 x 10 17 n/cm 2 , fracture toughness values are acceptable and remain within Appendix G limits.

5.3.1.5.2.3 Temperature Limits for Boltup. A minimum temperature of 10°F is required for the closure studs. A sufficient number of studs may be tensioned at 70°F to seal the closure flange O-rings for the purpose of raising reactor water level above the clos ure flanges to assist in warming them. The flanges and adjacent shell are required to be warmed to a minimum temperature of 80°F before they are stressed by the full intended bolt preload. The fully preloaded boltup limits are shown in Figure 5.3-1.

5.3.1.5.2.4 Inservice Inspection Hy drostatic or Leak Pressure Tests. Based on 10 CFR 50 Appendix G, and Regulatory Guid e 1.99, Revision 2, requirements, pressure/temperature limit curves were estab lished based on an RT NDT of 28°F for the limiting beltline material; see Figure 5.3-1. The fracture toughness analysis for inse rvice inspection of le ak test resulted in

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-005,04-033 5.3-6 curve A shown in Figure 5.3-1. The predicted shift in the RT NDT temperature was determined using the methodology outlined in Regulatory Guide 1.99, Revision 2.

Technical Specification 3.10.1 allo ws inservice leak and hydrostatic testing to be performed in Mode 4 when the metallurgical characteristics of the reactor pressure vessel require testing at temperatures greater than 200

°F, given specified Mode 3 Limiting Conditions for Operations are met. This exemption is only applicable provided reactor coolant temperature does not exceed 275

°F.

5.3.1.5.2.5 Operating Li mits During Heatup, Cooldow n, and Core Operation. The fracture toughness analysis was done for the normal heat up or cooldown rate of 100°F/hr. The temperature gradients and thermal stress effects corresponding to th is rate were included. The results of the analysis ar e operating limits defined by Figure 5.3-1. Curves A, B, and C give the limits for hydrotest, nonnucl ear heating, and nuclear heating. The minimum boltup temperature of 80°F is based on an RT NDT at 20°F for a shell plate wh ich connects to the lower flange (Heat and Slab No. C-1307-2); above 80°F the core beltline plate (Heat and Slab No. C-1272-1), which has an initial RT NDT of 28°F, is most limiting for inservice hydrostatic or leak pressure tests (curve A). The feedwater nozzles, which have an RT NDT of 0°F, are more restrictive than the core beltline at lower pressures during nonnucl ear and nuclear heating (curves B and C).

5.3.1.5.2.6 Reactor Vessel Annealing. Inplace annealing of the reactor vessel to counteract radiation embrittlement is unnecessary because beltl ine material adjusted reference temperature of the NDT is well within the 10 CFR 50 Appendix G 200°F screening limit.

5.3.1.6 Material Surveillance

The materials surveillance progr am monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting from exposure to neutron irradiation and ther mal environment.

The CGS plant-specific RPV ma terials surveillance program is replaced by the NRC approved BWR Vessel and Internals Proj ect (BWRVIP) Integrated Su rveillance Program (ISP), as described in BWRVIP-86-A (Reference 5.3.4-2). The NRC approved the ISP for the industry in their safety evaluation dated February 1, 2002 (Reference 5.3.4-3). The ISP meets the requirements of 10 CF R 50, Appendix H.

The current surveillance capsule withdrawal schedule for the re presentative materials for the CGS vessel is based on the latest approved ve rsion of BWRVIP-86-A (Reference 5.3.4-2). No capsules from the CGS ve ssel are included in the ISP. Th e withdrawal of capsules for the CGS plant-specific surveillance program is perman ently deferred by participation in the ISP. Capsules from other plants will be remove d and tested in acco rdance with the ISP C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-005,04-033 5.3-7 implementation plan. The results from these tests will provide the necessary data to monitor embrittlement for the CGS vessel.

Materials for the plant-specific materials surveillance program were se lected to represent materials used in the reactor beltline region.

The specimens were manufactured from a plate actually used in the beltline region and a weld typi cal of those in the be ltline region and thus represent base metal, weld meta l, and the transition zone betw een base metal and weld. The plate and weld were heat treated in a manner which simulates the actual heat treatment performed on the core regi on shell plates of the comp leted vessel. WPPSS-ENT-089 (Reference 5.3.4-1) provides additional de tail and supporting inform ation for the materials surveillance program.

For the extent of compliance to 10 CFR 50 Appendix H, see Table 5.3-8. NEDO-21708 also addressed the requirements of Appendix H to 10 CFR 50 and supports the current application of Regulatory Guide 1.99.

5.3.1.6.1 Positioning of Surve illance Capsules and Method of Attachment for Plant-Specific Surveillance Program

Surveillance specimen capsules are located at three azimuths at a common elevation in the core beltline region. The sealed capsules are not atta ched to the vessel but are in welded capsule holders. The capsule holders are mechanically restrained by capsule holder brackets as shown in Figure 5.3-4. The capsule holder brackets allow the capsule holder to be removed at any desired time in the life of the plant for specimen testing. A positive spring-loaded locking device is provided to retain the capsules in pos ition throughout any anticipated event during the lifetime of the vessel.

The capsule holder brackets are designed, fabricat ed, and analyzed to th e requirements of the ASME B&PV Code Section III. The surveillance brackets are welded to the clad material which surfaces the pressure vessel walls. As attached , the brackets do not ha ve to comply with specifications of the ASME Code.

5.3.1.6.2 Time and Number of Dosimetry Measurements

General Electric provides a sepa rate neutron dosimeter so that fluence measurements may be made at the vessel ID during the first fuel cycle to verify the predicted fluence at an early date in plant operation. This measurement is made ov er this short period to avoid saturation of the dosimeters now available. Once the fluence-to-thermal power output is verified, no further dosimetry is considered necessary because of the linear relationship be tween fluence and power output.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-005 5.3-8 5.3.1.6.3 Neutron Flux a nd Fluence Calculations

A description of the methods of analysis for neutron flux and fl uence calculations is contained in Sections 4.1.4.5 and 4.3.2.8.

5.3.1.7 Reactor Vessel Fasteners

The reactor vessel closure head (flange) is fastened to the reactor vessel shell flange by multiple sets of threaded studs and nuts. The lower end of each stud is installed in a thread hole in its vessel shell flange. A nut and washer are installed on the upper end of each stud.

The proper amount of preload can be applied to the studs by sequential te nsioning using hydraulic tensioners. The design a nd analysis of this area of th e vessel is in full compliance with all Section III Class 1 Code requirements. The material for studs, nuts, and washers is SA-540, Grade B23 or B24.

The maximum reported ultimate te nsile stress for the bolting material was 167,000 psi whic h is less than the 170,000 psi limitation in Regulatory Guide 1.65. Also the Charpy impact test recommendations of Pa ragraph IV.A.4 of Appendix G to 10 CFR 50 were not specified in the vessel order since the order was placed prior to issuance of Appendix G to 10 CFR 50.

However, impact data from the certified materials report shows that all bolting material has met the Appendix G im pact properties. For example, the lowest reported CV N energy was 45 ft-lb at 10°F ve rsus the required 45 ft-lb at 70°F and the lowest reported CV N expansion was 26 mils at 10°F versus the required 25 mils at 70°F.

Hardness tests are performed on a ll main closure bolting to demonstrate that heat treatment has been properly performed. Studs, nuts, and washers are ultras onically examined in accordance with Section III, N8-2585 and the following additiona l requirements:

a. Examination is performed after heat treatment and pr ior to machining threads.

b. Straight beam examination is performed on 100% of each stud. Reference standard for the radial scan is 0.5-in. diameter flat bottom hole having a depth equal to 10% of the material thickness. For the end scan the reference standard is a 0.5-in. flat bottom hole having a dept h of 0.5 in. For additional details of the techniques used to examine the reactor vessel studs, s ee the response to Regulatory Guide 1.65, Revision 0, October 1973, in Section 1.8.

c. Nuts and washers are examined by angle beam from the outside circumference in both the axial and circ umferential directions.

There are no metal platings applied to closure studs, nuts, or washers. A phosphate coating is applied to threaded areas of studs and nuts and bearing areas of nuts and washers to act as a rust inhibitor and to assist in re taining lubricant on these surfaces.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-005 5.3-9 5.3.2 PRESSURE-TEMPERATURE LIMITS

5.3.2.1 Limit Curves

Limits on pressure and temperat ure for inservice leak and hydr ostatic tests, normal operation (including heatup and cool down), and reactor core operation are shown in Figure 5.3-1. The basis used to determine these limits is described in Section 5.3.1.5.

5.3.2.2 Operating Procedures

By comparison of the pressure versus temperature limits in Figure 5.3-1 with intended normal operating procedures for the most severe upset transient, it is shown that the limits will not be exceeded during any foreseeable upset condition.

Reactor operating procedures have been

established such that actual tran sients will not be more severe than those for which the vessel design adequacy has been demonstrated. Of the design transients, the upset condition producing the most adverse temp erature and pressure condition anywhere in the vessel head and/or shell areas has a minimu m fluid temperature of 250°F a nd a maximum pressure peak of 1180 psig. Scram automatically oc curs with initiation of this even t, prior to the reduction in fluid temperature, such that the applicable operating limits are bounded by curve A of Figure 5.3-1. Figure 5.3-1 show that at the maximum tran sient pressure of 1180 psig, the minimum allowable reactor ve ssel metal temperature conser vatively bounds the minimum 250°F reactor fluid temperature.

5.3.3 REACTOR

VESSEL INTEGRITY

The reactor vessel was fabricated for GE's Nuclear Energy Di vision by CBI Nuclear Co., and was subject to the requirements of GE's Quality Assurance program.

Assurance was made that measures were es tablished requiring that purchased material, equipment, and services associated with the reactor vessel and appurt enances conform to the requirements of the subject purchase documents. These measures included provisions, as appropriate, for source evalua tion and selection, objective ev idence of quality furnished, inspection at the vendor source, and examin ation of the comple ted reactor vessel.

Energy Northwest's agent provided inspection surveillance of the reactor vessel fabricators in process manufacturing, fabrication, and tes ting operations in accordan ce with GE's Quality Assurance program and approved inspection procedures. The reactor vessel fabricator was responsible for the first level in spection of manufactur ing, fabrication, and testing activities, and GE was responsible for the first level of audit a nd surveillance inspection.

Adequate documentary evidence that the reactor vessel material, manufacture, testing, and inspection conforms to the specified quality assurance re quirements contained in the procurement specification is available in plant records.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-033,05-021 5.3-10 5.3.3.1 Design

5.3.3.1.1 Description

5.3.3.1.1.1 Reactor Vessel. The reactor vessel shown in Figure 5.3-5 is a vertical, cylindrical pressure vessel of welded cons truction. The vessel is designed, fabricated, tested, inspected, and stamped in accordance with the ASME Code Section III, Cla ss 1, including the addenda in effect at the date of order pl acement. Design of the reactor ve ssel and its support system meets Seismic Category I equipment requirements. The materials used in the reactor pressure vessel are shown in Table 5.2-7.

The cylindrical shell and bottom head sections of the reactor vessel are fabricated of low alloy steel, the interior of which is clad with stainless steel weld overlay. Nozzle and nozzle weld zones are unclad except fo r those mating to stainless steel piping systems.

Inplace annealing of the reactor vessel is unnecessary because shifts in transition temperature caused by irradiation during the 40-year life can be accommodated by raising the minimum pressurization temperature. Radiation embrittle ment is not a problem outside of the vessel beltline region because the irradiation in those areas is less than 1 x 10 18 nvt with neutron energies in excess of 1 MeV.

The inside diameter and mini mum wall thickness of the reactor vessel beltline is provided in Table 5.3-9.

Quality control methods used dur ing the fabrication and assemb ly of the reactor vessel and appurtenances ensure that design specifications were met. The ve ssel top head is secured to the reactor vessel by studs and nuts. These nuts are tightened with a stud tensioner. The vessel flanges are sealed with two concentric metal seal rings de signed to permit no detectable leakage through the inner or outer seal at any operating condition, including heating to operating pressure and te mperature at a maximum rate of 100°F/hr in any 1-hr period. To detect seal failure, a vent tap is located between the two seal rings. A monitor line is attached to the tap to provide an indication of leakage from the inner seal ring seal.

5.3.3.1.1.2 Shroud Support. The shroud support is a circular plate welded to the vessel wall.

This support is designed to ca rry the weight of the shroud, shroud head, peripheral fuel elements, neutron sources, core plate, top guide, the steam separators, the jet pump diffusers, jet pump slip joint clamps, and to laterally support the fuel as semblies. Design of the shroud support also accounts for pressure differentials across the shroud support plate, for the restraining effect of component s attached to the support, and for earthquake loadings. The shroud support design is specified to m eet appropriate ASME Code stress limits.

5.3.3.1.1.3 Protec tion of Closure Studs. The BWR does not use borated water for reactivity control. This section is therefore not applicable.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.3-11 5.3.3.1.2 Safety Design Bases

Design of the reactor vessel a nd appurtenances meet the foll owing safety design bases:

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

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

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

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

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

5.3.3.1.3 Power Gene ration Design Basis

The design of the reactor vessel and appurte nances meets the following power generation design basis:

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

b. External and internal supports that ar e integral parts of the reactor vessel are located and designed so that stresses in the vessel and supports that result from reactions at these supports are within ASME Code limits, and

c. Design of the reactor vessel and appurte nances allow for a suitable program of inspection and surveillance.

5.3.3.1.4 Reactor Vessel Design Data

Reactor vessel design data are contained in Tables 5.2-6 and 5.2-7.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.3-12 5.3.3.1.4.1 Vessel Support. The concrete and steel vessel support pedestal is constructed as an integral part of the building foundation. Steel anchor bolts set in the concrete extend through the bearing plate and secure the flange of the reactor vessel support skirt to the bearing plate and thus to the support pedestal.

5.3.3.1.4.2 Contro l Rod Drive Housings. The control rod drive (C RD) housings are inserted through the CRD penetrations in the reactor vessel bottom head and are welded to the reactor vessel. Each housing transmits loads to the bottom h ead of the reactor. These loads include the weights of a control rod, a CRD, a CRD t ube, a four-lobed fuel s upport piece, and the four fuel assemblies that rest on the fuel support piece. The housings are fabricated of Type 304 austenitic stainless steel.

5.3.3.1.4.2.1 Control Rod Drive Return Line. To preclude CRD return line cracking on CGS, the return line was deleted and the system modified. The modification cons ists of adding pressure equalizing valves be tween the exhaust and cooling water headers and the use of reverse flow through multiple hydr aulic control unit (HCU) solenoi d valves as the CRD system exhaust flow path. The acceptance of this modification is based on system analyses and performance tests conducted on operating BWRs which have shown satisfactory system operation. The system tests showed that system pressure transients, CRD settling times, and CRD speeds were all unchanged. The tests also showed that all syst ems functions performed normally.

5.3.3.1.4.3 In-Core Neut ron Flux Monitor Housings. Each in-core neutron flux monitor housing is inserted through the in-core penetrati ons in the bottom head and is welded to the inner surface of the bottom head.

An in-core flux monitor guide t ube is welded to the top of each housing and either a source range monitor/intermediate range monitor drive unit or a local power range monitor is bolted to the seal/ring flange at the bottom of the housing.

5.3.3.1.4.4 Reactor Vessel Insulation. The insulation panels for the cylindrical shell of the vessel are self-supporting, with seis mic restraints attach ed to the sacrificia l shield wall. The insulation is designed to be re movable over those portions of the vessel where required for the purpose of in-service inspection.

5.3.3.1.4.5 Reactor Vessel Nozzles. All piping connecting to the reactor vessel nozzles has been designed so as not to exceed the allowable loads on any nozzle.

The vessel top head nozzle is provided with a flange with large groove facing. The drain

nozzle is of the full penetration weld design. The recirculation inlet nozzles (located as shown in Figure 5.3-5), feedwater inlet nozzles, core spray inlet nozzles, low-pressure coolant injection (LPCI) nozzles, and the CRD hydraulic system return nozzle all have thermal sleeves. Nozzles connecting to stainless steel piping have safe ends or extensions made of C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.3-13 stainless steel. These safe ends or extensions were welded to the nozzles after the pressure vessel was heat treated to avoid furnace sensitization of the stainless steel. The material used is compatible with the material of the mating pipe.

The nozzle for the standby liquid control (SLC) pipe was designed to minimize thermal shock effects on the reactor vessel in th e event of injection of cold SLC solution. However, the SLC injection pipe has been relocate d to a nozzle on the high-pressure core spray (HPCS) injection line and no longer uses the old nozzle in the bottom head of the reactor pressure vessel. The old nozzle is still in service as the connection for pressure sensing belo w the core plate, but there is no flow through the nozzle under any oper ating condition.

In the past, thermal fatigue cracking of feedwater nozzles and vibrational cracking of sparger arms have been observed at other operating BWRs. The mechanisms which have caused cracking in other operating BWRs are understood. A summary discussion of these problems and the solutions incorporated in the CGS design is presented in the following.

A detailed evaluation of the problems of the feedwater nozzle and spar ger is presented in NEDE-21821, "BWR Feedwater No zzle/ Sparger Final Report,"

March 1978. The solution of the feedwater nozzle and sparger cracking pr oblems involved severa l elements, including material selection and processing, nozzle clad elimination, and ther mal sleeve and sparger redesign. The following summarizes the problem s and solutions that have been implemented in the CGS design.

Problem Cause Fix Sparger arm cracks Vibration Eliminated clearance between thermal sleeve and safe end

RPV feedwater Thermal Eliminated clad, thermal fatigue eliminated leakage with a welded joint between the sparger and safe end The sparger vibration has been a ttributed to a self-excitation caused by instability of leakage flow through the annular clearance between the thermal sleeve and safe end. Tests have shown that the vibration is eliminated if the clearance is reduced sufficiently or sealed. The solution that was selected for CGS uses a welded joint to ensure no leakage. This feature is also an essential part of the solution of the nozzle cracking problem.

Freedom from vibration over a range of conditions has been demonstrated by the tests reported in NEDE-23604 (see Figures 5.3-6 and 5.3-7).

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-033 5.3-14 The cracking of the feedwater noz zles is a two-part process. The crack initiation mechanism as discussed above is the resu lt of self-initiated thermal cycling. If this were the only mechanism present, the cracks would initiate, grow to a depth of approximately 0.25 in., and arrest. This degree of cracking could be to lerated; however, there is another mechanism which supports crack growth. This mechanism is the system induced tr ansients, primarily the startup/shutdown transients. Because of CGS's welded thermal sleeve arrangement, leakage flow is eliminated and the heat transfer between the feedwater and the nozzle are reduced to the point where the thermal stresses in the nozzle are not high enough to cause a significant crack growth. Analyses presented in NEDE-21821, Section 4.7, demonstrated the benefits of the welded thermal sleeve and of using unclad nozzles. With these demonstrated benefits and inservice surveillance, CGS found it unnecessary to install instrumentation for design verification.

CGS has installed two automatic feedwater low flow control va lves, RFW-FCV-10A and 10B. These valves have the capacity to control flow down to 362 gpm, or about 1.25% of total flow.

This valve configuration will substantially reduce the temperature differential between the feedwater and the water in the RPV during low power operation, also reducing the thermal stresses in the nozzle.

5.3.3.1.4.6 Materials and Inspection. The reactor vessel was de signed and fabricated in accordance with the appropriate ASME B&PV Code as defined in Section 5.2.1.2. Table 5.2-7 defines the materials and specifications.

Table 5.3-8 defines the compliance with reactor vessel material surve illance program requirements.

5.3.3.1.4.7 Reactor Vessel Schematic (BWR). The reactor vessel sche matic is contained in Figure 5.3-3. Trip system water levels are indicated as shown.

5.3.3.2 Materials of Construction

All materials used in the construction of the reactor pressure ve ssel conform to the requirements of ASME Code Section II materials. The vessel heads, shells, flanges, and nozzles are fabricated from low alloy steel plate and forgings purchased in accordance with ASME specifications SA533 Grad e B Class 1 and SA-508 Class

2. Special requirements for the low alloy steel plate and forgings are discussed in Section 5.3.1.2. Cladding employed on the interior surfaces of the vessel consists of austenitic stainless steel weld overlay.

These materials of construction were selected because they provide adequate strength, fracture toughness, fabricability, and compatibility with the BWR environment.

Their suitability has been demonstrated by long-term successful operating experience in reactor service.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.3-15 5.3.3.3 Fabrication Methods The reactor pressure vessel is a vertical cyli ndrical pressure vessel of welded construction fabricated in accordance with ASME Code Section III, Class 1, requirements. All fabrication of the reactor pressure vessel was performed in accordance with buyer-approved drawings, fabrication procedures, and test procedures. The shells and vessel heads were made from formed low alloy steel plates and the flanges and no zzles from low alloy steel forgings.

Welding performed to join these vessel components was in accordance with procedures qualified per ASME Section III and IX requirements. Weld test samples were required for each procedure for major vesse l full penetration welds.

Submerged arc and manual stick electrode welding processes we re employed. Electroslag welding was not permitted. Preheat and interpass temperatures employed for welding of low alloy steel met or exceeded the requirements of ASME Section III, Subsection NB. Postweld heat treatment of 1100°F minimum was applied to all low alloy steel welds.

All previous BWR pressure vesse ls have employed sim ilar fabrication met hods. These vessels have operated for periods up to 16 years and their service history is excellent.

The vessel fabricator, CBI Nu clear Co., has had extensive experience with GE, reactor vessels, and has been the primary supplier for GE domestic reactor vesse ls and some foreign vessels since the company was formed in 1972 from a merger agreement between Chicago Bridge and Iron Co. and GE. Prior experience by the Chicago Bridge and Iron Co. with GE reactor vessels dates back to 1966.

5.3.3.4 Inspection Requirements

All plate, forgings, and bolti ng were 100% ultrasonically te sted and surface examined by magnetic particle methods or li quid penetrant methods in acco rdance with ASME Section III requirements. Welds on the reactor pressure vessel were examin ed in accordance with methods prescribed and met the acceptance requi rements specified by AS ME Section III. In addition, the pressure-retaining welds were ultrasonically examined usin g acceptance standards which were required by ASME Section XI.

5.3.3.5 Shipment and Installation

The completed reactor vessel was given a thorough cleaning and examination prior to shipment. The vessel wa s tightly sealed for shipment to pr event entry of dirt or moisture. Preparations for shipment were in accordance with de tailed written procedures. On arrival at the reactor site the reactor vessel was carefully examined for evidence of any contamination as a result of damage to shipping covers. Suitable measures were taken during installation to ensure that vessel integrity was maintained; for example, acces s controls were applied to C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.3-16 personnel entering the vessel, weather protec tion was provided, peri odic cleanings were performed, and only approved miscellaneous materials were us ed during assembly.

5.3.3.6 Operating Conditions

Restrictions on plant operation to hold thermal stresses within acceptable ranges are included in the Technical Specifications. These re strictions on coolant temperature are

a. The average rate of change of react or coolant temperatur e during normal heatup and cooldown,

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

c. Idle reactor recirculation loop a nd average reactor c oolant temperature differential.

The limit regarding the normal rate of heatup and cooldown (item a) as sures that the vessel closure, closure studs, vessel support skirt, and CRD housing and stub tube stresses and usage remain within acceptable limits. The vessel temperatur e limit on recirculating pump operation and power level increase restriction (item b) augments the it em a limit in further detail by ensuring that the vessel bottom head region will not be warmed at an ex cessive rate caused by rapid sweep out of cold coolant in the vessel lower head region by recirculating pump operation or natural circulation (cold coolant can accumulate as a result of control drive inleakage and/or low recirculati on flow rate during startup or hot standby). The item c limit further restricts operation of the recirculating pumps to avoid high thermal stress effects in the pumps and piping, while also minimizing thermal stresses on the vessel nozzles.

The above operational limits when maintained insu re that the stress limi ts within the reactor vessel and its components are with in the thermal limits to whic h the vessel was designed for normal operating conditions. To maintain the material integrity of the vess el in the event that these operational limits are exceeded the reactor vessel has also been designed to withstand a limited number of transients caused by operator error. Reactor vessel material integrity is also maintained during abnorm al operating conditions where safety systems or controls provide an automatic response in the reactor vessel. The special and transi ent events cons idered in the design of the vessel are discus sed or referenced in Section 5.2.2.

5.3.3.7 Inservice Surveillance

Inservice inspection of the reactor pressure vessel is in acco rdance with the requirements as discussed in Section 5.2.4. The vessel was examined once prior to startup to satisfy the preoperational requirements of IS-232 or the ASME Code, Secti on XI. Subsequent inservice C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-033 5.3-17 inspection will be scheduled and performed in accordance with the requirements of 10 CFR 50.55a subparagraph (g).

The materials surveillance progr am monitors changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region resulting fr om their exposure to neutron irradiation and thermal environment. See Section 5.3.1.6 for description of the materials surveillance program. Operating procedures will be modified in accordance with test results to ensure adequate brittl e fracture control.

Material surveillance programs and inservice inspection programs ar e in accordance with applicable ASME Code require ments and provide assurance th at brittle fracture control and pressure vessel integrity will be maintained throughout the service lifetime of the reactor pressure vessel.

5.

3.4 REFERENCES

5.3.4-1 WPPSS-ENT-089, "WNP-2 RPV Surv eillance Program," Current Revision.

5.3.4-2 BWRVIP-86-A, "BWR Vessel and Internals Project , Updated BWR Integrated Surveillance Program (ISP) Implementation Plan," Final Repor t, October 2002.

5.3.4-3 Letter from U.S. NRC to C. Terry (BWRVIP), "Safety Eval uation Regarding EPRI Proprietary Reports 'BWR Vess el and Internals Project, BWR Integrated Surveillance Program Plan (BWRVIP-78)' and 'BWRVIP-86: BWR Vessel and Internals Project, BWR Integrated Surveillance Program Implementation Pl an,'" dated February 1, 2002.

Table 5.3-1 10 CFR 50 Appendix G Matrix Appendix G Paragraph Topic Comply Yes/No or N/A Alternative Actions or Comments C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT N o v e mb e r 1998 5.3-19I, II Introduction; Definitions -- III.A Compliance with ASME Code, Section NB-2300 Yes See Section 5.3.1.5.2 for discussion. III.B.1 Location and Orientation of Impact Test Spec Yes See III.A above. III.B.2 Materials Used to Prepare Test Specimens No Compliance except for CVN orientation and CVN upper shelf. III.B.3 Calibration of Temperature Instruments and Charpy Test Machines No Paragraph NB-2360 of the ASME B&PV Code Section III was not in existence at the time of purchase of the CGS reactor pressure vessel. However, the requirements of the 1971 edition of the ASME B&PV Section III code, Summer 1971 addenda, were met. For the discussions of the GE interpretations of compliance and NRC acceptance see References 1 and 2. The temperature instruments and Charpy Test Machines calibration data are retained until the next recalibration. This is in accordance with Regulatory Guide 1.88, Revision 2, GE Alternative Position 1.88, and ANSI N45.2.9-1974.

Therefore, the instrument calibration data for CGS would not be currently available. III.B.4 Qualification of Testing Personnel No No written procedures were in existence as required by the regulation; however, the individuals were qualified by on-the-job training and past experience. For the discussion of the GE interpretation of compliance and NRC acceptance see References 1 and 2. III.B.5 Test Results Recording and Certif ication Yes See References 1 and 2. III.C.1 Test Conditions No See III.A, III.B.2 above.

Table 5.3-1 10 CFR 50 Appendix G Ma trix (Continued)

Appendix G Paragraph Topic Comply Yes/No or N/A Alternative Actions or Comments C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT A p ril 2000LDCN-99-086 5.3-20III.C.2 Materials Used to Prepare Test Specimens for Reactor Vessel Beltline Yes Compliance on base metal and weld metal tests. Test weld not made on same heat of base plate necessarily. IV.A.1 Acceptance Standard of Materials -- IV.A.2.a Calculates Stress Intensity Factor Yes IV.A.2.b Requirements for Nozzles, Flanges, and Shell Region Near Geometric Discontinuities No Plus 60 F was added to the RTNDT for the reactor vessel flanges. For feedwater nozzles the results of the BWR/6 analysis was adjusted to CGS RTNDT conditions. IV.A.2.c RPV Metal Temperature Requirement When Core is Critical Yes Comply with 10 CFR 50 Appendix G. IV.A.2.d Minimum Permissible Temperature During Hydro Test Yes IV.A.3 Materials for Piping, Pumps, and Valves No Main steam line piping is in compliance. See 5.2.3.3 for discussions on pumps and valves. IV.A.4 Materials for Bolting and Other Fasteners Yes Current toughness requirements for closure head studs are met at +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 -20F and +10F only. An estimate of compliance to requirements should be made from the first surveillance capsule results per MTEB 5-2.

Table 5.3-1 10 CFR 50 Appendix G Ma trix (Continued)

Appendix G Paragraph Topic Comply Yes/No or N/A Alternative Actions or Comments C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORTDecember 2005LDCN-04-005,04-033 5.3-21IV.B (continued)

Beltline plates were tested with longitudinal CVNs at +10

°F only. The minimum values are for Heat C1272-1 (0.15% Cu; 34, 26, 30, 31, 34, 30 ft-lb; 10 and 40% shear at +10

°F) and Heat C1273-1 (0.14% Cu; 33, 33, 30, 30, 34, 35 ft-lb; 10% shear at +10

°F). Beltline welds were tested with CVNs at 10

°F or -20°F only. Lowest weld values are found for Heat 04P046/Lot D217A27A (0.06% Cu; 34, 36, 37, 39, 40 ft-lb; 20 and 30% shear at -20

°F). Heat C3L46C/Lot J020A27A (0.02% Cu; 35, 39, 40 ft-lb; 60% shear at +10

°F) and Heat 05P018/Lot D211A27A (0.09% Cu; 29, 30, 31, 36, 38 ft-lb; 30 and 40% shear at -20

°F). Because of the preceding relatively low test temperatures and Cu contents, it is anticipated that end-of-life upper shelf CVN values would

be in excess of 50 ft-lb. IV.C Requirements for Annealing when RTndt >200 N/A V.A Requirements for Material Surveillance Program See Table 5.3-8 V.B Conditions for Continued Operation Yes Requirements for continued operations are covered in Technical Specifications and the Reactor Pressure Vessel Surveillance Program document (WPPSS-ENT-089, Reference 5.3.4-1). See Section 5.3.1.6 for description of the Materials Surveillance Program.

V.C Alternative if V.B Cannot be Satisfied N/A The Surveillance Program demonstrates compliance with Appendix G,Section IV. See Section 5.3.1.6 for description of the Materials Surveillance Program.

Table 5.3-1 10 CFR 50 Appendix G Matr ix for (Continued)

Appendix G Paragraph Topic Comply Yes/No or N/A Alternative Actions or Comments C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORTNovember 1998 5.3-22V.D Requirement for RPV Thermal Annealing if V.C Cannot be Met N/A V.E Reporting Requirements for V.C and V.D N/A REFERENCES

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

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

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 Table 5.3-2 Pla t e Ma t e r i al Cross R e f e rence Heat Slab 5.3-23 Ring 21 PCMK 21-1-1 C1272 1 PCMK 21-1-2 C1273 1 PCMK 21-1-3 C1273 2 PCMK 21-1-4 C1272 2 Ring 22 PCMK 22-1-1 B5301 1 PCMK 22-1-2 C1336 1 PCMK 22-1-3 C1337 1 PCMK 22-1-4 C1337 2

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 Table 5.3-3

Weld Mate rial Cross Reference

Weld Identification Type Heat Lot 5.3-24 AB - Girthweld E8018NM 492L4871 A422B27 A F RAC01N M M 5P6756 0342 RAC01N M M 3P4955 0342 E8018NM 04T931 A423B27 A G Ring 21 BA E8018NM 04P046 D217A27A E8018NM 07L669 K004 A 27A RAC01NMM 3P4966 1214 BB E8018NM 04P046 D217A27A E8018NM 07L669 K004 A 27A E8018NM C3L46C J020A27A RAC01NMM 3P4966 1214 E8018NM 08M365 G128 A 27A BC E8018NM 09L853 A111 A 27A 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 C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 Table 5.3-4 Pla t e Ma t e r i al Charpy Impact ft-lb @ +1 0 F Charpy Expansion MLE Drop Weight NDT ( F) R T NDT ( F) 5.3-25 Ring 21 PCMK 21-1-1

Heat C1272-1 34, 26, 30/31, 34, 30 30, 34, 24/27, 26, 32 10 28 PCMK 21-1-2

Heat C1273-1 33, 33, 30/30, 34, 35 30, 31, 27/26, 34, 32 20 20 PCMK 21-1-3

Heat C1273-2 38, 48, 55/66, 61, 71 44, 39, 34/53, 52, 56 30 4 PCMK 21-1-4

Heat C1272-2 40, 42, 44/51, 55, 50 32, 36, 38/41, 44, 42 30 0 Ring 22 PCMK 22-1-1

Heat B5301-1 64, 62, 66/52, 52, 55 56, 56, 56/45, 44, 44 30 20 PCMK 22-1-2

Heat C1336-1 70, 72, 71/60, 44, 66 59, 60, 62/56, 41, 51 30 8 PCMK 22-1-3

Heat C1337-1 71, 76, 74/70, 72, 55 61, 60, 60/63, 61, 52 30 20 PCMK 22-1-4

Heat C1337-2 62, 72, 82/73, 67, 73 51, 61, 66/52, 59, 61 50 20

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Table 5.3-5 Weld Material Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature

(°F) RT NDT (°F) LDCN-04-005 5.3-26 Girth Weld AB E8018NM/492L4871 Lot A422B27AF 78, 82, 105, 93, 81 55, 60, 72, 74, 60 20 a 50 RAC01NMM/5P6756 b Lot 0342 76, 79, 77, 80, 72 64, 72, 55, 69, 60 +10 50 RAC01NMM/5P6756 c Lot 0342 76, 79, 77, 80, 72 64, 72, 55, 69, 60 +10 50 RAC01NMM/3P4955 b Lot 0342 49, 63, 47, 49, 64 39, 48, 36, 43, 57 +10 20 RAC01NMM/3P4955 c Lot 0342 52, 37, 45, 55, 33 44, 30, 43, 50, 32 +10 16 E8018NM/04T931 Lot A423B27AG 86, 84, 102, 63, 61 69, 58, 60, 57, 70 20 50 Ring 21BA E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20 a 48 E8018NM/07L669 Lot K004A27A 50, 50, 54 44, 44, 46

+10 a 50 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10 a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10 a -48 Ring 21BB E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20 a 48 E8018NM/07L669 Lot K004A27A 50, 50, 54 44, 44, 46

+10 a 50 E8018NM/C3L46C Lot J020827A 35, 39, 40 34, 39, 39

+10 a 20 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Table 5.3-5 Weld Material (Continued)

Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature

(°F) RT NDT (°F) LDCN-04-005 5.3-27 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10 a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10 a 48 E8018NM/08M365 Lot G128A27A 49, 50, 51 38, 40, 43

+10 a 48 Ring 21BC E8018NM/09L853 Lot A111A27A 78, 78, 79 60, 62, 62

+10 a 50 E8018NM/C3L46C Lot J020A27A 35, 39, 40 34, 39, 39

+10 a 20 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10 a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10 a 48 Ring 21BD E8018NM/C3L46C Lot J020A27A 35, 39, 40 34, 39, 39

+10 a 20 RAC01NMM/3P4966 c Lot 1214/3482 40, 71, 75, 63, 59 41, 63, 68, 58, 53 +10 a 30 RAC01NMM/3P4966 b Lot 1214/3482 65, 70, 67, 69, 49 60, 60, 63, 55, 44 +10 a 48 E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20 a 48 Ring 22BE RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Table 5.3-5 Weld Material (Continued)

Type/Heat/Lot/Control Charpy Impact (ft-lb) Charpy Expansion MLE Charpy Test Temperature

(°F) RT NDT (°F) LDCN-04-005 5.3-28 Ring 22BF E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20 a 48 E8018NM/05P018 Lot D211A27A 29, 30, 31, 36, 38 26, 26, 31, 33, 35 20 a 38 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 Ring 22BG E8018NM/624063 Lot C228A27A 37, 40, 51, 57, 70 33, 34, 41, 47, 55 20 a 50 E8018NM/624039 Lot D224A27A 28, 33, 34, 36, 42 29, 32, 33, 34, 42 20 a 36 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 Ring 22BH E8018NM/04P046 Lot D217A27A 34, 36, 37, 39, 40 23, 28, 24, 20, 24 20 a 48 E8018NM/624039 Lot D205A27A 41, 44, 49, 54, 58 32, 36, 40, 41, 45 20 a 50 RAC01NMM/3P4966 c Lot 1214/3481 39, 38, 38, 82, 84 68, 64, 63, 81, 72 +10 20 RAC01NMM/3P4966 b Lot 1214/3481 28, 84, 63, 75, 78 18, 62, 57, 51, 57 +10 6 a Drop weight NDT not applicable.

b Tandem wire process.

c Single wire process.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Table 5.3-6 Vessel Beltline Plate Plate P Cu C Mn Si S Ni Mo V LDCN-04-005 5.3-29 C1272-1 0.013 0.15 0.23 1.31 0.26 0.02 0.60 0.55 -- C1272-2 0.013 0.15 0.23 1.31 0.26 0.02 0.60 0.55 -- C1273-1 0.014 0.14 0.23 1.28 0.23 0.0180.60 0.57 -- C1273-2 0.014 0.14 0.23 1.28 0.23 0.0180.60 0.57 -- B5301-1 0.017 0.13 0.20 1.34 0.23 0.0140.50 0.52 -- C1336-1 0.017 0.13 0.21 1.36 0.22 0.0130.50 0.49 -- C1337-1 0.018 0.15 0.22 1.32 0.21 0.0130.51 0.50 -- C1337-2 0.018 0.15 0.22 1.32 0.21 0.0130.51 0.50 --

Peak I.D. EOL (33.1 EF PY) fluence = 7.41 x 10 17 n/cm 2.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 Table 5.3-7 Vessel Beltline Weld Material Chemistry a Weld Heat/Control Cu C Mn Si S Ni Mo V P LDCN-08-023 5.3-30 492L4871 b 0.03 0.07 1.17 0.32 0.02 0.98 0.51 0.02 0.02 5P6756/0342 c 5P6756/0342 d 0.08 f 0.08 f 0.063 0.078 1.27 1.24 0.57 0.53 0.011 0.012 0.936 f 0.936 f 0.45 0.46 0.006 0.006 0.01 0.01 3P4955/0342 d 3P4955/0342 c 0.027 f 0.027 f 0.035 0.054 1.33 1.28 0.56 0.55 0.011 0.010 0.921 f 0.921 f 0.52 0.54 0.006 0.007 0.016 0.016 04T931 b 0.03 0.05 1.03 0.28 0.024 1.00 0.53 0.01 0.02 04P046 b 0.06 0.044 1.04 0.40 0.021 0.90 0.58 0.02 0.009 07L996 b 0.03 0.05 1.24 0.48 0.016 1.02 0.54 -- 0.014 3P4966/3481 d 3P4966/3481 c 0.025 f 0.025 f 0.074 0.067 1.38 1.39 0.36 0.38 0.013 0.014 0.913 f 0.913 f 0.49 0.53 0.006 0.008 0.010 0.011 3P4966/3482 c 3P4966/3482 d 0.025 f 0.025 f 0.059 0.077 1.35 1.42 0.38 0.41 0.013 0.013 0.913 f 0.913 f 0.50 0.53 0.005 0.005 0.013 0.014 CL46C b 0.02 0.063 0.96 0.32 0.017 0.87 0.53 -- 0.01908M365 b 0.02 0.057 1.23 0.47 0.023 1.10 0.57 -- 0.02 09L853 b 0.03 0.052 1.23 0.46 0.023 0.86 0.51 -- 0.018 05P018 b 0.09 0.057 1.21 0.44 0.021 0.90 0.53 0.01 0.008 624063 b 0.03 0.041 1.12 0.41 0.018 1.00 0.54 0.01 0.009 624039b,e 0.07 0.060 1.11 0.45 0.025 1.01 0.57 0.02 0.015 624039b,e 0.10 0.041 1.12 0.45 0.02 0.92 0.53 0.01 0.01 a As deposited.

b M = Manual Welding Process c S = Single Wire Process d T = Tandem Wire Process e Different lot numbers f GE Nuclear Energy, "Pressure-Temperature Curves for Energy Northwest Columbia,"

NEDC-33144-P (CVI CAL 1012-00,3), Table 4-6b.

Table 5.3-8 10 CFR 50 Appendix H Matrix Appendix H Paragraph Topic Comply Yes/No or N/A Alternative Actions or Comments I Introduction N/A II.A Fluence 10 17 n/cm 2 Yes CGS Plant-specific RPV Surveillance Program is replaced by the

BWRVIP ISP. See Section 5.3.1.6.

II.B Standards Requirements (ASTM) for Surveillance

No Plant-specific Surveillance Program: Noncompliance with ASTM E185-73 in that the surveillance specimens are not necessarily from the limiting beltline material. Specimens are from actual beltline material, however, and can be used to predict behavior of the limiting material. Heat and heat/lot numbers for surveillance specimens were supplied.

See Section 5.3.1.6.

II.C.1 Surveillance Specimen Shall be Taken for Locations Alongside the Fracture Test Specimens (Section III.B of Appendix G)

No Plant-specific Surveillance Program: Noncompliance in that specimens may not have necessarily been taken from alongside specimens required by Section III of Appendix G and transverse CVNs may not be employed. However, representative materials have been used, and

RTNDT shift appears to be independent of specimen orientation.

See Section 5.3.1.6.

II.C.2 Locations of Surveillance Capsules in RPV

Yes Code basis is used for attachment of brackets to vessel cladding.

II.C.3.a Withdrawal Schedule of Capsules, RTNDT <100°F N/A See Section 5.3.1.6. Starting RT NDT of limiting material is based on alternative action (see paragraph III.A of Appendix G).

II.C.3.b Withdrawal Schedule of Capsules, RTNDT <200°F N/A II.C.3.c Withdrawal Schedule of Capsules, RTNDT >200°F N/A C OLUMBIA G ENERATING S TATION Amendment59 F INAL S AFETY A NALYSIS R EPORTDecember 2007LDCN-06-000 5.3-31 Table 5.3-8 10 CFR 50 Appendix H Ma trix (Continued)

Appendix H Paragraph Topic Comply Yes/No or N/A Alternative Actions or Comments

III.A Fracture Toughness Testing Requirements of

Specimens

Yes Requirements for postirradiation testing of surveillance material are addressed in BWRVIP-86-A (Reference 5.3.4-2).

III.B Method of Determining Adjusted Reference

Temperature for Base Metal, HAZ, and Weld

Metal Yes Method of determining adjusted reference temperatures found in BWRVIP-86-A (Reference 5.3.4-2).

IV.A Reporting Requirements of Test Results

Yes Reporting requirements are discussed in BWRVIP-86-A (Reference 5.3.4-2).

IV.B Requirement for Dosimetry Measurement

Yes Dosimetry requirements are discussed in BWRVIP-86-A (Reference 5.3.4-2).

IV.C Reporting Requirements of Pressure/Temperature Limits Yes A discussion of the pressure/temperature limits and reporting requirements is found in BWRVIP-86-A (Reference 5.3.4-2). C OLUMBIA G ENERATING S TATION Amendment58 F INAL S AFETY A NALYSIS R EPORTDecember 2005LDCN-04-033 5.3-32 C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 Table 5.3-9 Reactor Vessel Beltline Minimum Wall Thickness and Diameter LDCN-04-005,04-033 5.3-33 Inside diameter with clad = 251 in. (minimum)

Wall thickness (ring #22, lo wer intermediate shell) = 6.188 in. (minimum)

Wall thickness (ring #2 1, lower shell)

= 9.5 in. (minimum)

Clad thickness

= 0.1875 in. (nominal)

= 0.125 in. (minimum)

Refer to Figure 5.3-2 and CVI 02B13-06,2 Rev.

8 (VPF #3133-001-9) CBI Nuclear Company Drawing No. 1, Rev. 8, "Vessel Outline."

900547.42 Columbia Generating Station Final Safety Analysis Report Pressure Temperature Limits Testing Curve A (Inservice Leak and Hydrostatic Testing Curve)Draw. No.Rev.Figure Amendment 58 December 2005 5.3-1.1 Form No. 960690FH LDCN-04-005 0 25 50 75 100 125 150 175 200MINIMUM REACTOR VESSEL METAL TEMPERATURE

( F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig) 1035 PSIG 88.6°F 800 PSIG 68°F 1035 PSI G117.1°F UPPER VESSELAND BELTLINE

LIMITSBOTTOM HEADCURVEACCEPTABLE AREA OFOPERATION TO THE RIGHT OF THIS CURVEBELTLINE CURVES ADJUSTED AS SHOWN:EFPY SHIFT (°F) 33.1 35INITIAL RTndt VALUES ARE28°F FOR BELTLINE, 34°F FOR UPPER VESSEL, AND34°F FOR BOTTOM HEADHEATUP/COOLDOWNRATE OF COOLANT FLANGE REGION 80°FBOTTOM HEAD 68°F 910 PSI G110°F 1400 1300 12001100 1000 900 800 700 600 500 400 300 200 100 0 990578.74 Columbia Generating StationFinal Safety Analysis ReportPressure Temperature Limits Curve B(Non-Nuclear Heating and Cooldown Curve)Draw. No.Rev.Figure Amendment 58December 2005 5.3-1.2 Form No. 960690FH LDCN-04-005 0 10 0 20 0 30 0 40 0 50 0 60 0 70 0 80 0 90 0 100 0 1 10 0 120 0 130 0 140 0 0 25 50 75 10 0 125 150 17 5 200225250MINIM UM RE AC T OR VE S SEL METAL TEM PERAT UR E (F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig)U PPER VESSEL A ND BELTLINELIMITSBOTTOM H EA D CURVE BELTLINE CUR VE S ADJUSTED AS S HOWN: EFPY SHIFT (F)33.1 35HEA TU P/COOLDOWNRATE OF CO OLANT< 10 0F/HR BOTTOMHEAD 68 FFL ANGERE GIO N 80 F A CC EP T ABLE AREA OF O PERATI ON TO THERIGHT OF THIS CURVE600 PS IG 68 F790 PSIG140 FINITIAL RT ndt VALU ES ARE 28F FOR BELTLINE,34F FOR U PPER VE S SEL, AND34F FOR BOTTOM HEAD1035 PSIG148.1 F10 35 PSIG109.3 F 0 25 50 75 100 125 150 175 200 225 250 275 300 900547.43 Columbia Generating Station Final Safety Analysis Report Pressure Temperature Limits Curve C (Nuclear Heating and Cooldown Curve)Draw. No.Rev.Figure Amendment 58 December 2005 5.3-1.3 Form No. 960690FH LDCN-04-005MINIMUM REACTOR VESSEL METAL TEMPERATURE

( F)PRESSURE LIMIT IN REACTOR VESSEL TOP HEAD (psig) 1035 PSIG 188.1 F 1400 1300 12001100 1000 900 800 700 600 500 400 300 200 100 0 BELTLINE ANDNON-BELTLINELIMITS BELTLINE CURVE ADJUS TED AS SHOWN: EFPY SHIFT ( F)33.1 35INITIAL RT ndt VALUESARE28F FOR BELTLI NE , 34F FO R U PPE R V ESSEL, AND34F F OR BOTTOM HEAD HEATUP/C OO LD OW N RATE OF C OOLANT < 100F/HR A CC EP T ABLE AREA OF O PERATI ON TO THERIGHT OF THIS CURVE 790 PSIG 180 F 60 PSIG Minimum CriticalityTemperature 80 F 312 PSIG Amendment 57December 2003 910402.30 5.3-2 Figure Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis ReportVessel Beltline Plate and Weld Seam Identification LDCN-02-064 PCMK 22-1-4 Heat C1337

Slab 2Weld "BG"Weld "BF" PCMK 22-1-2

Heat C1336

Slab 1Weld "BE"Girth Weld "AB"Weld "BH" PCMK 21-1-2

Heat C1273

Slab 1Weld "BC"Weld "BB" PCMK 21-1-3

Heat C1273

Slab 2Weld "BA"Weld "BD" PCMK 21-1-1

Heat C1272

Slab 1 PCMK 21-1-4

Heat C1272

Slab 2 PCMK 22-1-3 Heat C1337

Slab 1 PCMK 22-1-1

Heat B5301

Slab 1 251" dia.Ring #22 Ring #21405" Elev.360.31" TopCore Elev.230" Elev.99 13/16" Elev.

216.31" Bott.Core Elev.

0" Elevation EOL Limiting Plate

Nominal Reactor Vessel Water Level Trip and Alarm Elevation Settings 960690.53 5.3-3High Water Level Alarm, L7 = 568.0 in.Normal Water Level = 563.55 in.Low Water Level Alarm, L4 = 559.0 in.

Recirc Outlet Nozzle = 172.5 in.Top of Active Fuel Zone = 366.31 in.Bottom of Active Fuel Zone = 216.31 in.

Elevation 0.00 in.

Recirc. Inlet Nozzle = 181.0 in.Low Water Level, L1 = 398.5 in.

Steam Line Nozzle = 648.0 in.High Water LevelTrip, L8 = 582.0 in.Low Water Level Scram, L3 = 540.5 in.

Feedwater Nozzle = 493.25 in.Low Water Level, L2 = 477.5 in.

Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Bracket for Holding Surveillance Capsule 960690.54 5.3-4 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.-.00-C-11B.12Vessel Inside Clad Radius Full Penetration Weld (Typ.)

-B-.25.25Typ.C.50 Total118.31-.25.06.62 1.38.06.06.06 2.00.75.75 2.00.06.06 1.18.62 2.00.06.06+.25+.12 Columbia Generating StationFinal Safety Analysis Report Rev.Figure Draw. No.Form No. 960690 Amendment 53 November 1998 Columbia Generating Station Final Safety Analysis Report 020002.44 5.3-5 Reactor Vessel Feedwater Nozzle 960690.56 5.3-6 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Nozzle, SA-508, CI.II Safe End, SB-166, Inconel Thermal Sleeve Extension, SB-166 Thermal Sleeve, SA-336, CI.F8 Inconel OverlayWeld Illustration Back-up Ring, SB-168 1 2 3 4 5 6 7 6 3/4" 1 4 5 3 7 6 7/8" 7/16" 1 1/8" 7 1/8" 9/16" 2 2 3/4"R 3 9/16"R Feedwater Sparger 960690.57 5.3-7 2 1 3 6" End BracketForged TeeTyp. for Weld Nozzle, SA-508, CI.IIForged Tee, 304S.S Sparger Header, 304S.S 1 2 3 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.4-1 5.4 COMPONENT AND SUBSYSTEM DESIGN Pumps and valves within the reactor coolant pressure boundary (RCPB) are described in Table 5.4-1.

5.4.1 REACTOR

RECIRCULATION PUMPS

5.4.1.1 Safety Design Bases The reactor recirculation system (RRC) has been designed to meet the following safety design bases: a. An adequate fuel barrier thermal margin shall be ensured during postulated transients,

b. A failure of piping inte grity shall not compromise the ability of the reactor vessel internals to provide a refloodable volume, and

c. The system shall mainta in pressure integrity duri ng adverse combinations of loadings and forces occurring during a bnormal, accident, and special event conditions.

5.4.1.2 Power Gene ration Design Bases

The RRC meets the following power generation design bases:

a. The system shall provide sufficient flow to remove heat from the fuel, and

b. System design shall minimize maintenance situations that would require core disassembly and fuel removal.

5.4.1.3 Description

The RRC consists of the two r ecirculation pump loops external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reacto r vessel jet pumps (see Figure 5.4-1

). Each external loop contains one hi gh-capacity variable-s peed motor-driven recirculation pump. The motor is powered by an adjustable speed driv e (ASD). The external loop also contains two motor-operated gate valves (for pump maintenance). Each pump

suction line contains a flow meas uring system. The recirculati on loops are part of the RCPB and are located inside the drywell structure. The jet pumps are reactor vessel internals. Their location and mechanical desi gn are discussed in Section 3.9.5. The important design and performance characteristics of the RRC is shown in Table 5.4-2.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 1-0 2 5 5.4-2 The head, flow, torque, net pos itive suction head (NPSH), BHP, and efficiency curves are shown in Figures 5.4-2 , 5.4-3 , and 5.4-4. Instrumentation and cont rol description is provided in Sections 7.6 and 7.7. The recirculation system pi ping and normally flooded secti on of the reactor vessel is periodically coated with a micros copic layer of noble metals. Th is coating serv es to create a catalytic layering of noble metals, platinum and rhodium, to reduce the hydrogen addition injection rate required to achie ve a low electrochemical corro sion potential (EC P). 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 hyd rogen injection rates.

The recirculated coolant consists of saturated water from the steam separators and dryers that have been subcooled by incoming feedwater.

This water passes down the annulus between the reactor vessel wall and the core shroud. A po rtion of the coolant flows from the vessel, through the two external recirc ulation loops, and beco mes the driving flow for the jet pumps.

Each of the two external recirc ulation loops discharg es high pressure flow into an external manifold from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remain ing portion of the coolant mixtur e in the annulus provides the driven flow for the jet pumps.

This flow enters the jet pump at suction inlets and is accelerated by the driving flow. The flows, both driving and driven, are mixed in the jet pump throat section and result in partial pressure recovery.

The balance of recovery is obtained in the jet pump diffusing suction (see Figure 5.4-5

). The adequacy of the to tal flow to the core is discussed in Section 4.4.

The allowable heatup rate for the recirculation pump casing is the same as the reactor vessel.

If one loop is shut down, the idle loop can be kept hot by leavi ng the loop valves open; this permits the reactor pressure plus the active jet pump head to cause reverse flow in the idle loop. When starting the pump in an idle recirc ulation loop with the other loop in operation, the operating loop flow will be verified to be less than 50% of rated loop flow within 15 minutes prior to pump start.

Because the removal of the reactor recirculation gate valve in ternals would re quire unloading the core, the objective of the valve trim design is to minimize the need for maintenance of the valve internals. The valves are provided with high quality backseats that permit renewal of stem packing while the system is full of water.

The 20-in. motor-operated gate valves provide pump and flow control valve (FCV) isolation during maintenance. The suction valve is capable of closing w ith up to 50 psi differential, while the discharge valve can clos e with up to 400 psi differential. Both valves are remote manually operated.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-3 The FCV is blocked open (seized in the full open position). This condition does not affect the pressure integrity or impact the transient duty cycle of the valve or allow the ball to break away from the shaft.

The required NPSH for the recirculation pumps and jet pumps is supplied by the subcooling provided by the feedwater flow. Accurate temperature detectors are provided in the recirculation lines. Steam dome temperature is provided through pressu re conversion. The difference between these two readings is a di rect measurement of the subcooling. If the subcooling falls below the time-delayed setpoint 10.7°F, the ASD system is reduced to minimum frequency 15 Hz (25% pump speed) on both of the RRC loops. Each loop has independent instrumentati on for cavitation protection.

When preparing for hydrostatic te sts, the nuclear system temperat ure must be raised above the vessel nil ductility transition (NDT) temperature lim it. The vessel is heat ed by core decay heat and/or by operating th e recirculation pumps.

Connections to the piping on the suction and discharge sides of the pumps provide a means to

flush and decontaminate the pum p and adjacent piping. The pi ping low point dr ain, designed for the connection of temporar y piping, is used during fl ushing or decontamination.

Each recirculation pump is driven by an adjustable speed motor and is equipped with a two-stage mechanical seal cart ridge. Each of the two seals in the package is subject to one-half the total pressure being sealed. Each seal is structurally capable of sealing full pressure for limited periods of operation. The two seals can be replaced without removing the motor from the pump. The pump shaft passes through a breakdown bushing in the pump casing to reduce leakage in the event of a gross failure of both shaft seals. The cavity temperature and pressure drop across each individual seal can be monitored.

Each recirculation pump motor is a vertical, solid-shaft, totally enclosed, air-water-cooled, induction motor. The combined rotating inertias of the recirculation pump and motor provide a slow coastdown of flow following loss of ASD-supplied power to the drive motors so that they are adequately cooled during the transient. This inertia requirement is met without a flywheel.

The ASD can vary the discharge flow of the pump proportionally to a reactor operator remote manually adjusted demand signal. The RRC GE-FANUC digital control scheme is described in Sections 7.6 and 7.7. The recirculation loop flow rate can be varied, within the expected flow range, in response to changes to system demand.

The design objective for the recirculation system equipment is to provide units that will not require removal from the system for rework or overhaul. Pump casing and valve bodies are designed for a 40-year life and are welded to the pipe.

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 LDCN-04-041 5.4-4 The pump drive motor, impeller, and wear rings ar e designed for as long a life as is practical. Pump mechanical seal parts and the valve packing have life expectancies which afford convenient replacement during the refueling outages.

The ASD system selected to drive the recirculation pump induction motor is a dual channel system. Two ASDs are provided, capable of 11,200 hp at 66 Hz per RRC loop. If one channel fails, the RRC loop flow capability must be reduced to the capability of a single channel ASD. The dual channel ASD system provides for high ava ilability of the ASD system. The ASD system is a solid-state frequency converter with overall high availability.

Sections 7.6 and 7.7 provide more detail of the system design.

The recirculation system piping is designed and constructed to meet the requirements of the applicable ASME and ANSI codes.

The RRC pressure boundary equipment is designe d as Seismic Category I equipment. The pump is assumed to be filled w ith water for the analysis. Vibr ation snubbers located at the top of the motor and at the bottom of the pump casing are designed to resist the horizontal reactions.

The recirculation piping, valves, and pumps ar e supported by hangers to avoid the use of piping expansion loops th at would be required if the pumps were anchored. In addition, the recirculation loops are provided with a system of restraints designed so that reaction forces associated with any split or ci rcumferential break do not jeopard ize drywell integrity. This restraint system provides adequate clearance for normal therma l expansion movement of the loop. The criteria for the protection agai nst the dynamic effects associated with a loss-of-coolant accident (LOCA) are contained in Section 3.6.

The recirculation system piping, valves, and pump casings are c overed with thermal insulation having a total maximum heat tr ansfer rate of 65 Btu/hr-ft 2 with the system at rated operating conditions. This heat loss includes losses through joints, laps , and other openings that may occur in normal application.

The insulation is primarily the al l-metal reflective type. It is prefabricated into components for field installation. Removable insulation is provided at various locations to permit periodic inspection of the equipment.

The residual heat removal (RHR) system can use the recirculation loop jet pumps to provide circulation through the reactor core. Operating restrictions limit RHR operation to regions where jet pump cavitation does not occur.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-5 5.4.1.3.1 Recirculation Syst em Cavitation Consideration Cavitation Coefficients

The recirculation pump, jet pump, and FCV were tested to determine their cavitation coefficients so that prolonged operati on in cavitating regime s can be avoided.

Equipment Damage Provisions Cavitation interlocks are provided for the recirculation pum p and jet pumps; since cavitation produces material damage afte r long-term operation and the damage potential decreases with an increase in water temperature, short periods of cavitation during a transient or accident are not a concern. However, long-te rm operation that might occur is of sufficient concern to call for inspections during the next refueling outage. Consequently , to avoid the need for such inspections, automatic interlocks are installed. Class 1E equipment is not necessary for power generation design requirements, so the automatic interlocks are non-Class 1E.

The consequences of cavitation would require inspection of the affected compone nt and repair or replacement if the inspection showed unacceptable damage. Consequently, cavitation could call for increased scheduled outag e time for inspection/repair aff ecting plant availability power generation design goals.

The ASD and its GE-FANUC digital control syst em is a non-safety-related system. The ASD and control system have alar m and protective systems and ar e provided with on-line video diagnostic displays at the main control room ope rating benchboard.

5.4.1.4 Safety Evaluation

Reactor recirculation system malfunctions that pose threats of damage to the fuel barrier are described and eval uated in Section 15.3. It is shown in Section 15.3 that none of the malfunctions result in significan t fuel damage. The RRC has sufficient flow coastdown characteristics to maintain fuel thermal margins during ab normal operational transients.

The core flooding capability of a jet pump design plant is discussed in detail in the emergency core cooling system (ECCS) docum ent submitted to the NRC (Reference 5.4-1). The ability to reflood the boiling water reactor (BWR) core to the top of the jet pumps is shown schematically in Figure 5.4-6 a nd is discussed in R e f e r e n c e 5.4-1.

Piping and pump design pressures for the RRC are based on peak steam pressure in the reactor dome, appropriate pump head allowances, and the elevation head above the lowest point in the recirculation loop. Piping and related equipment pressure part s are chosen in accordance with applicable codes. Use of the listed code design criteria ensure s that a system designed, built, C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-6 and operated within design limits has an extrem ely low probability of failure caused by any known failure mechanism.

Purchase specifications require that the recirculation pumps first critical speed shall not be less than 130% of operating speed. Calculation submittal was requi red and approved.

Purchase specifications require that integrity of the pum p case be maintained through all transients and that the pump remain operable through all normal and upset transients. The design of the motor bearings are required to be such that dynamic load capability at rated operating conditions is not exceed ed during the safe shutdown ear thquake (SSE). Calculation submittal was required of the vendor and has been received and approved by GE.

Pump overspeed occurs during the course of a LOCA due to blowdown through the broken loop's pump. Design studies determined that the overspeed was not sufficient to cause destruction of the motor; c onsequently no pump overspeed protection provision was made.

A failure modes effects analysis (FMEA) was performed on the bl ock valves. In addition, an analysis was made to determine the effect of block valve closure on recirculation pump coastdown. The analysis postulates that coincident with a recirculation pump trip, the block valves begin to close. It was concluded that any closure time greater than 1 minute will have no effect on coastdown times.

The consequences of an in advertent closure without a coincident pump trip is covered in the FMEA.

5.4.1.5 Inspection and Testing

Quality control methods we re used during fabrication and asse mbly of the RRC to ensure that design specifications were met.

Inspection and testing is carried out as described in Chapter 3. The reactor coolant system was thoroughly cl eaned and flushed before fuel was loaded initially.

During the preoperational test program, the RR C was hydrostatically tested at 125% reactor vessel design pressure. Preoperational tests on the RRC also included checking operation of the pumps, flow control system, and gate valves, and are discussed in Chapter 14.

During the startup test program, horizontal and vertical motions of the RRC piping and equipment were observed as described in Section 5.4.14.

5.4.2 STEAM

GENERATORS (Pressurized Water Reactor)

This is not applicab le to BWR plants.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-7 5.4.3 REACTOR COOLANT PIPING

The RCPB piping is di scussed in Sections 3.9.3.1 and 5.4.1. The recirculation loops are shown in Figures 5.4-1 and 5.4-7. The design characteristics are presented in Table 5.4-2. Avoidance of stress corrosion crack ing is discussed in Section 5.2.3.

5.4.4 MAIN STEAM LINE FLOW RESTRICTORS

5.4.4.1 Safety Design Bases

The main steam line flow restrictors were designed to

a. Limit the rate of vessel blowdown to 200 percent of the normal rated flow in the event of a steam line break outside c ontainment. This limits the reactor depressurization rate to a value which will ensure that the steam dryer and other reactor internal struct ures remain in place.

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

c. Limit the amount of radiological releas e outside of the drywell prior to main steam isolation valve (MSIV) closure, and

d. Provide trip signals for MSIV closure.

5.4.4.2 Description

A main steam line flow restrictor (see Figure 5.4-8) is provided for each of the four main steam lines. The restrictor is a complete assembly welded into the main steam line. It is located between the last main steam line safety/relief valve (SRV) and the inboard MSIV.

The restrictor limits the coolant blowdown rate from the reactor vessel in the event a main steam line break occurs outside the containment. The restrict or assembly consists of a venturi-type nozzle insert welded, in accordance with applicable code requirements, into the main steam line. The flow rest rictor is designed and fabricated in accordance with the ASME "Fluid Meters," 6th edition, 1977.

The flow restrictor has no moving parts. Its mechanical structure can withstand the velocities and forces associated with a main steam line break. The ma ximum differential pressure is conservatively assumed to be 1375 psi, the reactor vessel ASME Code limit pressure.

The ratio of venturi throat diameter to steam line inside diameter of approximately 0.55 results in a maximum pressure different ial (unrecovered pressure) of a bout 10 psig at 100% of rated

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 5.4-8 flow. This design limits the steam flow in a severed line to le ss than 200% rated flow, yet it results in negligible increase in steam moisture content during normal operation. The restrictor is also used to measure steam flow to initiate closure of the MSIVs when the steam flow exceeds preselected operational limits.

5.4.4.3 Safety Evaluation

A postulated guillotine break of one of the four main steam lines outside the containment results in mass loss from both ends of the break. The flow from the upst ream side is initially limited by the flow restrictor upstream of the inboard isolation valve. Flow from the downstream side is initially limited by the total area of the flow restrictors in the three unbroken lines. Subsequent closur e of the MSIVs further limits the flow when the valve area becomes less than the limiter area and finally terminates the mass loss when full closure is reached.

Analysis of the main steam break accident outside containment demonstrates that the radioactive materials released to the environs results in calculated doses that are in compliance with 10 CFR 50.67 and Regulat ory Guide 1.183 dose limits.

Tests on a scale model determined final design and performance characteristics of the flow restrictor. The characteristics include maximum flow rate of the restrictor corresponding to the accident conditions, unrecoverable losses under normal plant ope rating conditions, and discharge moisture level. The te sts showed that flow restriction at critical throat velocities is stable and predictable.

The steam flow restrictor is exposed to steam of 0.10% to 0.20%

moisture flowing at velocities approximately 150 ft/sec (steam piping I.D.) to 600 ft

/sec (steam restrictor throat).

The cast austenitic stainless steel (ASME SA351, or ASTM A351, Type CF8) was selected for the steam flow restrictor material because it has excellent resistance to erosion-corrosion in a high velocity steam atmosphere. The excellent performance of st ainless steel in high velocity steam appears to be due to its resistance to corrosion. A protective surface film forms on the stainless steel which prevents any surface attack and this film is not removed by the steam.

Hardness has no significant effect on erosion-corrosion. For example, hardened carbon steel or alloy steel will erode rapidl y in applications where soft stainless steel is unaffected.

Surface finish has a minor effect on erosion-corro sion. Experience shows that a machined or a ground surface is sufficiently smooth and th at no detrimental erosion will occur.

5.4.4.4 Inspection and Testing

Because the flow restrictor fo rms a permanent part of the ma in steam line piping and has no moving components, no test ing program is planned. Only ve ry slow erosion will occur with

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 5.4-9 time, and such a slight enlargement will have no sa fety significance. Stainless steel resistance to corrosion has been substantiated by turbine inspections at the Dresden Unit 1 facility, which have revealed no noticeable effects from erosion on the stainless steel nozzle partitions. The Dresden inlet velocities are about 300 ft/sec an d the exit velocities ar e 600 to 900 ft/sec.

However, calculations show that, even if the erosion rates are as high as 0.004 in. per year, after 40 years of operation the increase in restrictor choked flow rate would not exceed 5%. The impact on calculated accident radiological releases would be minimal.

5.4.5 MAIN STEAM LINE ISOLATION SYSTEM The MSIV leakage control system has been deactivated.

5.4.5.1 Safety Design Bases

The MSIVs, individually or collectively, shall

a. Close the main steam li nes within the time establis hed by design-basis accident analysis to limit the release of reactor coolant,

b. Close the main steam line s slowly enough that simultaneous closure of all steam lines will not induce transients that exceed the nuclear system design limits,

c. Close the main steam line when required despite single failure in either valve or in the associated controls, to provide a high level of reliability for the safety function,

d. Use separate energy sources as the motive force to clos e independently the redundant isolation valves in the individual steam lines,

e. Use local stored energy (compressed air and/or spri ngs) to close at least one isolation valve in each steam pipe line without relying on the continuity of any variety of electrical power to furnish the motive force to achieve closure,

f. Have capability to close the steam lines, either during or after seismic loadings, to ensure isolation if the nuclear system is breached, and

g. Have capability for testing during no rmal operating conditions to demonstrate that the valves will function.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-10 5.4.5.2 Description Two isolation valves are welded in a horizontal run of each of the four main steam pipes; one valve is as close as possible to the inside of the drywell a nd the other is just outside the primary containment.

Figure 5.4-9 shows an MSIV. Each is a 26-in. Y-patte rn, globe valve. Ra ted steam flow rate through each valve is 3.85 x 10 6 lb/hr. The main disc or poppet is attached to the lower end of the stem. Normal steam flow tends to close the valve, and higher inlet pressure tends to hold the valve closed. The bottom end of the valve stem closes a small pressure balancing hole in the poppet. When the hole is open, it acts as a pilot valve to relieve differential pressure forces on the poppet. Valve stem travel is suff icient to give flow ar eas past the wide open poppet approximately equal to the seat port area.

The poppet travels approximately 90% of the valve stem travel to close the main disc and approximately the last 10% of travel to close the pilot hole. The air cylinder can open the poppet with a maximum differential pressure of

200 psi across the isolation valv e in a direction that tends to hold the valve closed.

A 45-degree angle permits the inlet and outlet passages to be streamlined; this minimizes pressure drop during normal steam flow and help s prevent debris blockage. The pressure drop at 105% of rated flow is 7 psi maximum. Th e valve stem penetrates the valve bonnet through a stuffing box that has Grafoil packing. To help prevent leakage through the stem packing, the poppet backseats when th e valve is fully open.

Attached to the upper end of the stem is an air cylinder that ope ns and closes the valve and a hydraulic dashpot that controls its speed. The speed is adjusted by a valve in the hydraulic return line bypassing the dashpot piston. Valve closing time is adjustable to between 3 and 10 sec.

The air cylinder is supported on the valve bonnet by actuator suppor t and spring guide shafts.

Helical springs around the spring guide shafts maintain the valve in the closed position if air pressure is not available.

The valve is operated by pneuma tic pressure and by the action of compressed springs. The control unit is attached to the air cylinder. This unit contains three types of control valves that open and close the main valve and exercise it at slow speed. Remote manual switches in the control room enable the opera tor to operate the valves.

Operating air is supplied to the outboard valves from the plant air system and to the inboard valves from the containment instrument system (nitrogen). An air accumulator between the control valve and a check valve provides bac kup operating air. The outboard MSIVs will close on spring force or air cylinder pressure; the inboard valves require spring force and air pressure to close.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-11 Each valve is designed to acco mmodate saturated steam at plant operating conditions, with a moisture content of approxi mately 0.25%, an oxygen content of 30 ppm, and a hydrogen content of 4 ppm. The valves are furnished in conformance with a design pressure and temperature rating in excess of plant operati ng conditions to accommodate plant overpressure conditions.

In the worst case if the main steam line should rupture down stream of the valve, steam flow would quickly increase to 200% of rated flow. Further increase is prevented by the venturi flow restrictor inside the containment.

During approximately the first 75% of closing, the valve has little effect on flow reduction because the flow is choked by the venturi restrictor. After the valve is approximately 75% closed, flow is reduced as a function of the valve area versus travel characteristic.

The design objective for the valve is a minimum of 40-years service at the specified operating conditions. Operating cycles (excluding routine exercise cycles) are estimate d to be 100 cycles per year during the first year a nd 50 cycles per year thereafter.

In addition to minimum wall thic kness required by applicable code s, a corrosion allowance of 0.120-in. minimum is added to provide for 40 years of service.

Design specification ambient conditions for normal plant operation are 135°F normal temperature, 150°F maximum temperature, 100% hum idity, in a radiation field of 15 rad/hr gamma and 25 rad/hr neutron plus gamma, conti nuous for design life. The inside valves are not continuously exposed to maximum conditions, particularly during reactor shutdown, and valves outside the primary containment and sh ielding are in ambien t conditions that are considerably less severe.

The MSIVs are designed to close under accident environmental conditions of 340°F for 1 hr at drywell design pressure. In addition, they ar e designed to remain cl osed under the following postaccident environment conditions:

a. 340°F for an additional 2 hr at drywell design pressure of 45 psig maximum,

b. 320°F for an additional 3 hr at 45 psig maximum, c. 250°F for an additional 24 hr at 25 psig maximum, and d. 200°F during the next 1 00 days at 20 psig maximum.

To resist sufficiently the response motion from the SSE, the main steam line valve installations are designed as Seismic Categor y I equipment. The valve a ssembly is manufactured to withstand the SSE forces applied at the mass center of the exte nded mass of the valve operator, assuming the cylinder/spring opera tor is cantilevered from th e valve body and the valve is located in a horizontal run of pipe. The stre sses caused by horizontal and vertical seismic forces are assumed to act simu ltaneously. The stresses in the actuator supports caused by

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-12 seismic loads are combined with the stresses caused by other live and dead loads, including the operating loads. The allowable stress for this combination of loads is based on the allowable stress set forth in applicable codes. The parts of the MSIVs that constitute a process fluid pressure boundary are designed, fabricated, inspected, and tested as required by the ASME Code Section III.

5.4.5.3 Safety Evaluation

The analysis of a comp lete, sudden steam line break outside the containment is described in Chapter 15, "Accident Analyses." The shortest cl osing time (approximately 3 sec) of the MSIVs is also shown in Chapter 15 , to be satisfactory. The switches on the valves initiate reactor scram when specific conditions (extent of valve closure, number of pipe lines included, and reactor power level) are exceeded (see Section 7.2.1.1).

The ability of this 45-degree, Y-design globe valv e to close in a few sec onds after a steam line break, under conditions of high pressure differentials and flui d flows with fluid mixtures ranging from mostly steam to mostly water, ha s been demonstrated in a series of dynamic tests. A full-size, 20-in. valve was tested in a range of steam-water blowdown conditions simulating postulated accident conditions (Reference 5.4-2).

The following specified hydrosta tic, leakage, and stroking te sts, as a minimum, were performed by the valve ma nufacturer in shop tests:

a. To verify valve capability to close at settings between 3 and 10 sec,* each valve was tested at rated pres sure (1000 psig) and no flow. The valve was stroked several times, and the closing time recorded. The valve was closed by spring only and by the combination of air cylinder and springs. The closing time is slightly greater when closure is by springs only;

b. Leakage was measured with the valve seated and backseated. The specified maximum seat leakage, using cold water at design pressure, was 2 cm 3/hr/in. of nominal valve size. In addition, an ai r seat leakage test was conducted using 50 psi pressure upstream. Maximum permissible leakage was 0.1 scfh/in. of nominal valve size. There was no visible leakage from the stem packing at hydrostatic test pressure. The valv e stem was operated a minimum of three times from the closed position to the open position, and the packing leakage was zero by visual examination;

• Response time for full closure is set prior to plant operati on for 3 sec minimum, 5 sec maximum.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-13 c. Each valve was hydrostatic ally tested in accordance w ith the requirements of the applicable edition and adde nda of the ASME Code.

During valve fabrication, extensive nondestructive test s and examinations were conducted. Tests included radiographic, liquid penetran t, or magnetic particle examinations of castings, forgings, welds, hardfacings, and bolts; and

d. The spring guides and guiding of the sp ring seat member on support shafts and rigid attachment of the seat member ensure correct alignment of the actuating components. Binding of the valve poppet in the internal guides is prevented by making the poppet in the form of a cyli nder longer than its diameter and by applying stem force near the bottom of the poppet.

After the valves were installed in the nuclear system, each valve was test ed as discussed in Chapter 14.

Two isolation valves provide redundancy in each steam line so either can perform the isolation function, and either can be tested for leakage after the other is closed. The inside valve, the outside valve, and their respective c ontrol systems are separated physically.

Electrical equipment that is a ssociated with the isolation valv es and operates in an accident environment is limited to the wiring, solenoi d valves, and position switches on the isolation valves. The expected pressure and temperature transients following an accident are discussed in Chapter 15.

5.4.5.4 Inspection and Testing

The MSIVs can be functionally tested for ope rability during plant ope ration and refueling outage. The test provisions are listed below. During refu eling outage the MSIVs can be functionally tested, leak tested, and visually inspected.

The MSIVs can be tested and exercised indivi dually to the 90% open position, because the valves still pass rated steam flow when 90% open.

The MSIVs can also be tested and exercised indi vidually to the fully closed position if reactor power is reduced sufficiently to avoid scram fr om reactor overpressure or high flow through the steam line flow restrictors.

Leakage from the valv e stem packing will become suspect during reactor operation from measurements of leakage into th e drywell, or from observation or similar measurements in the steam tunnel.

The leak rate through the pipe line valve seats (pilot and poppet seats) can be measured accurately during shutdown by the pro cedure described in the following:

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-14 a. With the reactor at approximately 125°F and normal water level and decay heat being removed by the RHR system in th e shutdown cooling mode, all MSIVs are closed utilizing both spring force and air pressure on the operating cylinder;

b. Air from the instrument air system is introduced between the isolation valves at 25 to 26 psig. A pressure decay test or an air makeup test is used to determine combined inboard and outboard isolation valve seat leakage;

c. If combined inboard and outboard isol ation valve seat leakage is above the allowed leakage for a single isolation valve, the outboard isolation valve is then tested for seat leakage;

d. To leak-test the outboard isolation valves, the reactor vessel side of the inboard valves is pressurized to approximately the same pressure as the test pressure between the inboard and outboard valves using nitrogen gas or a hydrostatic head. A pressure decay or makeup leak test is then performed on the area between the isolation valves. This ensures essentially zero leakage through the inboard valves with test results indicating outboard va lve seat leakage. The volume between the closed valves is accurately known. Corrections for temperature variation during the test period are made to obtain the required

accuracy; and

e. At each refueling outage, the MSIVs are slow closed to verify the stem packing is not too tight. Also, the inboard MS IV containment instrument air (CIA) supply pressure boundary from the accumu lator check valve to the actuator is verified to not exceed the allowable leak rate.

Such a test and leakage measurement program ensure that the valves are operating correctly and that any leakage trend is detected.

During prestartup tests following an extensive shutdown, the valves will receive the same pressure boundary leakage or hydro tests (approximately 1000 psi) that are imposed in the primary system.

5.4.6 REACTOR

CORE ISOLATION COOLING SYSTEM

5.4.6.1 Design Bases

The reactor core isolation cooling (RCIC) system initiates the discharge of a specified constant flow into the reactor vessel over a specified pressure range with in a 30-sec time interval. The RCIC water discharge into the reactor vessel varies between a temperature of 40°F up to and

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-04-027 5.4-15 including a temperature of 140°F. The mixture of the RCIC water and the hot steam does the following:

a. Quenches the steam,

b. Removes reactor residual heat by reducing the heat level (enthalpy) due to the temperature differential between the steam and water, and

c. Replenishes reactor vessel inventory.

The RCIC system uses an elec trical power source of high reliability, which permits operation with either onsite power or offsite power.

The steam supply to the RCIC tu rbine is automatically isolat ed on detection of abnormal conditions in the RCIC system or in RCIC equipment areas. See Section 7.4.1.1.2. The RCIC system is not an ECCS nor an engineered safety feature (ESF) system and 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 tr ansients 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 cont ainment isolation valve arrangements are described in Section 6.2.

The RCIC system as noted in Table 3.2-1 is designed commensura te with the safety importance of the system and its equipment. Each componen t was individually tested to confirm compliance with system requirements. The system as a whole was tested during both the startup and preoperational phases of the plant to set a base mark for system reliability. To confirm that the system maintains this mark, functional and operability testing is performed at predetermined intervals throu ghout the life of the plant.

In addition to the automatic operational fe atures, provisions have been included for remote-manual startup, operation, and shutdown of the RCIC system, provided initiation or shutdown signals have not been act uated for startup and operation.

The RCIC system is physically located in a different quadrant of the reactor building and uses different divisional power (and se parate electrical routings) than the HPCS system. The system operates for the time intervals and the environmen tal conditions specified in Section 3.11.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-16 5.4.6.2 System Design 5.4.6.2.1 General

5.4.6.2.1.1 Description. The RCIC system consists of a turbine, pump, piping, valves, accessories, and instrumentation designed to ensure that sufficient reactor water inventory is maintained in the reactor vessel to permit adequate core cooling.

This prevents reactor fuel overheating should the vessel be isolated and accompanied by loss-of-coolant flow from the reactor feedwater system.

Following a reactor shutdown, steam generation will continue at a reduced rate due to the core fission product decay heat. At this time the turbine bypass system will di vert the steam to the main condenser, and the feedwater system will supply the make up water required to maintain reactor vessel inventory.

In the event the reac tor vessel is isolated and the feedwater supply is un available, relief valves are provided to automatically (or remote manually) maintain vessel pressure within desirable limits. The water level in the reactor vessel will drop due to conti nued steam generation by decay heat.

On reaching a predetermined low level, the RCIC system is initiated automatically. The RCIC turbine is driven with a portion of the decay heat steam from th e reactor and exhausts to the suppression pool. The turbine-driven pump take s suction from the condensate storage tank (CST) during normal modes of ope ration and injects into the reactor vessel. Condensate storage tank freeze protecti on is discussed in Section

9.2.6. Since

the CST is a covered tank, the water supply is not affect ed by dust storms. If the water supply from the CST becomes exhausted there is an automatic switchover to the suppression pool as the water source for the RCIC pump. This automatic sw itchover feature for RCIC cons ists of two Class 1E level switches mounted on a standpipe in the pump suc tion line. This standpi pe is located on the condensate supply line inside the reactor build ing at the reactor building/service building interface.

The standpipe is open ended and is used to indicate either a low water level condition in the CST or a loss-of-suction supply from the CST.

The standpipe is desi gned, fabricated, and installed to Seismic Category I, Quality Class I, and ASME Se ction III, Class 2 standards.

The piping from the reactor building/service build ing interface to the RCIC system is Seismic Category I; each circumferential buttweld has been radiographically examined per ASME Section III, NC-5230, and a chemic al analysis has been performe d on all piping materials and as-deposited weld materials.

The inline suction reserve from the CST has sufficient volume to maintain the minimum required NPSH for the RCIC pump plus an ap proximate four-ft margin while the switchover

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-04-029 5.4-17 occurs, thus ensuring a water supply for continuous operation of the RC IC system. The CST

switchover level of 448 ft 3 in. pr ovides an additional submergen ce of 2 ft (above the top of the CST outlet pipe), which is more than ade quate to preclude vortex formation in the CST since less than 6 in. of add itional submergence for vortex pr evention is required for RCIC.

The available NPSH for worst-case operating conditions (i.e., 625 gpm rated flow, maximum water temperature) was calcula ted for the RCIC pump suction from the suppression pool and the CST. Using the conservative water temperat ure of 140°F, the NPSH available from the suppression pool is approximately 60 ft. For the CST, using 100°F water, the NPSH available is 48 ft. In both cases, the NPSH available is greater than the required NPSH of 20 ft indicated in Figure 5.4-10 for the RCIC turbine high speed setpoint of 4500 rpm.

The RCIC suction line from the su ppression pool has also been eval uated for vortex formation.

The RCIC system has adequate NPSH and will not vortex unde r the conditions it would be expected to operate.

During RCIC operation, the s uppression pool acts as the heat sink for steam generated by reactor decay heat. This will re sult in a rise in pool water temp erature. Heat exchangers in the RHR system are used to ma intain pool water temperature within acceptable limits by cooling the pool water directly.

The RCIC turbine discharges in to a 10-in. exhaust pipe (see Figure 5.4-11

), which has been installed as a sparger to prev ent flow-induced oscillations due to steam bubble formation and collapse in the suppression pool. Also, a vacuum breaker system has b een installed close to the RCIC turbine exhaust line suppression pool penetr ation to avoid siph oning water from the suppression pool into the exhaust line as steam in the line conde nses during and after turbine operation. The vacuum breaker line runs from the suppression pool air volume to the RCIC exhaust line through two norma lly open motor-operate d gate valves a nd two swing check valves arranged to allow air flow into the exhaust line and to precl ude steam flow to the suppression pool air volume. Condensate buildup in the turbine exhaust line is removed by a drain pot in the low point of the line near the turb ine exhaust connection. The condensate collected in the drain pot drains to the barometric condenser.

5.4.6.2.1.2 Diagrams. The following diagrams are included for the RCIC systems:

a. A schematic "Piping and Instrumentation Diagram" (Figures 5.4-11) shows all components, piping, points where interfa ce system and subsys tems tie together and instrumentation and controls associated with subsystem and component actuation,

b. A schematic "Process Diagram" (Figure 5.4-12) shows temperature, pressures, and flows for RCIC operation and system process data hydrau lic requirements, and C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-18 c. RCIC turbine and pump performance curves; Constant Pump Flow Figure 5.4-10 and Constant Pump Speed Figure 5.4-13.

5.4.6.2.1.3 Interlocks. The following defines the various electrical interlocks:

a. There are four key-locked valves, RCIC-V-63 (F063), RCIC-V-8 (F008), RCIC-V-68 (F068), and RCIC-V-69 (F069

), and two key-locked resets, the "isolation resets;"

b. RCIC-V-31 (F031) limit switch acti vates when fully open and closes RCIC-V-10 (F010), RCIC-V-22 (F022), and RCIC-V-59 (F059);

c. RCIC-V-68 (F068) limit switch activate s when fully open and clears RCIC-V-45 (F045) permissive so RC IC-V-45 (F045) can open;

d. RCIC-V-45 (F045) limit switch activate s when RCIC-V-45 (F045) is not fully closed and energizes 15-sec time delay fo r low pump suction pressure trip and also initiates startup ramp function. This ramp resets each time RCIC-V-45 (F045) is closed;

e. RCIC-V-45 (F045) limits switch activates when fully closed and permits RCIC-V-4 (F004), RCIC-V-5 (F005), RCIC-V-25 (F025), and RCIC-V-26 (F026) to open and closes RCIC-V-13 (F013), RCIC-V-46 (F046) and RCIC-V-19 (F019). RCIC-V-13 (F013) and RCIC-V-46 (F046) auto open on initiation signal if RCIC-V-45 (F045) and RCIC-V-1 (F001) are open;

f. The turbine trip throttle valve RCIC-V-1 limit switch activates when fully closed and closes RCIC-V-13 (F013), RCIC-V-46 (F046) and RCIC-V-19 (F019);

g. The combined pressure switches at reactor low pressure and high drywell pressure when activated closes RCIC-V-110 a nd 113 (F080 and F086);

h. RCIC high turbine exhaust pressure, low pump suction pressure, low discharge header pressure, or an isolation signal actuates and closes the turbine trip throttle valve. When signal is cleared, the trip throttle valve must be reset from control room;

i. 125% overspeed trips both th e mechanical trip at the tu rbine and the trip throttle valve. The former is reset at the turbine and then the la ter is reset in the control room; C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-19 j. Valves RCIC-V-8 (F008), RCIC-V-63 (F063), and RCIC-V-76 (F076) automatically isolate on low reactor pressure, high turbine e xhaust line pressure, high ambient temperature in RCIC equipment areas (leak de tection) and high turbine steam supply flow rate (>300% - break detection). A setpoint of 300%

for break isolation provides sufficient operating margin to prevent inadvertent isolations due to startup tr ansients and yet is low e nough to detect large pipe breaks. Small breaks are detected by the leak detection system. Steam condensing supply valv e RCIC-V-64 (F064) has been lo ck closed as a part of the steam condensing mode deactivation.

Note, the key-lo cked switches for RCIC-V-8 (F008) and RCIC-V-63 (F063) do not prevent automatic isolation of these valves. The key-locked switche s are provided to prevent inadvertent manual isolation of the RCIC steam supply during system operation;

k. An initiation signal opens RCIC-V-10 (F010) if closed, RCIC-V-45 (F045), and RCIC-V-46 (F046) if RCIC-V-1 and RC IC-V-45 (F045) are not closed. The initiation signal also starts barometric condenser vacuum pump; and closes RCIC-V-22 (F022) and RCIC-V-59 (F059) if open;

l. The combined signal of low flow plus high discharge pressure opens and with increased flow closes RCIC-V-19 (F 019). Also see items e and f above;

m. The signal of in-line reserve tank low water level opens valve RCIC-V-31 (F031);

n. High reactor water level closes RCIC-V-45 (F045); and

o. Main turbine trips if RCIC-V-13 and RCIC-V-45 are open.

5.4.6.2.2 Equipment and Component Description

5.4.6.2.2.1 Design Conditions. Operating parameters for the components of the RCIC systems defined in the following are shown in Figure 5.4-12.

a. One 100% capacity tu rbine and accessories, b. One 100% capacity pump a ssembly and accessories, and

c. Piping, valves, a nd instrumentation for

1. Steam supply to the turbine,

2. Turbine exhaust to the suppression pool, C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-20 3. Makeup supply from the CST to the pump suction, 4. Makeup supply from the suppre ssion pool to the pump suction, and

5. Pump discharge to the head cooling spray nozzle, incl uding a test line to the CST, a minimum flow bypass line to the suppression pool, and a coolant water supply to accessory equipment.

5.4.6.2.2.2 De sign Parameters. Design parameter for the RCIC system components are listed below. See Figure 5.4-11 for cross reference of com ponent numbers listed below:

a. RCIC pump operation RCIC-P-1 (C001) (Reference to Figures 5.4-11 and 5.4-13) Flow rate Injection flow - 600 gpm Lube oil cooling water flow 25 gpm

Total pump discharge - 625 gpm (includes no margin for pump wear) Water temperature range 40°F to 140°F NPSH 21 ft minimum Developed head 3016 ft @

1225 psia reactor pressure 610 ft @ 165 psia reactor pressure BHP, not to exceed 761 HP @ 3016 ft developed head 130 HP @ 610 ft developed head Design pressure 1500 psia Design temperature 40°F to 140°F

b. RCIC turbine operation RCIC-DT-1 (C002)

HP condition LP condition Reactor pressure (saturation temperature) 1225 psia 165 psia Steam inlet pressure 1210 psia 150 psia Turbine exhaust press 15 to 25 psia 15 to 25 psia Design inlet pressure 1265 ps ia + saturated temperature Design exhaust pressure 165 ps ia + saturated temperature

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-21 c. RCIC orifice sizing Coolant loop orifice Sized with piping arrangement to ensure RCIC-RO-9 (D009) maximum pressure of 75 psia at the lube oil cooler inlet and a minimum pressure of 45 psia at the spray nozzles at the barometric condenser

Minimum flow orifice Sized with piping arrangement to ensure RCIC-RO-5 (D005) minimum flow of 100 gpm with RCIC-V-19 (MO-F019) fully open

Test return orifice Sized with piping arrangement to simulate RCIC-RO-6 (D006) pump discharge pressure required when the RCIC system is injecting design flow with the reactor vessel pressure at 165 psia

Leak-off orifices Sized for 1/8-in. diameter minimum, RCIC-RO-8 and RCIC-RO-10 3/16-in. diameter maximum (D008 and D010)

Minimum flow orifice Sized to maintain a minimum flow of RCIC-RO-11 (D011) 60 gpm thro ugh the RCIC water leg pump (RCIC-P-3) while maintaining a positive pressure in the RCIC system at the highest elevation

d. Valve operation requirements NOTE: Differential pressures listed in the following were obtained from the RCIC system design specification data sheet and are listed for information. Detailed differential pressure requi rements are contained in engineering calculations.

Steam supply valve Open and/or close against full steam RCIC-V-45 (F045) pressure Pump discharge valve Open and/or close against full pump RCIC-V-13 (F013) discharge pre ssure and open in thermal over-pressure conditions in the RCIC

discharge header

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-22 Pump minimum flow bypass Open and/or close against full pump valve RCIC-V-19 (F019) discharge pressure

Steam supply isolation valves Open and/or close against full differential RCIC-V-08/RCIC-V-63 (F008) pressure of 1210 psi Turbine lube oil/cooling Capa ble of maintain ing constant water pressure control downs tream pressure of 75 psia valve RCIC-PCV-15 (F015) through lube oil cooler Pump discharge header relief 1500 ps ig relief setting; less than 1 gpm valve (RCIC-RV-3) required capacity; the maximum allowable discharge is less than 20 gpm

Pump suction relief valve 122 psig relief setting; 20 gpm required RCIC-RV-17 (F017) capacity

Cooling water relief Sized to prevent overpressurization of valve (RCIC-RV-19T) piping valves and equipment in the turbine lube oil coolant loop in the event of failure of pressure control valve RCIC-PCV-15 (F015). Set pressure is 99 psig; required flow is 33.1 gpm

Pump test return valve Qualifie d to open, close, and throttle RCIC-V-22 (F022) against full pump discharge pressure

Pump test return valve Qualified to close (not open) against full RCIC-V-59 (F059) pump discharge pressure

Relief valve barometric Relief valve is capable of retaining condenser vacuum tank 10 in. of mercury vacuum at 140

°F RCIC-RV-33 (F033) ambient, with a set pressure of 6 psig; required flow is 20 gpm Pump suction valve Located as close as practical to the suppression pool primary containment RCIC-V-31 (F031)

Pump suction valve Open and/or close against full suction condensate storage head from the condensate storage tank tank RCIC-V-10 (F010)

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-23 Main pump discharge System test mode bypasses this valve. check valve Its functional capability is demonstrated RCIC-V-65/RCIC-V-66 separately (F065/F066)

Warm-up line Valve will open and/or close against full isolation valve steam pressure

RCIC-V-76 (F076)

Vacuum breaker isolation Valves will open and/or close against valves RCIC-V-110 (F080) tu rbine exhaust pressure and RCIC-V-113 (F086)

e. Rupture disc

Assemblies Utilized for tu rbine casing protection, RCIC-RD-1/RCIC-RD-2 includes a mated vacuum support to (D001/D002) prevent rupture disc reversing under

vacuum conditions

Rupture pressure 150 psig +/- 10 psig Flow capacity 60,000 lb/hr @ 165 psig

f. Condensate storage requirements

Total reserve storage for reactor pr essure valve make up is 135,000 gal.

g. Piping RCIC water temperature

The maximum water temperature range fo r continuous system operation will not exceed 140°F. However, due to poten tial short-term operation at higher temperatures, piping de sign is based on 170°F.

h. Turbine exhaust vertical reaction force Unbalanced pressure due to opening and discharge under the suppression pool water level is 20 psi.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-24 i. Ambient conditions Relative Temperature Humidity Normal plant operations 60

°F to 100°F 95%

Isolation conditions 148°F 100% j. Water leg pump Design pressure 150 psig Design temperature 212°F Capacity 25 gpm @ 200 ft total head

k. Barometric condenser Design pressure 50 psig Design temperature 650°F l. Vacuum tank Design pressure 15 psig Design temperature 212°F m. Condensate pump Design pressure 50 psig Design temperature 650°F Capacity 23 gpm @ 10 in. Hg vac., 70°F 50 psig discharge

n. Turbine and steam supply drain pots Design pressure 1250 psig Design temperature 575°F o. Turbine governing a nd trip throttle valves Design pressure 1250 psig Design temperature 575°F Normal operating pressure 1210 psig Normal operating temperature 550°F

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 5 6 5.4-25 p. Pump suction strainers in the suppression pool The suction strainers have been procured to the following specifications:

Primary service rating: ANSI 1501-1

Quality Class I

Seismic Category I

Cleanliness Class B

Applicable Code: Strainer materi als and fabrication meets ASME Section III, Class 2 requi rements. The "N" stamp is not be applied sin ce the strainers cannot be hydrostatically tested. Materials: Strainer body is stainless steel 304 or 316, or engineer approved equal, suitable for submergence in high quality water during a 40-year lifetime.

Quantity: 2

Diameter: 13.5 in.

Length: 5.25 in.

Rated flow: 300 gpm (per strainer)

The strainers are cyli ndrical, as shown in Figure 5.4-14. Strainer hole diameter is 0.09375 in. Strainers are attached to ANSI 150# RF Flanges.

Head loss is limited to 4 ft of water assuming the strainers are 50% clogged and the water

temperature is 220°F.

5.4.6.2.2.3 Overpressure Protection. Referring to Figure 5.4-11, four RCIC pipe lines have a low design pressure and, ther efore, require relief devices or some other basis for addressing overpressure protection.

The design pressure of the other major pipe lin es is equal to the vessel design pressure and subject to the normal overpressure protection syst em. In addition, the RCIC discharge header

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 5 6 5.4-26 has a relief valve, RCIC-RV-3, to protect against thermal overpressurization when the system is in standby mode, isolated from the reactor.

Below are the overpressure protection ba ses for the low pressure piping lines.

a. RCIC pump suction line

A relief valve [RCIC-RV-17 (F017)] is located on the pump suction line in Figure 5.4-11 to accommodate any potential leakage through the isolation valves

[RCIC-V-13 (F013) and RCIC-V-66 (F066)]. A high pump suction pressure alarm is provided in the control room.

b. RCIC turbine exhaust line

This line is normally vented to the suppression pool and is not subject to reactor pressure during normal operation. Rupture discs RCIC-RD-1 (D001) and RCIC-RD-2 (D002), as shown in Figure 5.4-11, are installed on this line to prevent exceeding piping design pressure should the exhaust line isolation valve RCIC-V-68 (F068) be closed when the RC IC turbine is operating. The RCIC system will automatically isolate if the rupture discs were to blow open.

c. Portions of the RCIC minimum flow line downstream of RCIC-V-19 (F019)

This line is normally vent ed to the suppression pool and is separated from reactor pressure by the pump discharge isolation valves [RCIC-V-13, RCIC-V-65, and RCIC-V-66 (F013, F065, and F066)], pump discharge check valve RCIC-V-90, and one additional nor mally closed isolation valve in the minimum flow line [RCIC-V-19 (F019)] as shown in Figure 5.4-11.

d. Portions of the RCIC cooling water line downstr eam of RCIC-PCV-15 (F015)

In the standby condition this line is separated from r eactor pressure by the pump discharge valves [RCIC-V-13, RCIC-V

-65, and RCIC-V-66 (F013, F065 and F066)], pump discharge check valve RCIC-V-90, and one additional normally closed shut-off valve in the cooling water line [RCIC-V-46 (F046)] as shown in Figure 5.4-11. During system operation a reli ef valve [RCIC-RV-19T (F018)] is provided to prevent overpressurizing piping, valves, and equipment in the coolant loop in the event of failure of pressure control valve RCIC-PCV-15 (F015) as shown in Figure 5.4-11.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-04-027 5.4-27 5.4.6.2.3 Applicable C odes and Classifications

The RCIC system components within the drywell up to and including the outer isolation valve are designed in accordance with ASME Code Section III, Class 1, Nuclear Power Plant Components. Safety-related portions of the RCIC system are Seismic Category 1.

The RCIC system component classifications a nd those for the condensat e storage system are given in Table 3.2-1. 5.4.6.2.4 System Reliability Considerations

To ensure that the RCIC will operate when necess ary, the power supply for the system is taken from immediately available energy sources of hi gh reliability. Added assurance is given by the capability for periodic testing during station operation. Evaluation of reliability of the instrumentation for the RCIC shows that no failure of a single initiating sensor either prevents or falsely star ts the system.

To ensure RCIC availability for the operational events noted previously, the following are considered in the system design.

a. The RCIC and HPCS are located in differe nt quadrants of the reactor building.

Piping runs are separated and the water delivered from each system enters the reactor vessel via different nozzles.

b. Prime mover independence is achieved by using a steam turbine to drive the RCIC and an electric motor-driven pump for the HPCS system.

c. The RCIC and HPCS control independence is secured by using different battery systems to provide control power to each system for sy stem operation. Separate detection initiation logic is used for each system.

d. Both systems are designed to meet a ppropriate safety and quality class requirements. Environment in the equipment rooms is maintained by separate auxiliary systems.

e. A design flow functional test of the RCIC is performed during plant operation by taking suction from the CST and discharg ing through the full flow test return line back to the CST.

The discharge valve to the head-spray line remains closed during the test, and reactor operation is undisturbed. All components of the RCIC system are capable of individual functional testing during normal plant operation. Control system design provides automatic return from test to

operating mode if system initiation is required. The three exceptions are as follows:

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-04-027 5.4-28 1. The auto/manual station on the flow controller. This feature is required for operator flexibility during system operation.

2. Steam inboard/outboard isolation valves. Closur e of either or both of these valves requires operator action to properly sequence their opening. An alarm sounds when either of th ese valves leaves the fully open position.

3. Bypassed or other delib erately rendered inoperabl e parts of the system are automatically indicated in the control room.

f. Periodic inspections and maintenance of the turbine-pump unit are conducted in accordance with manufacturer's instructions. Valve position indication and instrumentation alarms are displayed in the control room.

g. Specific operating procedures relieve the possibility of thermal shock or water hammer to the steam line, valve seals, and discs. Key lock switches are provided for positive administrative control of valve position. Operating procedures require throttling open the outboard isolation valve RCIC-V-8 to

remove any condensate tra pped between the isolation valves, warming up the steam line by throttling open the warmup valve RCIC-V-76 located on a pipe line bypassing the inboard isolation va lve, and then opening the inboard isolation valve RCIC-V-63. All the condensate is removed from the steam supply line by a drain pot located at the lowest point. An alarm sounds when any of these valves leaves the fully open position.

h. Emergency procedures address the opera tion of RCIC during a station blackout (SBO) event. The RCIC keepfill pump, RCIC-P-3, is powered by a Class 1E ac source, and will be unavailable during an SBO. Upon loss of ac power, the operator manually initiates RCIC. RCIC may be used during an SBO event by maintaining the RCIC discharge header continuously pressurized. The system can be operated in th is manner without its keepfill function.

5.4.6.2.5 System Operation 5.4.6.2.5.1 Auto matic Operation. Automatic startup or restart (after level 8 shutdown) of the RCIC system due to an initiation signal from reactor low water level requires no operator action. To permit this automa tic operation, Technical Specifications operability requirements ensure that all necessary components are available to perfor m their required functions. In addition, the following are periodically verified:

a. The flow controller has the correct flow setpoint and is in automatic mode; C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-04-027 5.4-29 b. Each RCIC manual, power-operated, and automatic valv e in the flow path that is not locked, sealed, or otherwise secure d in position, is in the correct position; and

c. The RCIC system piping is filled with water from the pump discharge valve to the injection valve.

The turbine is equipped with a mechanical overspeed trip. The mechanical overspeed trip must be reset out of the control room at the turbine itself. Once the mechanical overspeed trip is reset, the trip throttle valve can be reset.

RCIC System Operation and Shutdown:

During extended periods of opera tion and when the normal water level is again reached, the HPCS system may be manually tripped and the RCIC system flow controller may be adjusted

and switched to manual operation. This prevents unnecessary cycling of the two systems. The RCIC flow to the vessel is controlled by adjus ting flow to the amount necessary to maintain vessel level. Subsequent starts of RCIC will occur automatically if the water leve l decreases to the low level initiation point (Le vel 2) following a high level shutdown (Level 8). Should RCIC flow be inadequate, HPCS flow will automatically initiate.

RCIC flow may be directed away from the vessel by diverting the pump discharge to the CST.

This is accomplished by closi ng injection valve RCIC-V-13 and opening the test return valves (RCIC-V-22 and 59). The system is returned to injection mode by closing RCIC-V-59 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 sw itches 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 supp ly relief valves and are shown on the RCIC and RHR piping and instrumentation diagrams (P&IDs) (Figures 5.4-11 and 5.4-15 , respectively). Deletion of this mode of operation for RCIC and RHR will not adversely affect either system's capability to bring the reactor to cold shutdown.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-08-000 5.4-30 5.4.6.2.5.4 Manual Actions. The RCIC system w ill automatically initiate and inj ect into the reactor when the reactor water level drops to a low level (L2, -50 in.). No manual actions are required to operate the system.

However, control room oper ators can manually initiate the system prior to reaching the low level.

5.4.6.2.5.5 Reactor Core Isolati on Cooling Discharge Line Fill System. See Section 6.3.2.2.5. The description in this section is also applicable to the RCIC line fill system. 5.4.6.3 Performance Evaluation

The RCIC system makeup capacity is sufficient to avoid th e need for ECCS for normal shutdowns and shutdowns resulting from anticipated operational occurrences.

5.4.6.4 Preoperational Testing

The preoperational and initial startup test program for the RC IC system is presented in Chapter 14. Regulatory Guide 1.68 complia nce is described in Section 1.8.

5.4.6.5 Safety Interfaces

The balance-of-plant/GE nuclear steam supply system safety inte rfaces for the RCIC system are (a) preferred water supply from the CST, (b) all associated wire, ca ble, piping, sensors, and valves that lie outside the nuclear steam supply system scope of supply, a nd (c) air supply for testable check and so lenoid-actuated valve(s).

5.4.7 RESIDUAL

HEAT REMOVAL SYSTEM

5.4.7.1 Design Bases

The RHR system is comprised of three inde pendent loops. Each loop contains its own motor-driven pump, piping, valv es, instrumentation, and contro ls. Each loop has a suction source from the suppression pool an d is capable of disc harging water to the reactor vessel via a separate nozzle, or back to th e suppression pool via a se parate suppressi on pool return line. In addition, the A and B loops have heat exchange rs which are cooled by standby service water.

Loops A and B can also take suction from the RRC suction and can discharge into the reactor recirculation discharge or to the suppression pool and drywell spray spargers. Spool-piece

interties are available to permit the RHR heat exchangers to be used to supplement the cooling capacity of the fuel pool coo ling (FPC) system (see Section 9.1.3 for details). A spool piece intertie was also used to provi de a preoperational flus hing path for the low-pressure core spray (LPCS). The A and B loops also have connections to the RCIC steam line. However, these are not used because the steam conde nsing mode has been eliminated.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009 5.4-31 5.4.7.1.1 Functional Design Basis

The RHR system is designed to restore and mainta in the coolant inventory in the reactor vessel and to provide primary system decay heat removal followi ng reactor shutdown for both normal and postaccident conditions. The primary desi gn operating modes associated with performing these functions are briefl y described as follows:

a. Low-pressure coolant injection (LPC I) mode - The RHR sy stem automatically initiates into this mode a nd pumps suppression pool water into separate lines and core flooder nozzles for injection into the core region of the reactor vessel following a LOCA. The system's LPCI mode operates in c onjunction with the other ECCS to provide ad equate core cooling fo r all design basis LOCA conditions.

The functional design bases for the LPCI mode is to pump a total of 7450 gpm of water per loop using the separate pump loops from the suppression pool into the core region of the vessel when there is a 26 psi differential between reactor pressure and the pressure of the suppression pool air volume. Injection flow commences at 225 psid vessel pressure above drywell pressure.

The initiating signals are ve ssel level 1, 32 in. above the active core or drywell pressure equal to 2.0 psig. The pumps will attain rated speed in 27 sec and injection valves fully open in 46 sec.

These original LPCI mode performance capabilities bound the power uprate conditions and ensure adequate core c ooling can be provided following a LOCA at uprated power conditions;

b. Suppression pool cooling (SPC) and containment spra y cooling (CSC) modes - The RHR system's SPC and CSC mode s provide heat removal from the suppression pool and containment by pumping suppression pool water through the system's heat exchangers and discharg ing the water either directly back to the suppression pool (i.e., in the SPC m ode) or discharging the water to the wetwell and drywell spray sp argers (i.e., in the CSC mode) where the water is then returned, by drainage, back to the suppression pool. These modes of operation are designed to provide cooling to maintain containment and suppression pool temperatures and pre ssures following ma jor transients. Suppression pool cooling is manually initiated by the ope rator; however, at least one RHR loop is placed in the SPC mode to maintain suppression pool temperature <

110°F. The drywell spray func tion removes radioactive fission products from the containment atmos phere during a LOCA and is manually initiated within 15 minutes after the event occurs; C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-32 c. Shutdown cooling mode - The RHR sy stem's normal shutdo wn cooling mode removes reactor core decay and sensible heat from the primary reactor system to permit refueling and servicing. This heat removal function is initiated manually after the reactor pressure has been reduced to less than 48 psig (295°F) by discharge of steam to the main condenser.

This mode of operation provides the capability to cool down the reactor under controlled conditions with minimal availability impact. Refer to Section 5.4.7.3.1 for shutdown cooling time to reach 212°F;

d. Alternate shutdown cooling mode - The RHR system's alternate shutdown cooling mode is utilized during normal plant operation and design basis events when the normal shutdown c ooling mode is not availabl e to remove reactor core decay and sensible heat. This heat removal function is safety related, initiated manually and pumps suppressi on pool water into the co re and allows the water to return to the suppression pool through the SRVs. The design objective of this mode (as established by Re gulatory Guide 1.139) is to reach cold shutdown within 36 hrs and to meet the requirements of GDC 34;

e. Fuel pool cooling mode - During normal plant shutdown, when the reactor vessel head has been remove d, the RHR system is designed to be capable of being aligned to assist th e FPC and cleanup system in maintaining the fuel pool temperature within acceptable limits. In this mode the system is designed to cool water drawn from the fuel pool by passing it through an RHR system heat

exchanger and then discharge th e water back to the fuel pool;

f. Minimum flow bypass mode - The RHR system minimum flow bypass mode is designed to provide cooling for the RHR pumps during a small break LOCA that does not result in rapid reactor ve ssel depressurization to below the RHR system shutoff discharge pr essure. This mode cool s the pumps by providing a pump flow return line to the suppre ssion pool that allows sufficient pump cooling flow to return to the pool until flow in the main discharge line is sufficient to provide adequa te pump cooling. When fl ow in the main discharge lines is sufficient for cooling of the pumps, motor-operated valves in the

minimum flow bypass line to the suppressi on pool automatically close so that all of the system's flow is directed into the main discharge lines;

g. Standby mode - During normal power operation the RHR system is required to be available for the LPCI mode in the event a LOCA occurs. The system is normally maintained in the standby mode. In this mode the system is aligned with the pumps' suction from the suppre ssion pool and all othe r valves aligned so that only the injection valves are required to open and the RHR pumps started for LPCI flow to be delivered to the reactor fo llowing depressurization.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-33 Until adequate flow is esta blished, the RHR pumps are cooled automatically by flow through the minimum flow valves;

h. Reactor steam condensing mode - The reactor steam condens ing mode has been deactivated and will no longer be utilized for CGS. No credit has been taken for the steam condensing mode in any safety analysis; and

i. The potential for exceeding the 100°F/

hr cooldown limit during the cooldown mode is minimized by precautions and limitations in the appropriate operating procedures.

5.4.7.1.2 Design Basis for Isolation of Residual Heat Removal System from Reactor Coolant System

Interlocks are provided to inhi bit shutdown cooling mode alignment whenever reactor pressure is above the design pressure of the low pressu re portions of the RHR system (approximately 135 psig).

The low pressure portions of the RHR system are isolated from full reactor pressure whenever the primary system pressure is above the RHR system design pr essure. The minimum pressure above which LPCI protection is required is below the design pr essure of the low pressure portions of the RHR system. These interlocks also provide protection of the low pressure portions of the RHR system. These interlocks ca n be reset when pressure has been reduced to approximately 135 psig. The LPCI injection valves are interlocked to prevent opening when reactor pressure is above appr oximately 460 psig, which also pr ovides protection for the low pressure portions of the RHR system. In add ition, automatic isolation may occur for reasons of vessel water inventory retention which is unrelated to piping pressure ratings. See Section 5.2.5 for an explanation of the leak dete ction system and the isolation signals.

The RHR pumps are protected against damage from a closed discharge valve by means of automatic minimum flow valves, which open when the main line flow is low and close when the main line flow is greater than the setpoint specified in the Technical Specifications.

5.4.7.1.3 Design Basis for Pressure Relief Capacity The relief valves in the RHR system are sized for one or both of the following bases:

a. Thermal relief, b. Valve bypass leakage

Relief valves are set to ensure that the design pressure pl us 10% accumulation is not exceeded anywhere in the system being protected. A check valve, RHR-V-209, is installed across

RHR-V-9 to prevent thermal overpressuri zation between RHR-V-8 and RHR-V-9.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-34 The relief valves protecting the RHR system are listed below (see Figure 5.4-15

):

Relief Valve Nominal Setpoint (psig) Required Capacity (gpm)

Piping Location Design Pressure (psig)

RHR-RV-88A 205 1 RHR pump suction 220 (loop A)

RHR-RV-88B 205 1 from suppression 220 (loop B)

RHR-RV-88C 110 1 pool 125 (loop C) RHR-RV-5 183 1 RHR pump suction from recirculation pipe 220 RHR-RV-25A 487 1 RHR discharge 500

RHR-RV-25B 488 1 RHR discharge 500

RHR-RV-25C 493 1 RHR discharge 500 RHR-RV-30 103 1 RHR flush line to radwaste 125 RHR-RV-36* All RHR relief valves are purchased to ASME S ection III, Class 2, requi rements to match the requirements of the piping they are protecting. As such, the setpoi nt tolerance is plus or minus 3% for setpoints above 70 psi per ASME Section III, Paragraph NC-7600.

Pressure buildups in isolated lines will be slow and discharges from relief valves on these lines will be small. Water hammer and other hydrodyna mic loads are not considered a potential problem in RHR relief valve piping.

Redundant interlocks prevent ope ning valves to the low-pressu re suction piping when the reactor pressure is above the shutdown range. These same interlocks initiate valve closure on increasing reactor pressure.

A pressure interlock prevents connecting the discharge piping to the primary system whenever the primary pressure is greater than the design value. In add ition a high-pressure check valve will close to prevent reverse fl ow if the pressure should increase. Relief valves in the discharge piping are sized to account for leakage past the check valve.

The RHR cooling system is connected to hi gher pressure piping at (a) shutdown cooling suction, (b) shutdown cooling return, (c) LPCI injection, and (d) head spray. The vulnerability to overpressurization of each location is discussed in the following paragraphs:

• RHR-RV-36 has been permanently removed from Columbia Generating Station. It has been replaced with a blind-flanged "Testable Pipe Spool Assembly," RHR-TPSA-1.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-35 The shutdown cooling suction pipi ng has two gate valves (RHR-V

-8 and RHR-V-9) in series which have independent pressure interlocks to prevent opening at high reactor pressure. No

single active failure or operator error will result in overpressuri zation of the lower pressure piping. With the RHR pumps normally lin ed up to the suppression pool (RHR-V-6A and RHR-V-6B closed), the shutdown cooling suction line is protected from thermal expansion or from leakage past RHR-V-8 by RHR-RV-5. A bypass around RHR-V-6A may also be used to route leakage past RHR-V-8 and RHR-V-9 to the suppression pool. With all the RHR suction

valves closed, the suction piping is protected from thermal expansion or leakage past the discharge check valves by RHR-RV-88A, RHR-RV-88B, and RHR-RV-88C. When the bypass around RHR-V-6A is not in service, it will be isolated usi ng a single valve. This will allow the installed relief valves discussed above to protect the bypass piping.

The shutdown cooling return line has swing check valves (RHR-V-50A and RHR-V-50B) to protect it from higher vessel pressures. Additionally, a gate valve (RHR-V-53A and RHR-V-53B) is located in series and has a pressure interlock to prevent opening at high reactor pressures. No single active fa ilure or operator error will result in overpressurization of the lower pressure piping.

Each LPCI injection line has a swing check valve (RHR-V-41A, RHR-V-41B, and RHR-V-41C) to protect it from higher vessel pressures. Additionally, a gate valve (RHR-V-42A, RHR-V-42B, and RHR-V-42C) is locate d in series and has pressure interlocks to prevent opening at high reactor vessel pressure. No single active failu re or operator error will result in overpressurization of the lower pressure piping.

The head spray piping ha s three swing check valv es in series [two belonging to the RCIC system and one (RHR-V-19) belonging to the RHR system], to protect it from higher vessel pressures. Two of the swing check valves ha ve air operators but ar e only capable of opening the testable check va lve if the differential pressure is less than 5.0 psid. Additionally, a globe valve (RHR-V-23) is located in series and has a pressure interlock to prevent opening at high reactor pressures. No single active failure or operator error will result in the overpressurization of the lower pressure piping.

Overpressurization protection of the RHR discharge piping for therma l expansion or from leakage past the head spray, shutdown injection, and LPCI isolation va lves is provided by RHR-RV-25A, RHR-RV-25B, and RHR-RV-25C.

The RHR drain system to radwaste is protected from thermal expansion or from leakage past the isolation valves RHR-V-71A, RHR-V-71B, RHR-V-71C, RHR-V-72A, RHR-V-72B, and RHR-V-72C by RHR-RV-30.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-36 5.4.7.1.4 Design Basis With Resp ect to General Design Criterion 5 The RHR system for this unit doe s not share equipment or struct ures with any other nuclear unit.

5.4.7.1.5 Design Basis for Reliability and Operability

The design basis for the shutdown cooling modes of the RHR system is that these modes are controlled by the operator from the control r oom. The operations performed outside of the control room using the normal shutdown is manual operation of a local flushing water admission valve, which is the means of ensuring that the suc tion line of the shutdown portions of the RHR system is filled and vented.

In addition, the 0.75-in. bypass around RHR-V-6A would be isolated if necessary.

Two modes of operation provide the shutdown cooling function for the RHR system. One mode, the normal Shutdown Cooling Mode, is the preferred operational mode. Although preferred, this mode of RHR does not meet the redundancy and single fa ilure requirements of IEEE 279 and 10 CFR 50 Appendix A, GDC 34.

As a result, a second shutdown cooling mode, the Alternate Shutdown Cooling Mode, is provided and is the shutdown cooling mode credited to meet the requirements of IEEE 279 a nd GDC 34. This mode is safety related, Quality Class 1, Seismic Cate gory 1, redundant and single failure proof. Since the normal Shutdown Cooling Mode of RHR is preferre d for CGS, the components required for the operation of this mode are maintained as safety related, Quality Class 1.

For the normal shutdown cooling mode, two separate shutdown cooling loops are provided.

The reactor coolant temperature can be brought to 212°F in less than 36 hr with only one loop in operation. With the exception of the shutdown suction including the reactor recirculation loop suction and discharge valves, and shutdown return, the entir e RHR system is safety grade and redundant, is part of the ECCS and containment cooling syst ems, and is designed with the flooding protection, piping protection, power separation, etc., requi red of such systems. See

Section 6.3 for an explanation of the design bases for ECCS systems.

Shutdown cooling suction and discharge valves are required to be powered from both offsite and standby emergency power for purposes of isolation and shutdown following a loss of offsite power. In the event that the outboard shutdown cooling suction supply valve (RHR-V-8) fails to open from the control room, an operator ma y be sent to open the valve by hand.

If the attempt to open the outboard valve proves unsuccessful, or the inboard shutdown cooling suction supply valve (RHR-V-9) fails to open, the operator will establish the alternate shutdown cooling mode path as described in the notes to Figure 15.2-10, Activity C1 or C2.

For the alternate shutdown cooli ng mode, if vessel depressuri zation were to be achieved by manual actuation of relief valves, three valves would need to be actuated to pass sufficient steam flow to depressurize the vessel.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-37 Low-pressure liquid flow test results are presented in NED E-24988-P. This test program adequately demonstrated the ability to use SR Vs in the alternate shutdown cooling mode.

Following reactor depressurization (i.e., 100°F/hr), an alternate shutdown coolant flow rate of 2600 gpm would be required to bring the reactor to a shutdown condition. This flow capacity can be achieved by using one AD S valve. However, three valves are always available.

Calculations demonstrate that in the alternate shutdown cooling mode, with one RHR pump in operation, the total system resist ance head is 550 ft using one SR V valve. At this calculated head, the pump capacity is 4000 gpm and the reactor pressure is 160 psig.

The air supply for the ADS valves is discussed in Sections 5.2.2 , 6.2.2 , and 7.3.1.

5.4.7.1.6 Design Basis for Prot ection from Physical Damage

The RHR system is designe d to the requirements of Table 3.2-1. With the exception of the common shutdown cooling line, redundant com ponents of the RHR system are physically located in different quadrants of the reactor building, and ar e supplied from independent and redundant electrical divisions. Further discussion on protecti on from physical damage is provided in Section 6.3.

5.4.7.2 Systems Design

5.4.7.2.1 System Diagrams

All of the components of the RHR system are shown in Figure 5.4-15. A description of the controls and instrumentati on is presented in Section 7.3.1.1.1.

A process diagram and pro cess data are shown in Figures 5.4-16 and 5.4-17. All of the sizing modes of the system are shown in the process data. The functional control diagram for the RHR system is shown in Figure 7.3-10.

Interlocks are provided (a) to prevent draining vessel water to the suppression pool, (b) to prevent opening vessel suction va lves above the suction line de sign pressure, or above the discharge line design pressure with the pum p operating at shutoff head, (c) to prevent inadvertent opening of drywell spray valves, and (d) to prevent pump start when suction valve(s) are not open. This interlock is defeated for the RHR FPC assist mode (see Section 9.1.3).

The RHR system may be used to supplement the cooling capacity of the FPC system. This mode requires the installation of spool pieces and the opening of normally locked closed valves (see Section 9.1.3.2 for details).

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-38 The normal shutdown cooling mode of RHR loop B can be aligned to return a portion of the cooling flow back into the reactor ve ssel via the RCIC head spray nozzle.

The LPCS system may be cross tied with the RHR system to prov ide a flow path from the CST to the LPCS system via RHR. This preoperational alignment provided clean water to the LPCS system during flushing and provided a flowpath to the vesse l for the core spray sparger test. This spoolpiece is not expected to be used again during the lifetime of the plant.

The administrative controls used for these spoolpieces, interlocks , and valves are procedurally regulated to ensure pr oper system function.

5.4.7.2.2 Equipment and Component Description

a. System main pumps The RHR main system pumps are mo tor-driven deepwell pumps with mechanical seals. The pumps are sized on the basis of the LPCI mode (modes A1 and A2, see Figure 5.4-17

). Design pressure for the pump suction structure is 220 psig with a temperatur e range from 40°F to 360°F. Design pressure for the pump discharge structur e is 500 psig. The bases for the design temperature and pressure are maximum shutdown cut-in pressures and temperature, minimum ambient temperature, and maximum shutoff head. The pump housing is carbon st eel and the shaft is stainless steel. System configuration (elevation, piping design, etc.) ensures that minimum pump NPSH

requirements are met with margin.

Figures 5.4-18 through 5.4-20 are the actual pump performance curves.

The RHR pumps are designed for the life of the plant (40 years) and tested for operability assurance and performance as follows:

1. In-shop tests, including: (a) hydrosta tic tests of pressu re retaining parts at 1.5 times the design pressure, (b) performance tests to determine the total developed head at zero flow and design flow, and (c) NPSH requirements.

2. After the pumps were installed in the plant, they underwent (a) the system hydro test, (b) fu nctional tests, (c) peri odic testing to verify operability in accordance with the Inservice Testing (IST) Program Plan, and (d) about 1 month of operation each year for a refueling shutdown (shutdown operation time has been re duced coincident with reduced outage times).

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-39 3. In addition, the pumps are designed for a postulated single operation of 3 to 6 months for one accident during the 40 year life of the plant.

A listing of GE operating e xperience of Ingersoll-Rand RHR pumps is provided in Tables 5.4-3 and 5.4-4. b. Heat exchangers The RHR system heat exchangers are sized on the basis of the duty for the shutdown cooling mode (mode E of the Process Data). All other uses of these exchangers require less cooling surface.

Flow rates are 7450 gpm (rated) on the sh ell side and 7400 gpm (rated) on the tube side (service water side). Rated inlet temperat ure is 95°F tube side.

Design temperature range of both shell a nd tube sides are 40°F to 480°F. The tube side water temperature may be as low as 32°F. The low temperature condition is acceptable, base d on compliance with the AS ME III, Class 2, code.

Design pressure is 500 psig on both side

s. Fouling allowances are 0.0005 shell side and 0.002 tube side.

The construction materials are carbon steel for the pressure vessel with stainless steel tubes and stainless steel clad tube sheet.

c. Valves All of the directional valves in the system are conventi onal gate, globe, and check valves designed for nuclear service.

The injection valv es, reactor coolant isolation valves, and pump minimum flow valves are high speed valves, as operation for LPCI injection or vessel isolation requires.

Valve pressure ratings are specified as necessary to provide the control or isolation function: i.e., all vessel isolation valves are rated as Class 1 nuclear va lves rated at the same pressure as the primary system.

The pump minimum flow valves (RHR-FCV

-64) open automatically at main line flows less than approximately 800 gpm. This allows flow to return to the suppression pool through the minimum flow bypass line, which branches off the main line upstream of the flow element. The minimum flow valve closes at main line flows greater than approximately 900 gpm and forces the entire pump discharge flow through the main line. The minimum flow valve controls meet IEEE-279 requirements.

To prevent loss of vessel inventory to the suppression pool when operating shutdown cooling or RHR/FP C assist mode, the mini mum flow valve is not

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-40 permitted to open. Administrative controls ensure that the valve is returned to normal status following the conclusion of shutdown cooling.

d. Restricting orifices The metering orifices in the discharge lines do not serve as restricting orifices.

The piping for each mode of RHR operation has been investigated to ensure that the resistance is low enough to allow the rated flows given in Figure 5.4-17 yet high enough to prevent pump runout. Restricting orifices are necessary in the system test lines to prevent excessive runout during SP C and test modes and in the main discharge line to prevent exces sive runout for LPCI. In addition, restriction orifices are installed ahead of the RHR-V-53A and RHR-V-53B valves to prevent excessive pump runout or valve cavitation during the

shutdown cooling mode.

Figure 5.4-15 indicates the loca tion of restricting orifices.

Additionally, two orifices are installed in the FPC system to minimize cavitation and limit flow when RHR is used to assist FPC.

e. ECCS portions of the RHR system The ECCS portions of the RHR system include those sectio ns described in Figure 5.4-16. The route includes suppression pool suction strainers, suction piping, RHR pumps, discharge piping, injection valv es, and drywell piping into the vessel nozzles and core region of the reactor vessel.

The SPC components include pool suction strainers, suction piping, pumps, heat exchangers, and pool return lines.

Containment spray components are the sa me as SPC except that the spray headers replace the pool return lines.

5.4.7.2.3 Controls and Instrumentation

Controls and instrumentation for the RHR system are described in Section 7.3. The RHR system relief valve capacities and settings are listed in Section 5.4.7.1.3.

5.4.7.2.4 Applicable C odes and Classifications

See Section 3.2.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-41 5.4.7.2.5 Reliability Considerations The RHR system has included the re dundancy requireme nts of Section 5.4.7.1.5. Two redundant loops have been provided to re move residual heat. With the exception of the common shutdown cooling line and the shutdown return valves (RHR-V-53A and RHR-V-53B) which are powered from the same division power source, all mechanical and electrical components are separate. Either loop is cap able of cooling down the reactor within a reasonable length of time.

5.4.7.2.6 Manual Action

RHR (shutdown cooling mode)

In the shutdown cooling mode of operation, when reactor vessel pressure is 48 psig or less, a service water pump is started a nd cooling water flow establishe d through a heat exchanger.

The RHR pump suction valve RHR-V-4A and/or RHR-V-4B is then closed and shutdown cooling isolation valves RH R-V-9 and RHR-V-8 opened. RHR pump suction valve RHR-V-6A and/or RHR-V-6B is then opened. Pump suction piping is prewarmed and provided a nominal flush by opening valves to radwaste. These effluent valv es to radwaste are then closed and the RHR pump is started. The cooldown rate is contro lled by adjusting the heat exchanger outlet valve and heat exchanger bypass valve to ach ieve the desired temperature of the water returning to the r eactor vessel while maintaining th e total flow at approximately 7450 gpm.

If prewarming valves were acci dentally left open following in itiation of shutdown cooling, reactor pressure vessel (RPV) coolant inventory would drain to radwaste. If loss of inventory remained undetected and makeup did not occur, isolation valves RHR-V-8 and RHR-V-9 would automatically close at the RPV scram leve l specified in the Tec hnical Specifications; depressurization or loss of water from the RHR system causes a low pressure alarm in the RHR discharge piping.

If the bypass around RHR-V-6A were inadvertently left open following the initiation of shutdown cooling using RHR loop B, the RP V coolant inventory would drain to the

suppression pool at a flow rate of 1 gpm or less.

If this loss of inventory remained undetected and makeup did not occur, RHR-V-8 and RHR-V-9 would auto matically close at the RPV scram level.

The manual actions required for the most limiting failure are discussed in Section 5.4.7.1.5.

5.4.7.3 Performance Evaluation

Thermal performance of the RHR heat exchangers is based on the capability to remove enough sensible and decay heat from th e reactor system to reduce the bulk reactor coolant temperature C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 5.4-42 to 125°F within 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> after control rod in sertion, with two RHR loops in operation.

Because cooldown is usually a controlled operation, maximum service water temperature less 10°F is used as the service water inlet temper ature. These are nominal design conditions; if the service water temperature is higher, the exchanger capabilities are reduced and the cooldown time may be longer or vice versa.

5.4.7.3.1 Shutdown Cooling W ith All Components Available

No typical curve is included here to show vessel cooldown temperatures versus time due to the infinite variety of such curves due to (a) clea n steam systems that use the main condenser as the heat sink when nuclear steam pressure is insufficien t to maintain steam air ejector performance, (b) the fouling of the heat exchangers, (c) opera tor use of one or two cooling loops, (d) coolant water temperature, and (e) sy stem flushing time. Si nce the exch angers are designed for the fouled condition with relatively high service water temper ature, the units have excess capability to cool when first used at high vessel temperatures. Total flow mix temperature is controlled to avoid exceeding 100°F/hr cooldown rate. See Figure 5.4-21 for minimum shutdown cooling time to reach 212°F.

5.4.7.3.2 Shutdown Cooling With Most Limiting Failure

Shutdown cooling under cond itions of the most limiting failure is discussed in Section 5.4.7.1.5. The capability of the heat exchanger for any time period is balanced against residual heat, pump heat, and sensible heat. The excess over re sidual heat and pump heat is used to reduce the sensible heat.

5.4.7.4 Preoperational Testing

The preoperational test program and startup test program were used to generate data to verify the operational capabilities of equipment in the system, such as ea ch instrument, setpoint, logic element, pump, heat exchanger, valve, and limit switch. In addition these programs verified the capabilities of the system to provide the flows, pressure s, cooldown rate s, and reaction times required to perform all syst em functions as spec ified for the system or component in the System Data Sheets and Process Data. Logic elements were tested electrically; valves, pumps, controllers, relief valves were tested mechanically; finally the system was tested for total system performance against the design requireme nts as specified above using both the offsite power and standby emergency power. Preliminar y heat exchanger performance was evaluated by operating in the pool cooling mode, but a ve ssel cooldown was used fo r the final check due to the small temperature differences available with pool cooling (see Section 14.2).

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December2005 5.4-43 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 includi ng the outermost containment is olation valve. The other portions of the system are not part of th e RCPB and are isolat ed from the reactor.

5.4.8.1 Design Bases

5.4.8.1.1 Safety Design Bases The RCPB portion of the RWCU system meets the requirements of Regulatory Guides 1.26 and 1.29 to

a. Prevent excessive loss of reactor coolant,

b. Prevent the release of radioactive material from the reactor,

c. Isolate the cleanup syst em from the RCPB, and

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

5.4.8.1.2 Power Gene ration Design Bases

The RWCU system

a. Removes solid and dissolved impurities from reactor coolant such that the water purity meets Regulatory Guide 1.56,

b. Discharges excess reactor water during startup, shutdown, and hot standby conditions,

c. Minimizes temperature gradients in the recirculation pi ping and vessel during periods when the main recircul ation pumps are unavailable, d. Minimizes cleanup sy stem heat loss, and

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

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.4-44 5.4.8.2 System Description The RWCU system (see Figures 5.4-22 and 5.4-23) continuously purifies reactor water during all modes of reactor operation. The system take s suction from the inle t of each reactor main recirculation pump and from the reactor pressure vessel bottom head. Processed water is returned to the reactor pressure vessel, to the main condenser, or radwaste.

The cleanup system can be opera ted at any time during planned operations, or it may be shut down. The cleanup system is classified as a primary power generation system. The cleanup system is not an engineered safety system.

Major equipment of the RWCU sy stem is located in the reacto r building. This equipment includes the pumps and the regenerative and nonregenerative heat exchangers. Filter-demineralizers and suppor ting equipment are located in the radwaste building. The entire system is connected by associated valves and piping; controls and instrumentation provide proper system operation.

Design data for the major pieces of equipment are presented in Table 5.4-5.

Reactor water is cooled in the regenerative and nonregenerativ e heat exchangers, filtered, demineralized, and returned to the reactor pr essure vessel through the shell side of the regenerative heat exchanger.

The system pump is capable of producing a nom inal flow of 181,300 lbm/hr. Two filter demineralizer units are used to process this quantity of water.

The system can operate at reduced flow rates with one filter demineralizer unit.

The temperature of water processed through the filter-demineral izers is limited by the resin operating temperature. Therefore, the reactor water must be cooled before being processed in the filter-demineralizers. The regenerative heat exchanger transfers heat from the tube side (hot process) to the shell side (cold process). The shell side flow returns to the reactor. The nonregenerative heat exchanger c ools the process further by tran sferring heat to the reactor building closed cooling water system.

The filter-demineralizers (see Figure 5.4-24) are pressure precoat type filters using ion exchange resins. Spent resins are not regenerable and are sluiced from the filter-demineralizers to a backwash receiving tank from which they are transferred to the radwaste system for processing and disposal. To prevent resins from entering the RRC in the event of complete failure of a filter-demineralizer resin septum, a strainer is installed on each filter-demineralizer. Each strainer and filter-demineralizer vessel has a control room alarm that is energized by high differential pressure. Further increase in diffe rential pressure will isolate the filter-demineralizer. The backwash and precoat cycle for a filter-demineralizer is automatic to prevent operational errors such as inadvertent ope nings of valves that would initiate a backwash or contaminate reactor water with resins.

The filter-demineralizer piping

C OLUMBIA G ENERATING S TATION Amendment 58 F INAL S AFETY A NALYSIS R EPORT December 2005 5.4-45 configuration is arranged to ensure that transfers are complete and crud traps are avoided.

A bypass line is provided around the filter-dem ineralizers.

On low flow or loss of flow in the system, flow is maintained through each filter-demineralizer by its own holding pump. Sample points are pr ovided in the common influent header and in each effluent line of the filter-demineralizers for continuous indi cation and recording of system conductivity. High conductivity is annunciated in the control room. The influent sample point is also used as the normal source of reactor coolant grab samples. Sample analysis also indicates the effectiveness of the filter-demineralizers.

The suction line of the RCPB portion of the RWCU system contains two motor-operated isolation valves that automatically close in response to signals from the RPV low water level and the leak detection system. The outboard isolation valve, RWCU-V-4, automatically closes in response to signals from actuation of th e SLC system and high nonregenerative heat exchanger outlet water temperature. These actions prevent (a) loss of reactor coolant, (b) release of radioactive material from the reactor, (c) removal of liquid reactivity control material, and (d) thermal damage to ion-exchange resins. The RCPB isolation valves may be remote manually operated to isolate the system equipment for maintenance or servicing.

A remote manual-operated gate valve on the return line to the reactor provides long-term leakage control. Instantaneous reverse flow isolation is provided by check valves in the RWCU piping.

Operation of the RWCU system is controlled from the main control room. Resin-changing operations, which include backwashing and precoating, are controlled from the radwaste control room in the radwaste building.

A functional control diagram is provided in Figure 7.3-1.

5.4.8.3 System Evaluation

The RWCU system in conjunction with the condensate treatmen t system and FPC and cleanup system maintains reactor water quality during all reactor operating m odes (normal, standby, startup, shutdown, and refueling). The RWCU components provide a system with the capability to support reactor operations at power levels up to 3629 MWt.

The component pressure and temperat ure design conditions are shown in Table 5.4-5. The process containing components (p iping, valves, vesse ls, heat exchangers, pumps) are designed to the requirements of Section 3.2. The control requirements for the RCPB isolation valves are designed to the requirements of Table 7.3-5. The nonregenerative h eat exchanger is sized to maintain the process temperature required for the cleanup demineralizer resin when the cooling capacity of the regenerative heat exchanger is reduced at times when flow is partially bypassed to the main condenser or radwaste.

C OLUMBIA G ENERATING S TATION Amendment 61 F INAL S AFETY A NALYSIS R EPORT December 2011 LDCN-09-032 5.4-46 5.4.8.4 Demineralizer Resins

Regulatory Guide 1.56 complian ce is described in Section 1.8.

5.4.8.5 Reactor Water Cleanup Water Chemistry

5.4.8.5.1 Analy tical Methods

Chemical analyses methods used for determinati on of conductivity, pH, a nd chloride content of primary coolant are as follows:

Conductivity measured in accordance to ASTM-D-1125 pH measured in accord ance to ASTM-D-1293

Chloride determined by ion chromat ography in accordance with the vendor's operating manual

5.4.8.5.2 Relationship of Filter-Demineralizer Condition to Water Chemistry

The filter-demineralizer condition during norm al power operation is related to inlet conductivity and water volume proce ssed through the unit. The in let conductivity is related to impurity concentration through the equivalent c onductance of the constitu ents of the process fluid. System flow rates are measured and reco rded to determine quantity of water processed.

Periodically, when analyses of reactor coolant water chemistry indicates it will be beneficial for mitigating IGSCC a NobleChem application of a microscopic layer of noble metals, platinum and rhodium, is injected into the reactor coolant to be deposited onto the reactor internals.

Conductivity instrumentation is calibrated against laboratory flow cel ls in accordance with ASTM-D-1125. The alarm setpoints for the conductivity instrument ation at the inlet and outlet of the filter-demineralizers are set to indicate marginal performance or breakthrough of the filter-demineralizers.

The quantity of the principle ion(s) likely to cause demineralizer breakthrough are not calculated using conductivity as di scussed in position 4.C of Regulatory Guide 1.56. Instead, actual ion sample data is taken and used to determine ion levels at the outlet of the filter-demineralizer. When sample da ta indicates resin breakthrough or the allowable pressure drop is exceeded, the filter-demin eralizer is regenerated.

C OLUMBIA G ENERATING S TATION Amendment 60 F INAL S AFETY A NALYSIS R EPORT December 2009 LDCN-04-002 5.4-47 5.4.9 MAIN STEAM LINES AND FEEDWATER PIPING

5.4.9.1 Safety Design Bases

To satisfy the safety bases, the main steam and feedwate r lines have been designed

a. To accommodate operational stresses, such as internal pressures and SSE loads, without a failure that could lead to the release of radi oactivity in excess of the guideline values in pub lished regulations, and

b. With suitable accesses to permit IST and inspections.

5.4.9.2 Power Gene ration Design Bases

To satisfy the design bases

a. The main steam lines have been designed to conduct steam from the reactor vessel over the full range of re actor power operation, and

b. The feedwater lines have been designed to conduct water to the reactor vessel over the full range of reactor power operation.

5.4.9.3 Description

The main steam piping is described in Section 10.3. The main steam and feedwater piping is shown in Figure 10.3-2.

The feedwater piping consists of two 24-in. O.D. lines which penetrate the containment and drywell and branch into three 12-in. lines each, which connect to the r eactor vessel. Each 24-in. line includes three containm ent isolation valves consisting of one check valve inside the drywell and one motor-operated gate valve and one check valve outside the containment. The design pressure and temperature of the feedwa ter piping between the re actor and maintenance valve is 1300 psig and 575°F. The Seismic Category I design requirements are placed on the feedwater piping from the reactor through the out board isolation valve and connected piping up to and including the first isolati on valve in the connected piping.

The materials used in the piping are in acco rdance with the applicable design code and supplementary requirement s described in Section 3.2.

The feedwater system is furt her described in Sections 7.7.1 , 7.7.2 , and 10.4.7.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-48 5.4.9.4 Safety Evaluation Differential pressure on reactor internals under the assumed acc ident condition of a ruptured steam line is limited by the use of flow restrictor s and by the use of four main steam lines. All main steam and feedwater pipi ng is designed in accordance with the requirements defined in Section 3.2.

5.4.9.5 Inspection and Testing Inspection and testing of the main steam lines and feedwater piping is performed in accordance with the ISI Program Plan to ensure compliance w ith applicable codes.

5.4.10 PRESSURIZER

Not Applicable to BWRs.

5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM

Not Applicable to BWRs.

5.4.12 VALVES

5.4.12.1 Safety Design Bases

Line valves such as gate, globe, and check valves are located in the fluid systems to perform a mechanical function. Valves are components of the system pressure boundary and, having moving parts, are designed to operate efficiently to maintain the integrity of this boundary.

The valves operate under the in ternal pressure/temperature lo ading as well as the external loading experienced during the various system transient operating conditions. The design criteria, the design loading, and acceptability criteria are as required in Section 3.9.3 for ASME Class 1, 2, and 3 valves. Complia nces with ASME Code s are discussed in Section 5.2.1.

5.4.12.2 Description

Line valves furnished are manufactured standard types, designe d and constructed in accordance with the requirements of ASME Section III for Class 1, 2, and 3 valves. All materials, exclusive of seals, packing and wearing compone nts, are designed to en dure the 40-year plant life under the environmental conditi ons applicable to the particul ar system when appropriate maintenance is peri odically performed.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-49 Power operators have been si zed to operate successfully und er the maximum differential pressure determined in the design speci fication or design basis calculations.

5.4.12.3 Safety Evaluation

Line valves are shop tested by the manufacturer for performability. Pressure retaining parts are subject to the testing and ex amination requirements of Secti on III of the ASME Code. To minimize internal and external leakage past seating surfaces, maximum allowable leakage rates are stated in the design specifica tions for both back seat as well as the main seat for gate and globe valves.

Valve construction materials are compatible with the maximum anticipated radiation dosage for the service life of the valves.

5.4.12.4 Inspection and Testing

Valves serving as containment isolation valves and which must remain closed or open during normal plant operation may be partially exercised during this period to assure their operability at the time of an emergency or faulted conditions. Other valves, serving as a system block or throttling valves, may be exer cised when appropriate.

Motors used with valve actuators are furn ished in accordance with applicable industry standards. Each motor actuator has been assembled, factory te sted or tested in-situ, and adjusted on the valve for proper operation, position and torque switch setting, position transmitter function (where applicable), and speed requirements. A selected set of motor-

operated valves with active safety functions (Generic Letter 89-10 Program and Generic Letter 96-05 Program) have additionally been tested to demonstrate adequate stem thrust (or torque) capability to open (or clos e) the valve within the specified time at specified maximum expected differential pressure. Modifications have been made to several gate valves to eliminate the possibility for internal pressure locking forces wh ich could prevent the actuator from unseating the valve (G eneric Letter 95-07 Program).

Tests verified no mechanical damage to valve components during full st roking of the valve.

Suppliers were required to furnish assurance of acceptability of the equipment for the intended service based on any combination of

a. Test stand data, b. Prior field performance,

c. Prototype testing, and

d. Engineering analysis.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-50 Preoperational and operational testing performed on the installed valves consists of total circuit check out and performance tests to verify de sign basis capability including speed requirements at specified differential pressure.

5.4.13 SAFETY AND RELIEF VALVES

A listing of the safety and re lief valves is provided in Table 5.4-6.

5.4.13.1 Safety Design Bases

Overpressure protection is provi ded at isolatable portions of systems in accordance with the rules set forth in the ASME Code, Secti on III for Class 1, 2, and 3 components.

5.4.13.2 Description

Pressure relief valves are desi gned and constructed in accordance with the same code class as that of the line valves in the system.

The design criteria, design loading, and de sign procedure are described in Section 3.9.3.

5.4.13.3 Safety Evaluation

The use of pressure relieving devices will ensure that overpressure will not exceed 10% above the design pressure of the system. The number of relieving devices on a system or portion of a system have been determined on an individual component basis.

5.4.13.4 Inspection and Testing

The valves are inspected and tested in accordance with ASME Section XI, if required.

Other than the main steam relief valves, no prov isions are to be made for inline testing of pressure relief valves, other than set pressure and leakage. Certified set pressures and relieving capacities are stampe d on the body of the valves by the manufacturer and further examinations would necessitate removal of the component. For subsequent set pressure changes, the valve body will be stamped or a st amped tag will be attached indicating the new pressure.

5.4.14 COMPONENT AND PIPING SUPPORTS

Support elements are provided for those compon ents included in the RC PB and the connected systems.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 5.4-51 5.4.14.1 Safety Design Bases Design loading combinations, design procedures, and acceptability criteria are as described in Section 3.9.3. Flexibility calculations and seismic anal ysis for Class 1, 2, and 3 component and piping supports within the ASME boundary of jurisdiction conform with the appropriate requirements of ASME Secti on III, Subsection NF. Outside the ASME boundary steel structures conform to the AISC manual of Steel Construction.

Spacing and size of pipe suppor t elements were based on the piping analysis performed in accordance with ASME Section III a nd further described in Section

3.7. Standard

manufacturer hanger types were used and fabricated of mate rials per ASME Section III, Subsection NF.

5.4.14.2 Description

The use and location or rigid-t ype supports, variable or constant spring-type supports, and anchors or guides are determined from the results of static and dynamic analyses of the associated piping systems. The normal and transient (including seismic) support point loads generated by the piping analyses are combined as prescribed by Sections 3.9.3 and 3.7 , and then utilized as the design basis loadings for each affected pipe support.

Typically, components support elements are manufacturers' standard items which are purchased with certified load capacity data reports. Nonstandard support structures and pressure boundary attachments are qualified by detailed structural analyses in compliance with applicable load combinations and governing design codes.

As described by Sections 5.4.14.1 and 5.4.14.2, each component suppor t system has been rigorously evaluated with all due consideration for extreme load ing conditions and satisfaction of conservative design allowable stresses. This demonstration of structural adequacy combined with a comprehensive testing a nd inspection program (see Section 5.4.14.3) constitutes the safety evaluation basis for th ese passive support elements.

5.4.14.3 Inspection and Testing

After completion of the installa tion and balancing of a support system, all hanger elements were visually examined to ensu re that they were in correct adjustment to their cold setting position. On initial hot startup operations, ther mal growth was observe d and it was confirmed that all spring-type hangers a nd snubbers were functioning properly between their hot and cold setting positions. In addition, during power ascension testing critical systems were instrumented and monitored for vibration response under normal a nd plant transient conditions. The results of these tests showed all systems to be functioning as predicted by design analyses and thus all systems were accepted as operable and in compliance with the governing ASME Code.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-06-054 5.4-52 5.4.15 HIGH-PRESSURE CORE SPRAY SYSTEM

See Section 6.3 for a description of the HPCS system.

5.4.16 LOW-PRESSURE CORE SPRAY SYSTEM

See Section 6.3 for a description of the LPCS system.

5.4.17 STANDBY LIQUID CONTROL SYSTEM

See Section 9.3.5 for a description of the SLC system.

5.4.18 REFERENCES

5.4-1 Ianni, P. W., "Effect iveness of Core Standby Cooling Systems for General Electric Boiling Water React ors," APED-5458 , March 1968.

5.4-2 "Design and Performance of General Electric Boiling Water Reactor Main Steam Line Isolation Valves," APED-5750, General Electric Co., Atomic Power Equipment Depa rtment, March 1969.

5.4-3 "Power Uprate with Extended Load Line Limit Safety Analysis for WNP-2,"

NEDC-32141P, General Electric Company.

5.4-4 "Generic Evaluations of General Electric Boiling Wa ter Reactor Power Uprate -

Volume I," NEDC-31984P, Ge neral Electric Company.

5.4-5 "Reactor Core Isolation Cooling System (RCIC)," Design Basis Document, Section 315.

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 8-1 1 3 5.4-53 Table 5.4-1 Reactor Coolant Pr e ssure Boundary Pump

and Valve Descriptio n a Location Active

/Inac t i ve Valve Reference Figure Valve Description RHR vessel in Active Active Active Active Active Active

Inacti v e Inacti v e Inacti v e RHR-V-41A

RHR-V-41B RHR-V-41C (E12F041A, B, C) RHR-V-42A

RHR-V-42B RHR-V-42C (E12F042A, B, C) RHR-V-111A

RHR-V-111B

RHR-V-111C (E12F111A, B, C) 5.4-15 5.4-15 5.4-15 5.4-15 5.4-15 5.4-15

5.4-15 5.4-15 5.4-15 RHR/recirculation

line in Active Active

Active Active

Inacti v e Inacti v e

Inacti v e Inacti v e RHR-V-50A

RHR-V-50B (E12F050A, B) RHR-V-53A

RHR-V-53B (E12F053A, B) RHR-V-112A

RHR-V-112B (E12F112A , B)

RHR-V-123A

RHR-V-123B (E12F099A, B) 5.4-15 5.4-15

5.4-15 5.4-15

5.4-15 5.4-15

5.4-15 5.4-15 Head spray Active Active RHR-V-19 (E 12F019)

RHR-V-23 (E 12F023) 5.4-15 5.4-15 RHR shutdown

cooling suction Active Active Inacti v e RHR-V-8 (E12F008)

RHR-V-9 (E12F009)

RHR-V-113 (E12F113) 5.4-15 5.4-15 5.4-15 RCIC vessel out Active Active Active Active RCIC-V-8 (E51F008)

RCIC-V-63 (E51F063)

RCIC-V-64 (E51F064)

RCIC-V-76 (E51F0076) 5.4-11 5.4-11 5.4-11 5.4-11 C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 8-1 1 3 5.4-54 Table 5.4-1

Reactor Coolant Pr e ssure Boundary Pump

and Valve Descriptio n a (Continued)

Location Active

/Inac t i ve Valve Reference Figure (Nuclear boiler)

Reactor vessel head

Inactive Inactive MS-V-1 (B22F001)

MS-V-2 (B22F002)

10.3-2 10.3-2 Feedwater in Active Active

Inactive Inactive

Active Active

Active Active RFW-V-10A

RFW-V-10B (B22F010A, B)

RFW-V-11A

RFW-V-11B (B22F011A, B)

RFW-V-32A

RFW-V-32B (B22F032A, B)

RFW-V-65A

RFW-V-65B (B22F065A, B) 10.3-2 10.3-2

10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 Safety relief Active Active Active Active Active Active Active Active

Active Active Active Active Active Active

Active Active MS-RV-2A MS-RV-3A MS-RV-2D MS-RV-2C MS-RV-1B MS-RV-2B MS-RV-3C MS-RV-3B (B22F013A-H)

MS-RV-1A MS-RV-1D MS-RV-1C MS-RV-4C MS-RV-5C (B22F013J-N)

MS-RV-4D (B22F013P)

MS-RV-4B MS-RV-4A 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2

10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2

10.3-2 10.3-2 C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.4-55 Table 5.4-1 Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued)

Location Active/Inactive Valve Reference Figure Active Active (B22F013R-S)

MS-RV-5B MS-RV-3D (B22F013U-V)

10.3-2 10.3-2 Reactor water

cleanup system Inactive RWCU-V-103 (G33F103) 5.4-22 Line suction Active Active Inactive Inactive Inactive Inactive RWCU-V-1 (G33F001)

RWCU-V-4 (G33F004)

RWCU-V-100 (G33F100)

RWCU-V-101 (G33F101)

RWCU-V-102 (G33F102)

RWCU-V-106 (G33F106) 5.4-22 5.4-22 5.4-22 5.4-22

5.4-22

5.4-22 Line discharge Active RWCU-V-40 (G33F040) 5.4-22 Drain to condenser Active Active MS-V-16 (B22F016)

MS-V-19 (B22F019) 10.3-2 10.3-2 MSIV Active Active Active Active Active Active Active Active MS-V-22A MS-V-22B MS-V-22C MS-V-22D (B22F022)

MS-V-28A MS-V-28B MS-V-28C MS-V-28D (B22F028) 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 10.3-2 C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-05-009,06-000 5.4-56 Table 5.4-1

Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued)

Location Active/Inactive Valve Reference Figure Drain to condenser (Recirculation)

Active Active Active Active MS-V-67A MS-V-67B MS-V-67C MS-V-67D (B22F067) 10.3-2 10.3-2 10.3-2 10.3-2 Recirculation pump

suction Inactive Inactive RRC-V-23A RRC-V-23B (B35F023) 5.4-7 5.4-7 Flow control (pump

discharge) Inactive b Inactive b Inactive Inactive RRC-V-60A

RRC-V-60B (B35F060)

RRC-V-67A

RRC-V-67B (B35F067) 5.4-7 5.4-7

5.4-7 5.4-7 RCIC vessel head in Active Active Active RCIC-V-13 (E51F013)

RCIC-V-65 (E51F065)

RCIC-V-66 (E51F066) 5.4-11 5.4-11 5.4-11 HPCS in Active Active Inactive HPCS-V-4 (E22F005)

HPCS-V-5 (E22F004)

HPCS-V-38 (E22F038) 6.3-4 6.3-4 6.3-4 LPCS in Active Active Inactive LPCS-V-5 (E21F005)

LPCS-V-6 (E21F006)

LPCS-V-51 (E21F051) 6.3-4 6.3-4 6.3-4 Standby liquid

control in Active Active Active Active Inactive SLC-V-4A SLC-V-4B SLC-V-6 SLC-V-7 SLC-V-8 9.3-14 9.3-14 9.3-14 9.3-14 9.3-14 Pump description Recirculation pump Inactive Inactive RRC-P-1A RRC-P-1B (B35C001) 5.4-7 5.4-7 C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.4-57 Table 5.4-1 Reactor Coolant Pre ssure Boundary Pump and Valve Description a (Continued) a In addition to the process valves listed herein, there are instrument test conditions, drain valves, and sampling valves less than 1 in. nominal size within the RCPB. See associated system flow diagram figures.

b Mechanically blocked in the full open position.

NOTE:

Active components are those whose operability is relied on to perform a safety function during the transients or accidents.

Inactive components are those whose operab ility (e.g., valve opening or closure, pump operation or trip) is not relied on to perform the system's safety function during the transients or accidents.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December 2007 LDCN-07-011 5.4-58 Table 5.4-2

Reactor Recirculation System Design Characteristics

Description External loops 2 Pump sizes (nominal O.D.)

Pump suction, in.

24 Pump discharge, in.

24 Discharge manifold, in.

16 Recirculation inlet lines, in.

12 Design pressure (psig)/design temperature (°F) Suction piping and valve up to and including pump suction nozzle 1250/575 Pump, discharge valves, and piping between 1650/575 Piping after discharge blocking valve up to vessel 1550/575 Vessel bottom drain 1275/575 Operation at pump related conditions Recirculation pump Flow, gpm 47,200 Flow, lb/hr 17.85 x 10 6 Total developed head, ft 805

Suction pressure (static), psia 1025 Required NPSH, ft 115 Water temperature (maximum), °F 533 Pump brake hp (minimum) 8340 Flow velocity at pump suction (approximate), ft/sec 41.5 Pump motor Voltage rating 6600 Speed, rpm 1780 Motor rating, hp 8900

Phase 3 Frequency 60

Motor rotor inertia (lb-ft

2) 21,500 (RRC-M-P/1B) 20,600 (RRC-M-P/1A)

Jet pumps Number 20 Total jet pump flow, lb/hr 108.5 x 10 6 Total I.D., in. 6.4

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.4-59 Table 5.4-2

Reactor Recirculation System Desi g n Charac t er i s tics (C ontinued)

Description Diffuser I.D., in.

19.0 Nozzle I.D. (five each), in. 1.3 Diffuser ex it velocity, f t/sec 16.2 Jet pump head, ft 88.19 Flow control valve a Type Ball Material Austenit i c s t ainless steel

Valve wide open C V (minimum), gpm/psi 7000 Valve s i ze diame t er, in. 24 Recirculation block valve Type Gate valve Actuator Motor

Material Austenit i c s t ainless steel

Valve s i ze diame t er, in. 24 Recirculation pu m p flow measurement Type Elbow taps Rated flow (gpm) 47,200 Flow element location Pump suction line Range 20-115% rated pump flow Accuracy (% rated pressure drop) 9% Repeatability (% rate d pressure drop) 4% a Mechanically blocked in the full open position.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.4-60 Table 5.4-3

Operating E x perience of Ingersoll-Rand

Emergency Core Cooling Systems Pump s a,b Plant Pump Time (hr) Hatch 2 R HR 2A 864 2B 1112 2C 629 2D 569 LPCS 2A 13.5 2B 11.8 Chinshan 1 RHR 100 Core spray 30 Chinshan 2 RHR 75 Core spray 20 a The italicized information is historical and was provided to support the application for an operating license.

bNo problems have been reported on these pum ps. Pump design principles applied by Ingersoll-Rand to these units are not unique. Assu rance of a predictable functional reliability is also provided by a history of design, production, and applic ation of pumps for similar pumping requirements in other nuc lear and nonnuclear applications.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.4-61 Table 5.4-4

Operating E x perience of Similar Ingersoll-Rand Pumps for B WR Projects

Under Revie w a,b Year Size Range (g p m) Number of P u mps 1963 <4000 12 1964 <3000 24 1965 <5000 32 1966 <4500 39 1967 <5000 8000 39 3 1968 <6500 9000 11000 25 6 9 1969 <6500 8000-9000 39 9 1970 <6500 8000 12,000 33 14 6 1971 <6500 9000 10,000-12,000 53 3 12 1972 <6500 8000 10,000-12,000 44 18 18 1973 <6500 8000 10,000-13,800 41 8 20 1974 <6500 8000 10,000-13,800 32 2 30 1975 <7500 8500 10,000-13,800 76 18 50 1976 8500 9 a The italicized information is historical and was provided to support the application for an operating license.

b The vertical pumps used for ECCS functions at CGS are sized at 1200 to 8100 gpm. They are multistaged axial pumps. Included here is a partial list of the application history for similar pumps made by the same vendor. Although the operating experience in nuclear applications is just beginning, the postoperating experience in nonnuclear applications with these vertical pumps is very extensive. It indicates that the CGS ECCS pumps can be expected to operate as required. In reviewing this table, the generic pump design should be recalled because larger capacity pumps are configured from stages that comprise the smaller capacity pumps. Design refinements are evident in the capacity growth of these stages, whether in single, double, or multiple axial stackups.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.4-62 Table 5.4-5 Reactor Water Cleanup System

Equipment Design Data Main Cleanup Recirculation Pumps Number 2 Capacity (each) 100% (@90 bhp)

Design te m p erature, F 575 Design pressure, psig 1420 Discharge head at shutoff, ft 575 Minimum available NPSH, ft 16 Heat Exchangers Regenerative Nonregenerative Number 1 (3 shells) 1 (2 shells)

Shell design pressure, psig 1420 150 Shell design temperature, F 575 370 Tube design press u re, psig 1420 1420 Tube design temperature, F 575 575 Filter-De m i neralizers Type Pressure precoat Number 2 Design temperature, F 150 Design pressure, psig 1450

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 5 6 5.4-63 Table 5.4-6 Safety and Relief Valves for Piping Systems

Connected t o the React o r 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 s y stem discharge line RCIC-R V-3 RCIC s y stem suction l i ne RCIC-RV-17 (E51F017) RCIC lube oil cooler supply line RCIC-RV-19T RCIC vacuum tank RCIC-RV-33 (E51F033) a Shutdown cooling supp l y line RHR-RV-5 (E12F005)

Shutdown cooling retu r n line RHR-RV-25A RHR-RV-25B (F12F025A, B)

Suppression pool supply for RHR RHR-RV-88A RHR-RV-88B RHR-RV-88C (E12F088A, B, C) RHR flush line RHR-RV-30 (E12F030)

RHR heat exchanger (shell side)

RHR-RV-1A RHR-RV-1B RWCU regenerative heat exc h anger (shell side)

RWCU-RV-1 a C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 5.4-64 Table 5.4-6 Safety and Relief Valves for Piping Systems Connected to the Reactor Coolan t Pressure Bounda ry (Continued)

RWCU regenerative heat exchanger (tube side) RWCU-RV-3 a RWCU blowdown to radwaste system or condenser RWCU-RV-36 (G33F036) a HPCS suction line HPCS-RV-14 (E22F014) HPCS discharge line HPCS-RV-35 (E22F035)

LPCS discharge line LPCS-RV-18 (E21F018)

LPCS suction line LPCS-RV-31 (E21F031)

SLC pump discharge line SLC-RV-29A SLC-RV-29B (C41F029A, B) a These relief valves are instal led in a B31.1 system; not subject to Section XI testing and inspection.

Driving Flow Recirculation Pump Jet Pump Simplified SchematicPictorial View Recirculation Outlet Recirculation InletDischarge Shutoff ValveFlow Control Valve (Note 1)Suction Shutoff ValveNote 1: FCVs Are Mechanically Blocked Full Open.

Suction Flow CoreRecirculation System Evaluation and Isometric 960690.07 5.4-1 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report 110% Speed 105% Speed 100% Speed System Resistance 10,000 20,000 30,000 40,000 50,000 60,000 Flow - GPM Dynamic Head - Ft.

1,400 1,200 1,000 800 600 400 200 0 RRC Pump Dynamic Head-Flow Curve 960690.05 5.4-2 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report 020040060080010001200140016001800 25% Flow - 535F Water25% Flow - Cold Water 100% Flow - 535F Water100% Flow - Cold WaterBreakaway Torque is 1200 Ft. Lbs.

Pump Speed - RPM Pump Torque - Ft. Lbs.

36,000 32,000 28,000 24,000 20,000 16,000 12,000 8,000 4,000 0RRC Pump Speed - Torque Curve 960690.06 5.4-3 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.960690.59Recirculation Pump Head, NPSH, Flow and Efficiency Curves 5.4-4 400 200 0 10,000 5,000 0 90 80 70 60 50 40 30 20 10 0 1200 1000 800 600 400010.00020,00030,00040,00050,00060,00070,000 NPSH at C imp.Efficiency %

HeadBHP at 0.755 SP. GR.

Total Dynamic Head (Ft)

BHP NPSH (Ft)Efficiency %

Gallons Per Minute L Columbia Generating StationFinal Safety Analysis Report Operating Principle of Jet Pump 960690.58 5.4-5 Suction Flow Driving Flow Suction FlowP Driving FlowP Pressure Driving Flow Flow Suction Driving Nozzle Throat or Mixing SectionDiffuser Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.960690.60Core Flooding Capability of Recirculation System 5.4-6 Steam Separation Distribution PlenumWater Level After Break in Recirculation Loop NormalWater Level Steam Separators Active Core Columbia Generating StationFinal Safety Analysis Report Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-7.1 88 M530-1Reactor Recirculation System - P&IDRev.FigureDraw. No.Amendment 61December 2011 Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-7.2 7 M530-2Reactor Recirculation System - P&IDRev.FigureDraw. No.

Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.960690.61Main Steam Line Flow Restrictor Location 5.4-8Reactor Vessel Steam Flow Restrictor Drains Main Steam LineIsolation Valves Primary ContainmentTest Connection Columbia Generating StationFinal Safety Analysis Report Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.960690.84Main Steam Line Isolation Valve 5.4-9 Air Cylinder (Closing Piston Inside)

MSIV SpeedControl Valves Hydraulic Dash Pot Actuator Support

And Spring Guide

Shaft Closing Spring Spring Seat Member Stem Stem PackingLeak Off Connection (Plugged)

Bonnet Bolts Bonnet Balancing OrificeMain Valve

Seat Body Pilot Pilot Seat Accum Main Disk Columbia Generating StationFinal Safety Analysis Report Flow RCIC Pump Performance Curve (Constant Flow) 960690.55 5.4-10 NPSH-ft at 625 GPM EFF% at 625 GPM HEAD at 625 GPMBHP at SP. GR 1.0 at 625 GPM 3200 2800 2400 2000 1600 1200 800 400 0BHP Required NPSH-Required 30 20 10 0 600 400 200 0 800Eff.%90 80 70 60 50 40 30 20 10 01500200025003000350040004500 Speed Revolutions Per MinuteWitness Test Performance Bingham-Willamette Co.

Portland, Oregon Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report5.4-11 92 M519RCIC System - P&IDRev.FigureDraw. No.

Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-12 10 02E51-04,4,1RCIC System Process DiagramRev.FigureDraw. No.

Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.960690.86 RCIC Pump Performance Curve 5.4-13 1200 1400 1600 1800 2000 0 10 20 30 40 50 60 70 80 90Eff. %1200 500 1000 BHP 0 25 50 NPSH-ft 100 Gallons Per MinuteTest Speed RG. 3591-3585 RPM HeadEff%BHP at SP. GR 1.0 NPSH at C Imp.

L 1000 800 600 400 200 0 0Whitness Test Performance Bingham-Willamette Co.

Portland, Oregon.

Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.960690.87Typical Strainer 5.4-14 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 Measurements for Strainers at Penetration X-33

Rated Flow: 600 gal/min Columbia Generating StationFinal Safety Analysis Report Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-15.1 108 M521-1 Residual Heat Removal System - P&IDRev.FigureDraw. No.

Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-15.2 111 M521-2 Residual Heat Removal System - P&IDRev.FigureDraw. No.

Figure Not Available For Public Viewing Amendment 60December 2009 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 05.4-15.4 3 M521-4 Residual Heat Removal System - P&IDRev.FigureDraw. No.

Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-16 9 02E12-04,1,1Residual Heat Removal System Process DiagramRev.FigureDraw. No.

Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-17.1 7 02E12-04,22,1Residual Heat Removal System Process DataRev.FigureDraw. No.

Draw. No.

Rev.Figure Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.960690.89 RHR (LPCI) Pump Characteristics(S/N 0473113) P-2A 5.4-18 BHPEfficiency Head NPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 0 10 20 30 40 50 60 70 80 90 0 1 2 3

4 5

6 7

8 0 10 20 30 40 0 5 10 Brake Horsepower x 100 NPSH in FeetEfficiency, %

Columbia Generating StationFinal Safety Analysis Report Total Dynamic Head in Feet x 100 960690.90 Columbia Generating Station Final Safety Analysis ReportDraw. No.Rev.Figure Amendment 58 December 2005 5.4-19 Form No. 960690FH LDCN-05-000 RHR (LPCI) Pump Characteristics (S/N 0473 11 1) P-2B BHPEfficiency Head NPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 10 20 30 40 50 60 70 80 90 0 1 2 3 4 5 6 7 8 0 10 20 30 40 0 5 10 Brake Horsepow NPSH in FTotal Head in Feet x100Efficiency, %

960690.91 Columbia Generating Station Final Safety Analysis Report RHR (LPCI) Pump Characteristics(S/N 0473112) P-2CDraw. No.Rev.Figure Amendment 58 December 2005 5.4-20 Form No. 960690FH LDCN-05-000 BHPEfficiency Head NPSHR at C.L. Suction Nozzle Gallons Per Minute x 1000012345678 10 20 30 40 50 60 70 80 90 1 2 3 4 5

6 7 8 0 10 20 30 40 0 5 10 Brake Horsepower x 100 NPSH in FeetTotal Head in Feet x 100Efficiency, %

0 Figure Amendment 55 May 2001 Form No. 960690Draw. No.Rev.960690.88Vessel Coolant Temperature Versus Time(Two Heat Exchangers Available) 5.4-21 100 F/hr Assumed FlushTime 100 F/hr 212 F 600 500 400 300 200 100 0 012345678Hours After Control Rods InsertedVessel TemperatureVersus TimeTwo Exchangers Available Columbia Generating StationFinal Safety Analysis Report Vessel Water Temperature (°F)

Amendment 61December 2011 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-22.1 108 M523-1Reactor Water Cleanup System - P&IDRev.FigureDraw. No.

Amendment 59December 2007 Form No. 960690ai Columbia Generating StationFinal Safety Analysis Report 5.4-22.2 7 M523-2Reactor Water Cleanup System - P&IDRev.FigureDraw. No.

Amendment 61December 2011 Columbia Generating StationFinal Safety Analysis Report 5.4-22.3 M523-3Reactor Water Cleanup System - P&IDRev. 4FigureDraw. No.Form No. 960690ai LDCN-06-000

Draw. No.

Rev. Figure Amendment 55 May 2001 Figure Form No. 960690Draw. No.Rev.960690.92Vessel Coolant Temperature Versus Time(One Heat Exchanger Available) 5.4-25Hours After Control Rods Inserted012345678 0 100 200 300 400 500 600 100 F/hr Assumed FlushTime 212 F Columbia Generating StationFinal Safety Analysis Report Vessel Water Temperature (°F)