RS-14-006, Clinton, Unit 1, Updated Safety Analysis Report, Revision 16, Chapter 5 - Reactor Coolant System and Connected Systems
Text
CPS/USAR CHAPTER 05 5-i REV. 13, JANUARY 2009 CHAPTER 5 - REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS TABLE OF CONTENTS PAGE 5.1
SUMMARY
DESCRIPTION 5.1-1 5.1.1 Schematic Flow Diagram 5.1-2 5.1.2 Piping and Instrumentation Diagram 5.1-3 5.1.3 Elevation Drawings 5.1 3 5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY 5.2-1 5.2.1 Compliance with Codes and Code Cases 5.2-1 5.2.1.1 Compliance with 10 CFR Part 50, Section 50.55a 5.2-1 5.2.1.2 Applicable Code Cases 5.2-1 5.2.2 Overpressure Protection 5.2-1 5.2.2.1 Design Basis 5.2-1 5.2.2.1.1 Safety Design Bases 5.2-2 5.2.2.1.2 Power Generation Design Bases 5.2-2 5.2.2.1.3 Discussion 5.2-2 5.2.2.1.4 Safety Valve Capacity 5.2-3 5.2.2.2 Design Evaluation 5.2-3 5.2.2.2.1 Method of Analysis 5.2-3 5.2.2.2.2 System Design 5.2-4 5.2.2.2.2.1 Operating Conditions 5.2-4 5.2.2.2.2.2 Transients 5.2-4 5.2.2.2.2.3 Scram 5.2-5 5.2.2.2.2.4 Safety/Relief Valve Transient Analysis Specification 5.2-5 5.2.2.2.2.5 Safety/Relief Valve Capacity 5.2-5 5.2.2.2.3 Evaluation of Results 5.2-6 5.2.2.2.3.1 Safety/Relief Valve Capacity 5.2-6 5.2.2.2.3.2 Low-Low Set Relief Function 5.2-7 5.2.2.2.3.3 Pressure Drop in Inlet and Discharge 5.2-8 5.2.2.3 Piping & Instrument Diagrams 5.2-8 5.2.2.4 Equipment and Component Descritption 5.2-8 5.2.2.4.1 Description 5.2-8 5.2.2.4.2 Design Parameters 5.2-11 5.2.2.4.2.1 Safety/Relief Valve 5.2-11 5.2.2.5 Mounting of Pressure Relief Devices 5.2-11 5.2.2.6 Applicable Codes and Classification 5.2-12 5.2.2.7 Material Specification 5.2-12 5.2.2.8 Process Instrumentation 5.2-12 5.2.2.9 System Reliability 5.2-12 5.2.2.10 Inspection and Testing 5.2-12 5.2.3 Reactor Coolant Pressure Boundry Materials 5.2-13 5.2.3.1 Material Specifications 5.2-13 5.2.3.2 Compatibility with Reactor Coolant 5.2-13 CPS/USAR TABLE OF CONTENTS (Cont'd)
PAGE CHAPTER 05 5-ii REV. 13, JANUARY 2009 5.2.3.2.1 PWR Chemistry of Reactor Coolant 5.2-13 5.2.3.2.2 BWR Chemistry of Reactor Coolant 5.2-13 5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant 5.2-19 5.2.3.2.4 Compatibility of Construction Materials with External Insulation and Reactor Coolant 5.2-19 5.2.3.3 Fabrication and Processing of Ferritic Materials 5.2-20 5.2.3.3.1 Fracture Toughness 5.2-20 5.2.3.3.1.1 Compliance with Code Requirements 5.2-20 5.2.3.3.2 Control of Welding 5.2-20 5.2.3.3.2.1 Control of Preheat Temperature Employed for Welding of Low Alloy Steel. Regulatory Guide 1.50 5.2-20 5.2.3.3.2.2 Control of Electroslag Weld Properties. Regulatory Guide 1.34 5.2-21 5.2.3.3.2.3 Welder Qualification for Areas of Limited Accessibility. Regulatory Guide 1.71 5.2-21 5.2.3.3.3 Nondestructive Examination of Ferritic Tubular Products. Regulatory Guide 1.66 5.2-21 5.2.3.3.4 Moisture Control for Low Hydrogen, Covered Arc-Welding Electrodes 5.2-21 5.2.3.4 Fabrication and Processing of Austenitic Stainless Steels 5.2-22 5.2.3.4.1 Avoidance of Stress Corrosion Cracking 5.2-22 5.2.3.4.1.1 Avoidance of Significant Sensitization 5.2-22 5.2.3.4.1.2 Process Controls to Minimize Exposure to Contaminants 5.2-23 5.2.3.4.1.3 Cold Worked Austenitic Stainless Steels 5.2-23 5.2.3.4.2 Control of Welding 5.2-23 5.2.3.4.2.1 Avoidance of Hot Cracking 5.2-23 5.2.3.4.2.2 Electroslag Welds Regulatory. Guide 1.34 5.2-24 5.2.3.4.2.3 Welder Qualification for Areas of Limited Accessibility. Regulatory Guide 1.71 5.2-24 5.2.3.4.3 Nondestructive Examination of Tubular Products. Regulatory Guide 1.66 5.2-24 5.2.4 Inservice Inspection and Testing of Reactor Coolant Pressure Boundary 5.2-24 5.2.4.1 Inservice Inspection Program 5.2-24 5.2.4.1.1 Examination Plans 5.2-24 5.2.4.1.1.1 Preservice Examination Plan 5.2-25 5.2.4.1.1.2 Inservice Examination Plan 5.2-26 5.2.4.2 System Boundaries Subject to Inspection 5.2-26 5.2.4.3 Provision for Access to Reactor Coolant Pressure Boundary 5.2-26 5.2.4.3.1 Reactor Pressure Vessel 5.2-27 5.2.4.3.2 Pipe, Pumps and Valves 5.2-28 5.2.4.4 Examination Techniques and Procedures 5.2-28 5.2.4.5 Equipment for Inservice Inspection 5.2-28 5.2.4.6 Inspection Intervals 5.2-29 5.2.4.7 Examination Categories and Requirements 5.2-29 5.2.4.8 Evaluation of Examination Results 5.2-29 5.2.4.9 Coordination of Inspection Equipment with Access Provisions 5.2-29 5.2.4.10 System Leakage and Hydrostatic Tests 5.2-29 CPS/USAR CHAPTER 05 5-iii REV. 13, JANUARY 2009 5.2.4.11 Ultrasonic Calibration Standards 5.2-30 5.2.4.12 Augmented Inservice Inspection 5.2-30 5.2.4.12.1 Feedwater Nozzles and CRD Return Line Nozzle Examinations 5.2-30 5.2.4.12.2 Examination of Piping Susceptible to Intergranular Stress Corrosion Cracking 5.2-30 5.2.4.12.3 Examination of Containment Penetration Head Fittings 5.2-30 5.2.4.12.4 Examination of Break Exclusion Region 5.2-30 5.2.4.13 Repairs 5.2-30 5.2.5 Reactor Coolant Pressure Boundary and ECCS System Leakage Detection System 5.2-30a 5.2.5.1 Leakage Detection Methods 5.2-30a 5.2.5.1.1 Detection of Leakage Within The Drywell 5.2-31 5.2.5.1.2 Detection of Leakage External to the Drywell 5.2-32 5.2.5.1.3 Detection of Leakage External to Containment Building 5.2-32 5.2.5.1.4 Intersystem Leakage Monitoring 5.2-33 5.2.5.2 Leak Detection Instrumentation and Monitoring 5.2-33 5.2.5.2.1 Leak Detection Instrumentation and Monitoring Inside Drywell 5.2-33 5.2.5.2.2 Containment/Drywell Airborne Radioactivity Monitoring 5.2-36 5.2.5.2.2.1 Source of Leakage 5.2-36 5.2.5.2.2.2 Drywell Conditions Affecting Monitor Performance 5.2-37 5.2.5.2.2.3 Capabilities of the Detector 5.2-37 5.2.5.2.3 Leak Detection Instrumentation and Monitoring External to the Drywell 5.2-38 5.2.5.2.4 Summary 5.2-40 5.2.5.3 Indication in Control Room 5.2-40 5.2.5.4 Limits for Reactor Coolant Leakage 5.2-41 5.2.5.4.1 Total Leakage Rate 5.2-41 5.2.5.4.2 Identified Leakage Inside Drywell 5.2-41 5.2.5.5 Unidentified Leakage Inside the Drywell 5.2-41 5.2.5.5.1 Unidentified Leakage Rate 5.2-41 5.2.5.5.2 Sensitivity and Response Times 5.2-41 5.2.5.5.3 Length of Through-Wall Flaw 5.2-42 5.2.5.5.4 Margins of Safety 5.2-44 5.2.5.5.5 Criteria to Evaluate the Adequacy and Margin of the Leak Detection System 5.2-44 5.2.5.6 Differentiation Between Identified and Unidentified Leaks 5.2-44 5.2.5.7 Sensitivity and Operability Tests 5.2-44 5.2.5.8 Safety Interfaces 5.2-44 5.2.5.9 Testing and Calibration 5.2-45 5.2.5.10 Regulatory Guide 1.45 Compliance 5.2-45 5.2.6 References 5.2-45 5.3 REACTOR VESSEL 5.3-1 5.3.1 Reactor Vessel Materials 5.3-1 5.3.1.1 Material 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 CPS/USAR CHAPTER 05 5-iv REV. 13, JANUARY 2009 5.3.1.4 Special Controls for Ferritic and Austentic Stainless Steels 5.3-2 5.3.1.4.1 Compliance with Regulatory Guides 5.3-2 5.3.1.4.1.1 Regulatory Guide 1.31, Control of Stainless Steel Welding 5.3-2 5.3.1.4.1.2 Regulatory Guide 1.34, Control of Electroslag Weld Properties 5.3-2 5.3.1.4.1.3 Regulatory Guide 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components 5.3-2 5.3.1.4.1.4 Regulatory Guide 1.44, Control of the Use of Sensitized Stainless Steel 5.3-2 5.3.1.4.1.5 Regulatory Guide 1.50, Control of Preheat Temperature for Welding Low-Alloy Steel 5.3-2 5.3.1.4.1.6 Regulatory Guide 1.71, Welder Qualification for Areas of Limited Accessibility 5.3-2 5.3.1.4.1.7 Regulatory Guide 1.99, Revision 2, Radiation Embrittlement of Reactor Vessel Materials 5.3-2 5.3.1.5 Fracture Toughness 5.3-3 5.3.1.5.1 Compliance with 10 CFR 50 Appendix G 5.3-3 5.3.1.5.1.1 Method of Compliance 5.3-3 5.3.1.6 Material Surveillance 5.3-5 5.3.1.6.1 Compliance with "Reactor Vessel Material Surveillance Program Requirements" 5.3-5 5.3.1.6.2 Neutron Flux and Fluence Calculations 5.3-6 5.3.1.6.3 Predicted Irradiation Effects on Vessel Beltline Materials 5.3-6 5.3.1.6.4 Positioning of Surveillance Capsules and Method of Attachment 5.3-6 5.3.1.6.5 Time and Number of Dosimetry Measurements 5.3-7 5.3.1.7 Reactor Vessel Fasteners 5.3-7 5.3.2 Pressure-Temperature Limits 5.3-9 5.3.2.1 Limit Curves 5.3-9 5.3.2.1.1 Temperature Limits for Boltup 5.3-9 5.3.2.1.2 Temperature Limits for ISI Hydro Static or Leak Pressure Tests 5.3-9 5.3.2.1.3 Operating Limits During Heatup, Cool- down and Core Operation 5.3-10 5.3.2.1.4 Reactor Vessel Annealing 5.3-10 5.3.2.1.5 Predicted Shift in RTNDT 5.3-10 5.3.2.2 Operating Procedures 5.3-10 5.3.3 Reactor Vessel Integrity 5.3-10 5.3.3.1 Design 5.3-12 5.3.3.1.1 Description 5.3-12 5.3.3.1.1.1 Reactor Vessel 5.3-12 5.3.3.1.1.2 Shroud Support 5.3-12 5.3.3.1.1.3 Protection of Closure Studs 5.3-12 5.3.3.1.2 Safety Design Basis 5.3-13 5.3.3.1.3 Power Generation Design Basis 5.3-13 5.3.3.1.4 Reactor Vessel Design Data 5.3-13 5.3.3.1.4.1 Vessel Supports 5.3-13 5.3.3.1.4.2 Control Rod Drive Housings 5.3-13 5.3.3.1.4.3 In-Core Neutron Flux Monitor Housings 5.3-14 5.3.3.1.4.4 Reactor Vessel Insulation 5.3-14 5.3.3.1.4.5 Reactor Vessel Nozzles 5.3-14 5.3.3.1.4.6 Materials and Inspections 5.3-16 5.3.3.1.4.7 Reactor Vessel Schematic (BWR) 5.3-16 5.3.3.2 Materials of Construction 5.3-17 5.3.3.3 Fabrication Methods 5.3-17 CPS/USAR TABLE OF CONTENTS (Cont'd)
PAGE CHAPTER 05 5-v REV. 11, JANUARY 2005 5.3.3.4 Inspection Requirements 5.3-17 5.3.3.5 Shipment and Installation 5.3-17 5.3.3.6 Operating Conditions 5.3-18 5.3.3.7 Inservice Surveillance 5.3-18 5.3.4 References 5.3-19 A5.3 Attachments A and B to Question 251.2 5.4 COMPONENT AND SUBSYSTEM DESIGN 5.4-1 5.4.1 Reactor Recirculation Pumps 5.4-1 5.4.1.1 Safety Design Bases 5.4-1 5.4.1.2 Power Generation Design Bases 5.4-1 5.4.1.3 Description 5.4-1 5.4.1.4 Safety Evaluation 5.4-3 5.4.1.4.1 Compliance with General Design Criteria 5.4-4 5.4.1.5 Inspection and Testing 5.4-4 5.4.1.6 Operation 5.4-5 5.4.1.6.1 Normal Operation 5.4-5 5.4.1.6.1.1 Start 5.4-5 5.4.1.6.1.2 Heatup and Pressurization 5.4-6 5.4.1.6.1.3 Low Thermal Power 5.4-6 5.4.1.6.1.4 High Thermal Power 5.4-6 5.4.1.6.1.5 Power-Flow Control 5.4-6 5.4.1.6.2 Abnormal Operation 5.4-6 5.4.1.6.2.1 Safety 5.4-7 5.4.1.6.2.1.1 Moderate and Infrequent Events 5.4-7 5.4.1.6.2.1.2 Accident Events 5.4-7 5.4.1.6.2.2 Power Generation 5.4-7 5.4.1.6.2.2.1 Cavitation Interlocks 5.4-7 5.4.1.6.2.2.2 Flow Control Valve Automatic Runback 5.4-7 5.4.1.6.2.2.3 Flow Control Valve Minimum Position Interlock 5.4-7 5.4.1.6.2.2.4 LFMG Output Breaker Control 5.4-7 5.4.1.6.2.2.5 High Loop Flow Mismatch 5.4-8 5.4.1.6.2.2.6 Loop Suction and Discharge Isolation Valve Position 5.4-8 5.4.1.6.2.2.7 Trip to 25% Speed 5.4-8 5.4.1.6.3 One-Pump Operation 5.4-8 5.4.1.6.3.1 One Recirculation Pump Operation 5.4-8 5.4.1.6.3.2 Restart of One Recirculation Pump 5.4-8 5.4.1.6.4 Automatic Load-Following (ALF) Characteristics (Deleted) 5.4-8 5.4.1.6.5 Trip and Start Functions 5.4-8 5.4.1.6.6 Suction and Discharge Block Valve Operation 5.4-8 5.4.1.6.7 Residual Heat Removal System Operation 5.4-9 5.4.1.7 Safety Related Considerations 5.4-9 5.4.1.7.1 Pressure Integrity 5.4-9 5.4.1.7.2 Bearing Load Capability 5.4-9 5.4.1.7.3 Pump Shaft Critical Speed 5.4-9 5.4.1.7.4 Pump Bearing Integrity 5.4-9 CPS/USAR TABLE OF CONTENTS (Cont'd)
PAGE CHAPTER 05 5-vi REV. 11, JANUARY 2005 5.4.1.7.5 Pipe Rupture 5.4-9 5.4.1.7.6 Suction And Discharge Block Valve Close Rate 5.4-9 5.4.1.7.7 Flow Control Valve Actuator Stroking Rate 5.4-10 5.4.1.7.8 Loop Flow Balance 5.4-10 5.4.1.7.9 Thermal Shock 5.4-10 5.4.1.7.10 Anticipated Transients Without Scrams (ATWS) 5.4-10 5.4.1.8 Flow Control Components Description 5.4-10 5.4.1.8.1 Flow Control Valves (FCV) 5.4-10 5.4.1.8.2 Hydraulic Equipment 5.4-11 5.4.1.8.2.1 Flow Control Valve Actuator 5.4-11 5.4.1.8.2.2 Circulation Unit 5.4-12 5.4.1.8.2.3 Hydraulic Power Unit 5.4-12 5.4.1.8.2.4 Interconnecting Piping and Drain and Vent Valves 5.4-12 5.4.1.8.2.5 Hydraulic Fluid 5.4-12 5.4.1.9 Flow Control System Description 5.4-12 5.4.1.9.1 Safety Requirements 5.4-12 5.4.1.9.2 Design Description 5.4-12 5.4.1.9.3 Valve Actuation Equipment 5.4-13 5.4.1.9.4 Circuit Description 5.4-14 5.4.1.9.5 Hydraulic Power Unit Logic Controls 5.4-15 5.4.1.9.5.1 General Description 5.4-15 5.4.1.9.5.2 Functional Description 5.4-15 5.4.1.10 Low-Frequency Motor-Generator (LFMG) Set 5.4-17 5.4.1.10.1 Description 5.4-17 5.4.1.10.2 Safety 5.4-17 5.4.1.10.3 Power Generation 5.4-17 5.4.1.11 Power Supplies 5.4-17 5.4.1.11.1 General 5.4-17 5.4.1.11.2 Power Supply Arrangement 5.4-17 5.4.2 Steam Generators (PWR) 5.4-17 5.4.3 Reactor Coolant Piping 5.4-17 5.4.4 Main Steam Line Flow Restrictors 5.4-18 5.4.4.1 Safety Design Bases 5.4-18 5.4.4.2 Description 5.4-18 5.4.4.3 Safety Evaluation 5.4-18 5.4.4.4 Inspection and Testing 5.4-19 5.4.5 Main Steam Line Isolation System 5.4-19 5.4.5.1 Safety Design Bases 5.4-19 5.4.5.2 Description 5.4-20 5.4.5.3 Safety Evaluation 5.4-22 5.4.5.4 Inspection and Testing 5.4-23 5.4.6 Reactor Core Isolation Cooling System 5.4-24 5.4.6.1 Design Basis 5.4-24 5.4.6.1.1 Residual Heat and Isolation 5.4-25 5.4.6.1.1.1 Residual Heat 5.4-25 5.4.6.1.1.2 Isolation 5.4-25 5.4.6.1.2 Reliability, Operability, and Manual Operation 5.4-26 CPS/USAR TABLE OF CONTENTS (Cont'd)
PAGE CHAPTER 05 5-vii REV. 11, JANUARY 2005 5.4.6.1.2.1 Reliability and Operability 5.4-26 5.4.6.1.2.2 Manual Operation 5.4-27 5.4.6.1.3 Loss of Offsite Power 5.4-27 5.4.6.1.4 Physical Damage 5.4-27 5.4.6.1.5 Environment 5.4-27 5.4.6.2 System Design 5.4-27 5.4.6.2.1 General 5.4-27 5.4.6.2.1.1 Description 5.4-27 5.4.6.2.1.2 Diagrams 5.4-27 5.4.6.2.1.3 Interlocks 5.4-28 5.4.6.2.2 Equipment and Component Description 5.4-29 5.4.6.2.2.1 Design Conditions 5.4-29 5.4.6.2.2.2 Design Parameters 5.4-30 5.4.6.2.3 Applicable Codes and Classifications 5.4-34 5.4.6.2.4 System Reliability Considerations 5.4-34 5.4.6.2.5 System Operation 5.4-36 5.4.6.2.5.1 Automatic Operation 5.4-36 5.4.6.2.5.2 Test Loop Operation 5.4-37 5.4.6.2.5.3 Steam Condensing (Hot Standby) Operation - Not Available 5.4-38 5.4.6.2.5.4 Limiting Single Failure 5.4-38 5.4.6.3 Performance Evaluation 5.4-39 5.4.6.4 Preoperational Testing 5.4-39 5.4.7 Residual Heat Removal System 5.4-39 5.4.7.1 Design Bases 5.4-39 5.4.7.1.1 Functional Design Basis 5.4-39 5.4.7.1.1.1 Residual Heat Removal Mode (Shutdown Cooling Mode) 5.4-39 5.4.7.1.1.2 Low Pressure Injection (LPCI) Mode 5.4-40 5.4.7.1.1.3 Suppression Pool Cooling Mode 5.4-40 5.4.7.1.1.4 Containment Spray Cooling Mode 5.4-40 5.4.7.1.1.5 Reactor Steam Condensing Mode - Not Available 5.4-40 5.4.7.1.1.6 Feedwater Leakage Control Mode (FWLC) 5.4-40 5.4.7.1.2 Design Basis for Isolation of RHR System from Reactor Coolant System 5.4-41 5.4.7.1.3 Design Basis for Pressure Relief Capacity 5.4-42 5.4.7.1.3.1 RHR System Relief with respect to Operator Errors 5.4-43 5.4.7.1.4 Design Basis with Respect to General Design Criterion 5 5.4-44 5.4.7.1.5 Design Basis for Reliability and Operability 5.4-44 5.4.7.1.6 Design Basis for Protection from Physical Damage 5.4-45 5.4.7.2 Systems Design 5.4-45 5.4.7.2.1 System Diagrams 5.4-45 5.4.7.2.2 Equipment and Component Description 5.4-45 5.4.7.2.3 Controls and Instrumentation 5.4-46 5.4.7.2.4 Applicable Codes and Classifications 5.4-47 5.4.7.2.5 Reliability Considerations 5.4-47 5.4.7.2.6 Manual Action 5.4-47 5.4.7.2.7 Outline of Operating Procedure 5.4-48 5.4.7.3 Performance Evaluation 5.4-49 CPS/USAR TABLE OF CONTENTS (Cont'd)
PAGE CHAPTER 05 5-viii REV. 11, JANUARY 2005 5.4.7.3.1 Shutdown with All Components Available 5.4-49 5.4.7.3.2 Shutdown with Most Limiting Failure 5.4-50 5.4.7.3.3 Shutdown with Crack in RHR Cooling Loop 5.4-50 5.4.7.4 Preoperational Testing 5.4-51 5.4.8 Reactor Water Cleanup System 5.4-51 5.4.8.1 Design Bases 5.4-51 5.4.8.1.1 Safety Design Basis 5.4-51 5.4.8.1.2 Power Generation Design Bases 5.4-51 5.4.8.2 System Description 5.4-52 5.4.8.3 System Evaluation 5.4-54 5.4.9 Main Steam Lines and Feedwater Piping 5.4-54 5.4.9.1 Safety Design Bases 5.4-54 5.4.9.2 Power Generation Design Bases 5.4-54 5.4.9.3 Description 5.4-55 5.4.9.4 Safety Evaluation 5.4-55 5.4.9.5 Inspection and Testing 5.4-56 5.4.10 Pressurizer (Not Applicable to BWR) 5.4-56 5.4.11 Pressurizer Relief Discharge System (Not Applicable to BWR) 5.4-56 5.4.12 Valves 5.4-56 5.4.12.1 Safety Design Bases 5.4-56 5.4.12.2 Description 5.4-56 5.4.12.3 Safety Evaluation 5.4-56 5.4.12.4 Inspection and Testing 5.4-57 5.4.13 Safety and Relief Valves 5.4-57 5.4.13.1 Safety Design Bases 5.4-57 5.4.13.2 Description 5.4-57 5.4.13.3 Safety Evaluation 5.4-57 5.4.13.4 Inspection and Testing 5.4-58 5.4.14 Component Supports 5.4-58 5.4.14.1 Safety Design Bases 5.4-58 5.4.14.2 Description 5.4-58 5.4.14.3 Safety Evaluation 5.4-58 5.4.14.4 Inspection and Testing 5.4-58 5.4.15 Hydrogen Water Chemistry System 5.4-59 5.4.15.1 Design Basis 5.4-59 5.4.15.2 System Description 5.4-59 5.4.16 References 5.4-60 CPS/USAR CHAPTER 05 5-ix REV. 13, JANUARY 2009 CHAPTER 5 - REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS LIST OF TABLES NUMBER TITLE PAGE 5.2-1 Reactor Coolant Pressure Boundary Components Applicable Code Cases 5.2-47 5.2-2 Nuclear System Safety Relief Set Pressures and Capacities 5.2-48 5.2-3 Preservice Examination Coverage 5.2-49 5.2-4 Reactor Coolant Pressure Boundary Materials 5.2-50 5.2-5 (Deleted) 5.2-56 5.2-6 Typical BWR Water Chemistry 5.2-57 5.2-7 Systems Which May Initiate During Overpressure Event 5.2-58 5.2-8 Water Sample Locations 5.2-59 5.2-9a Summary of Isolation/Alarm of System Monitored and the Leak Detection Methods Used (Summary of Variable Trip Alarms Leakage Source vs. Generated Variables) 5.2-60 5.2-9b Summary of Isolation/Alarm of System Monitored and the Leak Detection Methods Used 5.2-62 5.2-10 Sequence of Events for Figure 5.2-1 5.2-63 5.3-1 Charpy Test Results 5.3-20 5.3-2 Beltline Plate & Weld RT NDT & USE Values 5.3-24 5.3-3 Beltline & Adjacent Girth Weld ART Results 5.3-26 5.3-4 Shell Course Number 1 ART Results 5.3-27 5.4-1 Reactor Recirculation System Design Characteristics 5.4-61 5.4-2 Reactor Water Cleanup System Equipment Design Data 5.4-64 5.4-3 RHR Pump/Valve Logic 5.4-65 5.4-4 Recirculation System Trip and Start Functions 5.4-69 5.4-5 Reactor Core Isolation Cooling System - Design Specification Valve Stroke Time/ Differential Pressure Historical Information 5.4-70
CPS/USAR CHAPTER 05 5-x REV. 13, JANUARY 2009 CHAPTER 5 - REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS LIST OF FIGURES NUMBER TITLE 5.1-1 Rated Operating Conditions of the Boiling Water Reactor 5.1-2 Coolant Volumes of the Boiling Water Reactor 5.2-1 Safety/Relief Valve Capacity Sizing Transient MSIV Closure with High Flux Trip 5.2-2A Safety/Relief Valve Lift vs. Time Characteristic (Power Actuated Relief Mode) 5.2-2B Safety/Relief Valve Lift vs. Time Characteristic (Spring Action Safety Mode) 5.2-3A Scram Reactivity versus Time Characteristic 5.2-3B Control Rod Drive vs. Time Characteristics 5.2-4 Peak Vessel Pressure versus Safety/Relief Capacity 5.2-5 Time Response for Pressurization Transients for Safety/Relief Capacity Sizing 5.2-6 (Deleted) 5.2-7A Reactor Vessel Pressure Following Transient Isolation Event 5.2-7B Power Actuated and Safety Action Valve Lift Characteristics 5.2-8 Safety/Relief Valve and Steamline Schematic 5.2-9 Not Used 5.2-10 Schematic of Safety/Relief Valve with Auxiliary Actuating Device 5.2-11 Typical BWR Flow Diagram 5.2-12 Conductance vs. pH as a Function of Chloride Concentration of Aqueous Solution at 25°C 5.2-13 Calculated Leak Rate vs. Crack Length as a Function of Applied Hoop Stress 5.2-14 Axial Through-Wall Crack Length Data Correlation 5.2-15 Cross-Section View of Valve-Operating BWRs 5.3-1 Reactor Vessel Cutaway Diagram 5.3-2 Nominal Reactor Vessel Water Level Trip and Alarm Elevations 5.4-1 Recirculation System Elevation and Isometric 5.4-2 Deleted 5.4-3 Recirculation Pump Head, NPSH, and Efficiency vs. Flow Curves
5.4-4 Deleted 5.4-5 Operating Principle of Jet Pump 5.4-6 Core Flooding Capability of Recirculation System 5.4-7 Main Steamline Flow Restrictor 5.4-8 Main Steamline Isolation Valve
5.4-9 Deleted CPS/USAR CHAPTER 05 5-xi REV. 13, JANUARY 2009 5.4-10 Deleted 5.4-11 Vessel Coolant Temperature versus Time (Two Heat Exchangers Available) 5.4-12 Vessel Coolant Temperature versus Time (One Heat Exchanger Available) 5.4-13 Deleted 5.4-14 Deleted 5.4-15 RHR Pump Characteristic Curves
5.4-16 through Deleted
5.4-19 5.4-20 Recirculation System External Loop Piping Layout 5.4-21 One Pump Operation Map 5.4-22 Deleted 5.4-23 Power Supply Development "A" Recirculation Loop 5.4-24 Layout of Auxiliary Power System for Reactor Recirculation System Pump "A" CPS/USAR CHAPTER 05 5-xii REV. 13, JANUARY 2009 CHAPTER 5 - REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS DRAWINGS CITED IN THIS CHAPTER
- *The listed drawings are included as "General References" only; i.e., refer to the drawings to obtain additional detail or to obtain background information. These drawings are not part of the USAR. They are controlled by the Controlled Documents Program. DRAWING* SUBJECT 105D4952AC Reactor Water Cleanup 762E421AA Process Diagram Reactor Core Isolation Cooling 762E425AC Process Diagram Reactor Heat Removal 767E956 Bracket for Holding Surveillance Capsule 794E766AB Filter/Demineralization System 796E724 Nuclear Boiler System M01-1111 General Arrangement - Sections "C-C", "D-D", and "E-E" M01-1112 General Arrangement - Sections "F1-F1", "F2-F2", and "G-G" M05-1002 Main Steam M05-1004 Reactor Feedwater System M05-1041 Leakage Detection M05-1072 Reactor Recirculation System M05-1075 Residual Heat Removal System M05-1076 Reactor Water Cleanup System M05-1079 Reactor Core Isolation Cooling System CPS/USAR CHAPTER 05 5.1-1 REV. 11, JANUARY 2005 5.0 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. This chapter of the Updated Safety Analysis Report provides information regarding the reactor coolant system and pressure-containing appendages out to and including isolation valving. This grouping of components is defined as the reactor coolant pressure boundary (RCPB) as follows: Reactor coolant pressure boundary (RCPB) includes all pressure-containing components such as pressure vessels, piping, pumps, and valves, which are: (1) Part of the reactor coolant system, or (2) Connected to the reactor coolant system, up to and including any and all of the following: a. The outermost containment isolation valve in piping which penetrates primary reactor containment, b. The second of the two valves normally closed during normal reactor operation in system piping which does not penetrate primary reactor containment, c. The reactor coolant system safety/relief valve piping. This chapter also deals with various subsystems to the RCPB which are closely allied to it. Specifically, section 5.4 deals with these subsystems. The nuclear system pressure relief system protects the reactor coolant pressure boundary from damage due to overpressure. To protect against overpressure, pressure-operated relief valves are provided that can discharge steam from the nuclear system to the suppression pool. The pressure relief system also acts to automatically depressurize the nuclear system in the event of a loss-of-coolant accident in which the high pressure core spray (HPCS) system fails to maintain reactor vessel water level. Depressurization of the nuclear system allows the low pressure core cooling systems to supply enough cooling water to adequately cool the fuel. "Detection of Leakage Through Reactor Coolant Pressure Boundary," in subsection 5.2.5, establishes the limits on nuclear system leakage inside the drywell so that appropriate action can be taken before the integrity of the nuclear system process barrier is impaired. The reactor vessel and appurtenances are described in the "Reactor Vessel," section 5.3. The major safety consideration for the reactor vessel is the ability of the vessel to function as a radioactive material barrier. Various combinations of loading are considered in the vessel design. The vessel meets the requirements of applicable codes and criteria. The possibility of brittle fracture is considered, and suitable design, material selection, material surveillance activity and operational limits are established that avoid conditions where brittle fracture is possible.
CPS/USAR CHAPTER 05 5.1-2 REV. 11, JANUARY 2005 The reactor recirculation system provides coolant flow through the core. The recirculation system is designed to provide a slow coastdown of flow so that fuel thermal limits cannot be exceeded as a result of recirculation system malfunctions. The arrangement of the recirculation system routing is such that a piping failure cannot compromise the integrity of the floodable inner volume of the reactor vessel. The main steam line flow restrictors of the venturi-type are installed in each main steam line inside the primary containment. The restrictors are designed to limit the loss of coolant resulting from a main steam line break outside the primary containment. The coolant loss is limited so that reactor vessel water level remains above the top of the core during the time required for the main steam line isolation valves to close. This action protects the fuel barrier. Two isolation valves are installed on each main steam line; one is located inside, and the other is located outside the primary containment. In the event that a main steam line break occurs inside the containment, closure of the isolation valve outside the primary containment acts to seal the primary containment itself. The main steam line isolation valves automatically isolate the reactor coolant pressure boundary in the event a pipe break occurs downstream of the inboard isolation valves. This action limits the loss of coolant and the release of radioactive materials from the nuclear system. The reactor core isolation cooling (RCIC) system provides makeup water to the core during a reactor shutdown in which feedwater flow is not available. The system is started automatically upon receipt of a low reactor water level signal or manually by the operator. Water is pumped to the core by a turbine-pump driven by reactor steam. The residual heat removal (RHR) system includes a number of pumps and heat exchangers that can be used to cool the nuclear system under a variety of situations. During normal shutdown and reactor servicing, the RHR system removes residual and decay heat. The RHR system allows decay heat to be removed whenever the main heat sink (main condenser) is not available (e.g., hot standby). One mode of RHR oper ation allows the removal of heat from the primary containment following a loss of coolant accident. Another operational mode of the RHR system is low pressure coolant injection (LPCI). LPCI operation is an engineered safety feature for use during a postulated loss-of coolant accident. This operation is described in section 6.3, "Emergency Core Cooling Systems." The low pressure core spray system (LPCS) also provides protection to the nuclear system. The reactor water cleanup system recirculates a portion of reactor coolant through a filter-demineralizer to remove particulate and dissolved impurities from the reactor coolant. It also removes excess coolant from the reactor system under controlled conditions. Design and performance characteristics of the Reactor Coolant System and its various components will be found in Table 5.4-1. 5.1.1 Schematic Flow Diagram Schematic flow diagrams of the reactor coolant system denoting all major components, principal pressures, temperatures, flow rates, and coolant volumes for normal steady-state operating conditions at rated power are presented in Figures 5.1-1 and 5.1-2.
CPS/USAR CHAPTER 05 5.1-3 REV. 11, JANUARY 2005 5.1.2 Piping and Instrumentation Diagram Piping and instrumentation diagrams covering the systems included within the reactor coolant system and connected systems are presented in the following: (1) the nuclear boiler system shown on Drawing 796E724, (2) main steam shown on Drawing M05-1002; (3) feedwater shown on Drawing M05-1004; (4) recirculation system shown on Drawing M05-1072; (5) reactor core isolation cooling system shown on Drawing M05-1079; (6) residual heat removal system shown on Drawing M05-1075; (7) reactor water cleanup system shown on Drawing M05-1076. 5.1.3 Elevation Drawings Elevation drawings showing the principal dimensions of the reactor coolant system in relation to the supporting and surrounding concrete structures are shown in Drawings M01-1111-4 and
M01-1112-4.
CPS/USAR CHAPTER 05 5.2-1 REV. 11, JANUARY 2005 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 Compliance with the rules of 10 CFR Part 50 "Codes and Standards" is included in Table 3.2-4. Code edition, applicable addenda, and component dates are in accordance with 10 CFR
50.55a. 5.2.1.2 Applicable Code Cases The reactor pressure vessel and appurtenances, and the RCPB piping, pumps and valves, have been designed, fabricated, and tested in accordance with the applicable edition of the ASME Code, including addenda that were mandatory at the order date for the applicable components.
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 cases that were applied to components in the RCPB are listed in Table 5.2-1. A. Regulatory Guides 1.84 and 1.85 General Compliance or Alternative Approach Assessment:
For commitment, revision number, and scope see section 1.8. These guides provide a list of ASME Design and Fabrication Code Cases that have been generically approved by the Regulatory Staff. Code Cases on this list may, for design purposes, be used until appropriately annulled. Annulled cases are considered "active" for equipment that has been contractually committed to fabrication prior to the annulment.
GE's procedure for meeting the regulatory requirements is to obtain NRC approval for Code Cases applicable to Class 1 components only. NRC approval of Class 2 and 3 Code Cases was not required at the time of the design of Clinton and is not required by 10CFR50.55a. All class 2 and 3 equipment has been designed to ASME code or ASME approved Code Cases. This provision together with the Quality C ontrol programs provide adequate safety equipment functional assurances. 5.2.2 Overpressure Protection This section provides evaluation of the systems that protect the RCPB from overpressurization. 5.2.2.1 Design Basis Overpressure protection is provided in conformance with 10 CFR 50, Appendix A, General Design Criterion 15. Preoperational and startup instructions are given in Chapter 14.
CPS/USAR CHAPTER 05 5.2-2 REV. 11, JANUARY 2005 5.2.2.1.1 Safety Design Bases The nuclear pressure-relief system has been designed: (1) To prevent overpressurization of the nuclear system that could lead to the failure of the reactor coolant pressure boundary. (2) To provide automatic depressurization for small breaks in the nuclear system occurring with maloperation of the high pressure core spray (HPCS) system so that the low pressure coolant injection (LPCI) and the low pressure core spray (LPCS) systems can operate to protect the fuel barrier. (3) To permit verification of its operability.
(4) To withstand adverse combinations of loadings and forces resulting from normal, upset, emergency, or faulted conditions. 5.2.2.1.2 Power Generation Design Bases The nuclear pressure relief system safety/relief valves have been designed to meet the following power generation bases: (1) Discharge to the containment suppression pool.
(2) 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 requires that each vessel designed to meet Section III be protected from overpressure under upset conditions. The code allows a peak allowable pressure of 110% of vessel design pressure under upset conditions. The code specifications for safety valves require that: (1) the lowest safety valve be set at or below vessel design pressure and (2) the highest safety valve be set so that total accumulated pressure does not exceed 110% of the design pressure for upset conditions. The safety/relief valves are designed to open via either of two modes of operation: automatically using a pneumatic power actuator or by self-actuation in the spring lift mode. The safety/relief valve setpoints are listed in Table 5.2-2. These setpoints satisfy the ASME Code specifications for safety valves, because all valves open at less than the nuclear system design pressure of 1250 psig. The automatic depressurization capability of the nuclear system pressure relief system is evaluated in section 6.3, "Emergency Core Cooling Systems," and in section 7.3, "Engineered Safety Feature Systems." The following detailed criteria are used in selection of relief valves: (1) Must meet requirements of ASME Code,Section III; CPS/USAR CHAPTER 05 5.2-3 REV. 11, JANUARY 2005 (2) Must qualify for 100% of nameplate capacity credit for the overpressure protection function; (3) Must meet other performance requirements such as response time, etc., as necessary to provide relief functions. The safety/relief valve discharge piping is designed, installed, and tested in accordance with the ASME Code,Section III. 5.2.2.1.4 Safety Valve Capacity The safety valve capacity of this plant is adequate to limit the primary system pressure, including transients, to the requirements of the ASME Boiler and Pressure Vessel Code,Section III, Nuclear Power Plant Components, Division 1, 1971 Edition with Addenda up to and including Summer 1973. The essential ASME requirements which are all met by this analysis are as follows: It is recognized that the protection of vessels in a nuclear power plant is dependent upon many protective systems to relieve or terminate pressure transients. Installation of pressure relieving devices may not independent ly provide complete protection. The safety valve sizing evaluation assumes credit for operation of the scram protective system which may be tripped by either one of two sources; i.e., a direct or flux trip signal. The direct scram trip signal is derived from position switches mounted on the main steamline isolation valves or the turbine stop valves or from pressure switches mounted on the dump valve of the turbine control valve hydraulic actuation system. The position switches are actuated when the respective valves are closing and following 10% travel of full stroke. The pressure switches are actuated when a fast closure of the turbine control valves is initiated. Credit is taken for 50% of the total installed safety/relief valve capacity operating via the power operated mode as permitted by ASME III. Credit is also taken for the remaining safety/relief valve capacity which opens via the spring mode of operation direct from inlet pressure. The rated capaity of the pressure relieving devices shall be sufficient to prevent a rise in pressure within the protected vessel of more than 110% of the design pressure (1.10 x 1250 psig = 1375 psig) for events defined in subsection 15.2. Full account is taken of the pressure drop on both the inlet and discharge sides of the valves. All combination safety/relief valves discharge into the suppression pool through a discharge pipe from each valve which is designed to achieve sonic flow conditions through the valve, thus providing flow independence to discharge piping losses. Table 5.2-7 lists the systems which could initiate during the design basis overpressure event. 5.2.2.2 Design Evaluation 5.2.2.2.1 Method of Analysis To design the pressure protection for the nuclear boiler system, extensive analytical models representing all essential dynamic characteristics of the system are simulated on a large computing facility. These models include the hydrodynamics of the flow loop, the reactor CPS/USAR CHAPTER 05 5.2-4 REV. 11, JANUARY 2005 kinetics, the thermal characteristics of the fuel and its transfer of heat to the coolant, and all the principal controller features, such as feedwater flow, recirculation flow, reactor water level, pressure, and load demand. These are represented with all their principal nonlinear features in models that have evolved through extensive experience and fa vorable comparison of analysis with actual BWR test data. A detailed description of this model is documented in licensing topical report NEDO-10802, "Analytical Methods of Plant Transient Evaluations for the GE-BWR," R. B. Linford, (Reference 1). Safety/relief valves are simulated in a nonlinear representation, and the model thereby allows full investigation of the various valve response times, valve capacities, and actuation setpoints that are available in applicable hardware systems. Typical valve characteristics as modeled are shown in Figures 5.2-2A and 5.2-2B for the power-activated relief and spring-action safety modes of the dual purpose safety/relief valves. The associated bypass, turbine control valve, and main steam isolation valve characteristics are also simulated in the model. 5.2.2.2.2 Systems Design A parametric study was conducted to determine the required steam flow capacity of the safety/relief valves based on the following assumptions. 5.2.2.2.2.1 Operating Conditions Operating conditions for the initial cycle performance were as follows: (1) operating power = 3015 MWt (104.2% of nuclear boiler rated power),
(2) vessel dome pressure = 1045 psig, and (3) steamflow = 13.076 x 10 6 lb/hr (105% of nuclear boiler rated steamflow) Operating conditions for cycle performance with extended power uprate (EPU) are as follows: (1) operating power = 3543 MWt (102% of nuclear boiler rated power),
(2) vessel dome pressure less than or equal to 1045.3 psig, and (3) steam flow = 15.52 x 10 6 lb/hr (102% of nuclear boiler rated steamflow) These conditions are the most severe because maximum stored energy exists at these conditions. At lower power conditions the transients would be less severe. 5.2.2.2.2.2 Transients The overpressure protection system must accommodate the most severe pressurization transient. There are two major transients, the closure of all main steam line isolation valves and a turbine/generator trip with a coincident closure of the turbine steam bypa ss system valves that represent the most severe abnormal operational transients resulting in a nuclear system pressure rise. The evaluation of transient behavior with final plant configuration has shown that the isolation valve closure is slightly more severe when credit is taken only for indirect derived CPS/USAR CHAPTER 05 5.2-5 REV. 11, JANUARY 2005 scrams, therefore, it is used as the overpressure protection basis event and shown in Figure 5.2-1. Table 5.2-10 lists the sequence of events for the main steam line isolation valve closure event with flux scram (performed for the initial cycle) and with the installed safety/relief valve capacity. The transient response for the current reload cycle is provided in Appendix 15D, Reload Analysis. 5.2.2.2.2.3 Scram (1) scram reactivity curve - Figure 5.2-3A (2) control rod drive scram motion - Figure 5.2-3B 5.2.2.2.2.4 Safety/Relief Valve Transient Analysis Specification (1) simulated valve groups: power-actuated relief mode - 3 groups spring-action safety mode - 3 groups (2) pressure setpoint (maximum safety limit):
power-actuated relief mode group 1 1125 psig group 2 1135 psig group 3 1145 psig group 4 1155 psig spring action safety mode group 1 1175 psig group 2 1195 psig group 3 1215 psig The above analysis input set points are assumed at a conservatively high level above the normal set points. This is to account for initial set point errors and any instrument set point drift that might occur during operation. Typically the assumed set points in the analysis are 1 to 2 % above the actual nominal set points as shown in Table 5.2-2. High conservative safety relief/valve response characteristics are also assumed. 5.2.2.2.2.5 Safety/Relief Valve Capacity Sizing of the safety/relief valve capacity is based on establishing an adequate margin from the peak vessel pressure to the vessel code limit (1375 psig) in response to the reference
transients. The method used to determine total valve capacity is described as follows: Whenever system pressure increases to the relief pressure set point of a group of valves having the same set point, half of those valves are assumed to operate in the relief CPS/USAR CHAPTER 05 5.2-6 REV. 11, JANUARY 2005 mode, opened by the pneumatic power actuation. When the system pressure increases to the valve spring set pressure of a group of valves, those valves not already considered open are assumed to begin opening and to reach full open at 103% of the valve spring set pressure. 5.2.2.2.3 Evaluation of Results 5.2.2.2.3.1 Safety/Relief Valve Capacity For the evaluation of SRV safety-mode setpoint tolerance relaxation to +/-3% and 2 SRV's out-of-service, refer to Reference 8. Note that the information provided in this chapter is from baseline analysis performed in support of initial cycle operation. The required safety/relief valve capacity is determined by analyzing the pressure rise from a MSIV closure with flux scram transient. The plant is assumed to be operating at the turbine-generator design conditions at a maximum vessel dome pressure of 1045 psig. The analysis hypothetically assumes the failure of the direct isolation valve position scram. The reactor is shut down by the backup, indirect, high neutron flux scram. For the initial cycle analysis, the power-actuated relief set points of the safety/relief valve are assumed to be in the range of 1125 to 1155 psig and the spring-action safety set points to be in the range of 1175 to 1215 psig. The analysis indicates that the design valve capacity is capable of maintaining adequate margin below the peak ASME code allowable pressure in the nuclear system (1375 psig). Figure 5.2-1 shows curves produced by this initial cycle analysis (Reference 6). The sequence of events in Table 5.2-10 assumed in this initial cycle analysis was investigated to meet code requirements and to evaluate the pressure relief system exclusively. The results of the overpressurization analysis for the current cycle are pr ovided in Appendix 15D, Reload Analysis.
Under the General Requirements for Protection Against Overpressure as given in section III of the ASME Boiler and Pressure Vessel Code, credit can be allowed for a scram from the reactor protection system. In addition, credit is also taken for the protective circuits which are indirectly derived when determining the required safety/relief valve 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 safety/relief valves. Application of the direct position scrams in the design basis could be used since they qualify as acceptable pressure protection devices when determining the required safety/relief valve capacity of nuclear vessels under the provisions of the ASME code. The safety/relief valves are operated in a relief mode (pneumatically) at set points lower than those specified for the safety function. This ensures sufficient margin between anticipated relief mode closing pressures and valve spring forces for proper seating of the valves. The parametric relationship between peak vessel (bottom) pressure and safety/relief valve capacity for the MSIV transient with high flux scram is described in Figure 5.2-4. Also shown in Figure 5.2-4 is the parametric relationship between peak vessel (bottom) pressure and safety/relief valve capacity for the generator load rejection with a coincident closure of the turbine bypass valves and direct scram, which is the most severe transient when direct scram is considered. Pressures shown for flux scram will result only with multiple failure in the redundant direct scram system. The time response of the vessel pressure to the MSIV transient with flux scram and the generator load rejection with a coincident closure of the turbine bypass valves and direct scram for 16 valves is illustrated in Figure 5.2-5. This shows that the pressure at the vessel bottom CPS/USAR CHAPTER 05 5.2-7 REV. 11, JANUARY 2005 exceeds 1250 psig for less than 5 seconds which is not long enough to transfer any appreciable amount of heat into the vessel metal which was at a temperature well below 550°F at the start of the transient. 5.2.2.2.3.2 Low-Low Set Relief Function In order to assure that no more than one relief valve reopens following a reactor isolation event, two valves are provided with lower opening and closing setpoints and three valves with lower closing setpoints. On initial relief mode actuation of any safety/relief valve (SRV), these setpoints override the normal setpoints and act to hold open these valves longer, thus preventing more than a single valve from reopening subsequently. This system logic is referred to as the low-low set relief logic and functions to ensure that the containment design basis of one safety/relief valve operating on subsequent actuations is met. The low-low set logic is armed from the existing pressure sensors of the low normal relief setpoint SRV or the second normal relief setpoint group of SRVs or the high normal relief setpoint group of SRVs. Thus, the low-low set valves will not actuate during normal plant operation even though the reopening setpoints of one of the valves is in the normal operating pressure range. This arming method results in the low-low set safety/relief valves opening initially during an overpressure transient at the normal relief opening setpoint. The lowest setpoint low-low set valve will cycle to remove decay heat. Table 5.2-2 shows the opening and closing setpoints for the low-low set safety/relief valves. The assumptions used in the calculation of the pressure transient after the initial opening of the relief valves are: a. The transient event is a 3-second closure of all MSIV's with position scram.
- b. Nominal relief valve setpoints are used. c. The maximum expected relief capacity is used. d. Relief valve opening times shown in Figure 5.2-7b are used.
- e. The closing setpoint of the relief valves is 100 psi below the opening setpoint.
- f. ANS + 20% decay heat at infinite exposure is used. The results using the above assumptions are shown in the reactor vessel pressure transient curve in Figure 5.2-7a. Despite the conservative input assumptions which tend to maximize the pressure peaks on subsequent actuations, there is a 72 psi margin for avoiding the second pop of more than one valve. The system is single failure proof since a failure of one of the low-low set valves still gives a 40 psi margin for avoiding multiple valve actuations. See Table 5.2-2 for the setpoints of the low-low set valves. The safety/relief valves are balanced, spring loaded, and provided with an auxiliary power-actuated device which allows opening of the valve even when pressure is less than the safety-set pressure on the valve. Previous undesirable performance on operating BWR's was associated principally with multiple stage pilot operated safety/relief valves shown in Figure 5.2-15. These newer, power-operated safety/relief valves employ significantly fewer moving parts wetted by the steam and are, therefore, considered an improvement over the ones previously used.
CPS/USAR CHAPTER 05 5.2-8 REV. 11, JANUARY 2005 5.2.2.2.3.3 Pressure Drop in Inlet and Discharge Pressure drop on the piping from the reactor vessel to the valves is taken into account in calculating the maximum vessel pressures. Pressure drop in the discharge piping to the suppression pool is limited by proper discharge line sizing to prevent backpressure on each safety/relief valve from reducing valve capacity below the nameplate rating due to the discharge piping. Each safety/relief valve has its own separate discharge line. 5.2.2.3 Piping & Instrument Diagrams The schematic arrangements of the pressure - relieving devices for the reactor coolant system, which are the safety/relief valves, are shown in Drawing 796E724, sheet 6, and Figure 5.2-8. The schematic representation of the blowdown/heat dissipation system connected to the discharge side of these pressure relieving devices is shown on Drawing M05-1002, sheet 6. 5.2.2.4 Equipment and Component Description 5.2.2.4.1 Description The nuclear pressure relief system consists of safety/relief valves located on the main steam lines between the reactor vessel and the first isolation valve within the drywell. These valves protect against overpressure of the nuclear system.
The safety/relief valves provide three main protection functions: (1) Overpressure relief operation. The valves open automatically to limit a pressure rise. (2) Overpressure safety operation. The valves function as safety valves and open (self-actuated operation if not already automatically opened for relief operation) to prevent nuclear system overpressurization. (3) Depressurization operation. The ADS valves open automatically as part of the emergency core cooling system (ECCS) for events involving small breaks in the nuclear system process barrier. The location and number of the ADS valves can be determined from Drawing 796E724, sheet 6. Chapter 15 discusses the events which are expected to activate the primary system safety/relief valves. The section also summarizes the number of valves expected to operate during the initial blowdown of the valves and the expected duration of this first blowdown. For several of the events it is expected that the lowest set safety/relief valve will reopen and reclose as generated heat drops into the decay heat characteristics. The pressure increase and relief cycle will continue with lower frequency and shorter relief discharges as the decay heat drops off and until such time as the RHR system can dissipate this heat. Remote manual actuation of the valves from the control room is recommended to minimize the total number of these discharges, with the intent of achieving extended valve seat life. A schematic of the safety/relief valve is shown in Figure 5.2-10. It is opened by either of two modes of operation:
CPS/USAR CHAPTER 05 5.2-9 REV. 11, JANUARY 2005 (1) The spring mode of operation which consists of direct action of the steam pressure against a spring-loaded disk that will pop open when the valve inlet pressure force exceeds the spring force. (2) 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 arranged that if it malfunctions it will not prevent the valve disk from lifting if steam inlet pressure reaches the spring lift set pressure. For overpressure safety relief valve operation (self-actuated or spring lift mode), the spring load establishes the safety valve opening setpoint pressure and is set to open at setpoints designated in Table 5.2-2. In accordance with the ASME code, the full lift of this mode of operation is attained at a pressure no greater than 3% above the setpoint. The safety function of the safety/relief valve is a backup to the relief function described below. The spring-loaded valves are designed and constructed in accordance with ASME III, NB 7640 as safety valves with auxiliary actuating devices. For overpressure relief valve operation (power actuated mode), each valve is provided with a pressure sensing device which operates at the setpoints designated in Table 5.2-2. When the set pressure is reached, it operates a solenoid air valve which in turn actuates the pneumatic piston/cylinder and linkage assembly to open the valve. When the piston 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 0.1 seconds. The maximum elapsed time between signal to actuator and full open position of valve will not exceed 0.2 seconds. The safety/relief valves can be operated in the power actuated mode by remote-manual controls from the main control room. Actuation of either solenoid A or solenoid B on the safety/relief valve will cause the safety/relief valve to open, hence, there is no single failure of a logic component or safety/relief valve solenoid valve which would result in failure of the main valve to open. The trip units, see Drawing 796E724, for each safety/relief valve within each division are in series, and failure of one of the transmitters shown on Drawing 796E724 will not cause the safety/relief valves to open. Each safety/relief valve is provided with its own pneumatic accumulator and inlet check valve. The accumulator capacity is sufficient to provide one safety/relief valve actuation, which is all that is required for overpressure protection. Subsequent actuations for an overpressure event can be spring actuations to limit reactor pressure to acceptable levels.
CPS/USAR CHAPTER 05 5.2-10 REV. 11, JANUARY 2005 The safety/relief valves are qualified to operate to the extent required for overpressure protection in the following accident environments*: (1) 340ºF for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> at drywell pressure 45 psig (2) 320ºF for an additional 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> period, at drywell pressure 45 psig (3) 250ºF for an additional 18 hour2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> period, at 25 psig (4) Then the duration of operability is 2 days at 200° F and 20 psig, following which the valves will remain fully closed for 97 days or fully open provided air and power supply is available. The Automatic Depressurization System (ADS) utilizes selected safety/relief valves for depressurization of the reactor as described in Section 6.3, "Emergency Core Cooling System." Each of the safety/relief valves utilized for automatic depressurization is equipped with an air accumulator and check valve arrangement. The ADS pneumatic supply is split into two divisions. One supplies to the ADS valves on steamlines "A" and "C"; the other supplies to the ADS valves on steamlines "B" and "D". The air supply piping and equipment for the safety/relief valves from the inside containment isolation valve to the accumulators is designed to the requirements of ASME section III class 3 and is Seismic Category I. The air supply from the outside containment isolation valve to the air bottle tank farm is Seismic Cat. I, class 3 except for the air bottle tank farm and air filter which are Seismic Category I, class other. The air bottles are designed to DOT Specification 3AA requirements. The accumulators and air bottle tank farms assure that the valves can be held open following failure of the normal air supply to the accumulators. They are sized to be capable of opening the valves and holding them open against the drywell design pressure of 30 psig. The accumulator capacity is sufficient for each ADS valve to provide two actuations against 70% of drywell design pressure (21 psig). The capacity of the air bottle tank farms is sufficient to account for system leakage in order to allow
the valves to remain open for a minimum period of 2 days without replenishment. If the non-safety-related air supply is unavailable for longer than 2 days, the air bottles and accumulators can be recharged via a connection outside the south wall of the Diesel Generator building. Each safety/relief valve discharges steam through a discharge line to a point below the minimum water level in the suppression pool. The safety/relief valve discharge lines are classified as Quality Group C and Seismic Category I. Safety/relief valve discharge line piping from the safety/relief valve to the suppression pool consists of two parts. The first is attached at one end to the safety/relief valve and attached at its other end to a pipe anchor. The main steam piping, including this portion of the safety/relief valve discharge piping, is analyzed as a complete system. The second part of the safety/relief valve discharge piping extends from the anchor to the suppression pool. Because of the upstream 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.
- The qualification environments have an additional conservatism over the predicted worst-case environments given in Table 3.11-6 because of the desired general applicability to both BWR5 and BWR6 safety/relief valves.
CPS/USAR CHAPTER 05 5.2-11 REV. 11, JANUARY 2005 As a part of the preoperational and startup testing of the main steam lines, movement of the safety/relief valve discharge lines was monitored. The safety/relief valve discharge piping is designed to limit valve outlet pressure to 40% of maximum valve inlet pressure with the valve wide open. Water in the line more than a few feet above suppression pool water level would cause excessive pressure at the valve discharge when the valve is again opened. For this reason , two vacuum relief valves are provided on each safety/relief valve discharge line to prevent drawing an excessive amount of water up into the line as a result of steam condensation following termination of relief operation. The safety/relief valves are located on the main steam line piping, rather than on the reactor vessel top head, primarily to simplify the discharge piping to the pool and to avoid the necessity of having to remove sections of this piping when the reactor head is removed for refueling. In addition, valves located on the steam lines are more accessible during a shutdown for valve
maintenance. The nuclear pressure relief system automatically depressurizes the nuclear system sufficiently to permit the LPCI and LPCS systems to operate as a backup for the high pressure core spray (HPCS) system. Further descriptions of the operation of the automatic depressurization feature are found in section 6.3, "Emergency Core Cooling Systems," and in subsection 7.3.1.1.1, "Emergency Core Cooling Systems In strumentation and Controls." 5.2.2.4.2 Design Parameters The specified operating transients for components within the RCPB are given in subsection 3.9.1. Refer to section 3.7 for discussion of the input criteria for design of Seismic Category I structures, systems, and components. The design requirements established to protect the principal components of the reactor coolant system against environmental effects are discussed in section 3.11. 5.2.2.4.2.1 Safety/Relief Valve The discharge area of the valve is 18.4 square inches and the coefficient of discharge K(D) is equal to 0.873 (K = 0.9 K(D)). The design pressure and temperature of the valve inlet and outlet are 1375 psig @ 585°F and 625 psig @ 500°F, respectively. The valves have been designed to achieve the maximum practical number of actuations consistent with state-of-the-art technology. The safety/relief valves and appurtenances are designed to withstand 60 operating cycles at design temperature and pressure during each time period between valve refurbishing. See Figure 5.2-10 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 header. The mounting consists of a special contour nozzle and an over-sized flange connection. This provides a high CPS/USAR CHAPTER 05 5.2-12 REV. 11, JANUARY 2005 integrity connection that withstands the thrust, bending and torsional loadings to which the main steam pipe and relief valve discharge pipe are subjected. This includes: (1) The thermal expansion effects of the connecting piping.
(2) The dynamic effects of the piping due to SSE. (3) The reactions due to transient unbalanced wave forces exerted on the safety/relief valves during the first few seconds after the valve is opened and prior to the time steady-state flow has been established. (With steady-state flow, the dynamic flow reaction forces will be self-equilibrated by the valve discharge piping.) (4) The dynamic effects of the piping and branch connection due to the turbine stop valve closure. In no case are allowable valve flange loads exceeded nor does the stress at any point in the piping exceed code allowables for any specified combination of loads. The design criteria and analysis methods for considering loads due to SRV discharge is contained in subsection
3.9.3.3. 5.2.2.6 Applicable Codes and Classification The vessel overpressure protection system is designed to satisfy the requirements of Section III of the ASME Boiler and Pressure Vessel Code. The general requirements for protection against overpressure of Section III of the Code recognize that reactor vessel overpressure protection is one function of the reactor protective systems and allows the integration of pressure relief devices with the protective systems of the nuclear reactor. Hence, credit is taken for the scram protective system as a complementary pressure protection device. The NRC has also adopted the ASME Codes as part of their requirements in the Code of Federal Regulations (10 CFR 50.55A). 5.2.2.7 Material Specification Material specifications of pressure retaining components of safety/relief valves are reported in Table 5.2-4. 5.2.2.8 Process Instrumentation Overpressure protection process instrumentation is shown on the P&ID 796E724. 5.2.2.9 System Reliability The system is designed to satisfy the requirements of Section III of the ASME Boiler & Pressure Vessel Code. Therefore, it has high reliability. The consequences of failure are discussed in Section 15.1.4 and 15.6.1. 5.2.2.10 Inspection and Testing The inspection and testing applicable to safety/relief valves utilizes a quality assurance program which complies with Appendix B of 10 CFR 50.
CPS/USAR CHAPTER 05 5.2-13 REV. 13, JANUARY 2009 The safety/relief valves are tested at the vendor's shop in accordance with quality control procedures to detect defects and to prove operability prior to installation. The following tests are
conducted: (1) Hydrostatic test at specified test conditions. (2) Seat leakage measurements are made with steam during the set pressure test. (3) Set pressure test: valve pressurized with saturated steam, with the pressure rising to the valve set pressure. Valve must open at nameplate set pressure +/-3%. (4) Response time test: each safety/relief valve tested to demonstrate acceptable response time. The valves are installed as received from the factory. The GE equipment specification requires certification from the valve manufacturer that design and performance requirements have been met. This includes capacity and blowdown requirements. The set points are adjusted, verified, and indicated on the valves by the vendor. Specified manual and automatic actuation relief mode of each safety/relief valve was verified during the preoperational test program. It is not feasible to test the safety/relief valve set points while the valves are in place. The valves are mounted on 1500-lb primary service rating flanges. They can be removed for maintenance or bench checks and reinstalled during normal plant shutdowns. The valves will be tested to check set pressure in accordance with the requirements of the plant technical specifications. The external surface and seating of all safety/relief valves are 100% visually inspected when the valves are removed for maintenance or bench checks. Valve operability was verified during the preoperational test program as discussed in Chapter 14. 5.2.3 Reactor Coolant Pressure Boundary Materials 5.2.3.1 Material Specifications Table 5.2-4 lists the principal pressure retaining materials and the appropriate material specifications for the reactor coolant pressure boundary components. 5.2.3.2 Compatibility with Reactor Coolant 5.2.3.2.1 PWR Chemistry of Reactor Coolant Not applicable to BWRs. 5.2.3.2.2 BWR Chemistry of Reactor Coolant Materials in the primary system are primarily austenitic stainless steel and Zircaloy cladding. The reactor water chemistry limits are established to provide an environment favorable to these materials. Limits are placed on conductivity and chloride concentrations. Conductivity is limited because it can be continuously and reliably measured and gives an indication of abnormal conditions and the presence of unusual materials in the coolant. Chloride limits are specified to prevent stress corrosion cracking of stainless steel. For further information, see Reference 2.
CPS/USAR CHAPTER 05 5.2-14 REV. 11, JANUARY 2005 Several investigations have shown that in neutral solutions some oxygen is required to cause stress corrosion cracking of stainless steel, while in the absence of oxygen no cracking occurs. One of these is the chloride-oxygen relationship of Williams, (Reference 3), where it is shown that at high chloride concentration little oxygen is required to cause stress corrosion cracking of stainless steel, and at high oxygen concentration little chloride is required to cause cracking. These measurements were determined in a wetting and drying situation using alkaline-phosphate-treated boiler water and, therefore, are of limited significance to BWR conditions.
They are, however a qualitative indication of trends. The water quality requirements are further supported by General Electric stress corrosion test data summarized as follows: (1) Type 304 stainless steel specimens were exposed in a flowing loop operating at 537°F. The water contained 1.5 ppm chloride and 1.2 ppm oxygen at pH 7. Test specimens were bent beam strips stressed over their yield strength. After 2100 hours0.0243 days <br />0.583 hours <br />0.00347 weeks <br />7.9905e-4 months <br /> exposure, no cracking or failures occurred. (2) Welded Type-304 stainless steel specimens were exposed in a refreshed autoclave operating at 550°F. The water contained 0.5 ppm chloride and 1.5 ppm oxygen at pH 7. Uniaxial tensile test specimens were stressed at 125% of their 550°F yield strength. No cracking or failures occurred at 15,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />
exposure. When conductivity is in its normal range, pH, chloride and other impurities affecting conductivity will also be within their normal range. When conductivity becomes abnormal, chloride measurements are made to determine whether or not they are also out of their normal operating values. This would not necessarily be the case. Conductivity could be high due to the presence of a neutral salt which would not have an effect on pH or chloride. In such a case, high conductivity alone is not a cause for shutdown. In some types of water-cooled reactors, conductivities are high because of the purposeful use of additives. In BWRs, however, where no additives are used and where near neutral pH is maintained, conductivity provides a good and prompt measure of the quality of the reactor water. Significant changes in conductivity provide the operator with a warning mechanism so he can investigate and remedy the condition before reactor water limits are reached. Methods available to the operator for correcting the off-standard condition include operation of the reactor cleanup system, reducing the input of impurities, and placing the reactor in the cold shutdown condition. The major benefit of cold shutdown is to reduce the temperature dependent corrosion rates and provide time for the cleanup system to reestablish the purity of the reactor coolant. The following is a summary and description of BWR water chemistry for various plant conditions. (1) Normal Plant Operation The BWR system water chemistry is conveniently described by following the system cycle as shown on Figure 5.2-11. Reference to Table 5.2-6 has been made as numbered on the diagram and correspondingly in the table. For normal operation starting with the condenser-hotwell, condensate water is processed through a condensate treatment system. This process consists of CPS/USAR CHAPTER 05 5.2-15 REV. 11, JANUARY 2005 filtration and demineralization, resulting in effluent water quality represented in Table 5.2-6. Hydrogen is injected into the condensate booster pump suction header to mitigate intergranular stress corrosion cracking in the reactor vessel internals and recirculation piping. The Hydrogen Water Chemistry (HWC) system is described in Section 5.4.15. The effluent from the condensate treatment system is pumped through the feedwater heater train, and enters the reactor vessel at an elevated temperature and with a chemical composition typically as shown in Table 5.2-6. A small amount of depleted zinc oxide (DZO) is injected into the feedwater during normal operation via the General Electric zinc injection passivation (GEZIP) system. The system consists of a simple passive recirculation loop off the feedwater piping. A stream of feedwater from the feedwater pump discharge is passed through the GEZIP skid zinc disolution column which contains pelletized DZO. The feedwater dissolves the pellets as it passes through the zinc vessel carrying the dissolved DZO back into the feedwater pump suction. This process maintains trace quantities of ionic zinc in the reactor water for the purpose of reducing radiation buildup on the primary system surfaces. During normal plant operation, boiling occurs in the reactor, decomposition of water takes place due to radiolysis, and oxygen and hydrogen gases are formed.
Due to steam generation, stripping of these gases from the water phase takes place, and the gases are carried with the steam through the turbine to the condenser. The oxygen level in the steam, resulting from this stripping process, is typically observed to be about 20 ppm (see Table 5.2-6). At the condenser, deaeration takes place and the gases are removed from the process by means of steam jet air ejectors (SJAEs). The deaeration is completed to a level of approximately 20 ppb (0.02 ppm) oxygen in the condensate and oxygen injection is provided to maintain this level. The dynamic equilibrium in the reactor vessel water phase established by the steam-gas stripping and the radiolytic formation (principally) rates, corresponds to a nominal value of approximately 200 ppb (0.2 ppm) of oxygen at rated operating conditions. Slight variations around this value have been observed as a result of differences in neutron flux density, coreflow and recirculation flow rate. A reactor water cleanup system is provided for removal of impurities resulting from fission products and corrosion products formed in the primary system. The cleanup process consists of filtration and ion exchange, and serves to maintain a high level of water purity in the reactor coolant. Typical chemical parametric values for the reactor water are listed in Table 5.2-6 for various plant conditions. Additional water input to the reactor vessel originates from the Control Rod Drive (CRD) cooling water. The CRD water is approximately feedwater quality. Separate filtration for purification and removal of insoluble corrosion products CPS/USAR CHAPTER 05 5.2-16 REV. 11, JANUARY 2005 takes place within the CRD system prior to entering the drive mechanisms and reactor vessel. No other inputs of water are present during normal plant operation. During plant conditions other than normal operation additional inputs and mechanisms are present as outlined in the following section. (2) Plant Conditions Outside Normal Operation During periods of plant conditions other than normal power production, transients take place, particularly with regard to the oxygen levels in the primary coolant.
Oxygen levels in the primary coolant will vary from the normal during plant startup, plant shutdown, hot standby , and when the reactor is vented and depressurized. The hotwell condensate will absorb oxygen from the air when vacuum is broken on the condenser. Prior to startup and input of feedwater to the reactor, vacuum is established in the condenser and deaeration of the condensate takes place by means of mechanical vacuum pump and steam jet air ejector (SJAE) operation and condensate recirculation. During these plant
conditions, continuous input of control rod drive (CRD) cooling water takes place as described previously. a. Plant Depressurized and Reactor Vented During certain periods such as during refueling and maintenance outages, the reactor is vented to the condenser or atmosphere. Under these circumstances the reactor cools and the oxygen concentration increases to a maximum value of 8 ppm. Equilibrium between the atmosphere above the reactor water surface, the CRD cooling water input, any residual radiolytic effects, and the bulk reactor water will be established after some time. No other changes in water chemistry of significance take place during this plant condition because no appreciable inputs take place. b. Plant Transient Conditions - Plant Startup/Shutdown During these conditions, no significant changes in water chemistry other than oxygen concentration take place. 1) Plant Startup Depending on the duration of the plant shutdown prior to startup and whether the reactor has been vented, the oxygen concentration could be that of air saturated water, i.e., approximately 8 ppm oxygen. Following nuclear heatup initiation, the oxygen level in the reactor water will decrease rapidly as a function of water temperature increase and corresponding oxygen solubility in water. The oxygen level will reach a minimum of about 20 ppb (0.02 ppm) at a coolant temperature of about 380°F, at which point an increase will take place due to significant radiolytic oxygen generation. For CPS/USAR CHAPTER 05 5.2-17 REV. 11, JANUARY 2005 the elapsed process up to this point the oxygen is degassed from the water and is displaced to the steam dome above the water
surface. Further increase in power increases the oxygen generation as well as the temperature. The solubility of oxygen in the reactor water at the prevailing temperature controls the oxygen level in the coolant until rated temperature (540°F) is reached. Thus, a gradual increase from the minimum level of 20 ppb to a maximum value of about 200 ppb oxygen takes place. At, and after this point (540°F) steaming and the radiolytic process control the coolant oxygen concentration to a level of around 200 ppb. 2) Plant Shutdown Upon plant shutdown following power operation, the radiolytic oxygen generation essentially ceases as the fission process is terminated. Because oxygen is no longer generated, while some steaming still will take place due to residual energy, the oxygen concentration in the coolant will decrease to a minimum value determined by steaming rate temperature. If venting is performed, a gradual increase to essentially oxygen saturation at the coolant temperature will take place, reaching a maximum value of <8 ppm
oxygen. 3) Oxygen in Piping and Parts Other Than the Reactor Vessel Proper As can be concluded from the preceding descriptions, the maximum possible oxygen concentration in the reactor coolant and any other directly related or associated parts is that of air saturation at ambient temperature. At no time or location, in the water phase, will oxygen levels exceed the nominal value of 8 ppm. As temperature is increased and hence, oxygen solubility decreased accordingly, the oxygen concentration will be maintained at this maximum value, or reduced below it depending on available removal mechanisms, i.e., diffusion, steam stripping, flow transfer or degassing. Depending on the location, configuration, etc., such as dead legs or stagnant water, inventories may contain 8 ppm dissolved oxygen or some other value below this maximum limitation. Conductivity of the reactor coolant is continuously monitored. Conductivity instruments are connected to redundant sources: the reactor water recirculation loop and the reactor water cleanup system inlet. The effluent from the reactor water cleanup system is also monitored for conductivity on a continuous basis. These measurements provide reasonable assurance for adequate surveillance of the reactor coolant.
CPS/USAR CHAPTER 05 5.2-18 REV. 11, JANUARY 2005 Grab samples are provided, for the locations shown on Table 5.2-8, for special and noncontinuous measurements such as pH, oxygen, chloride and radiochemical measurements. The relationship of chloride concentration to specific conductance measured at 25°C for chloride compounds such as sodium chloride and hydrochloric acid can be calculated, as shown on Figure 5.2-12. 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 imposed on the condensate, condensate treatment system and feedwater by warranty requirements and specifications. Thus, a total plant water quality surveillance program is established providing assurance that off specification conditions will quickly be detected and
corrected. The sampling frequency when reactor water has a low specific conductance is adequate for calibration and routine audit purposes. When specific conductance increases, and higher chloride concentrations are possible, or when continuous conductivity monitoring is unavailable, increased sampling is provided. (See the Operational Requirements
Manual (ORM)). For the higher than normal limits of <1
µmho/cm, more frequent sampling and analyses are invoked by the coolant chemistry surveillance program. The primary coolant conductivity monitoring instrumentation, ranges, accuracy sensor and indicator locations are shown in Table 5.2-8. The sampling is coordinated in a reactor sample station especially designed with constant temperature control and sample conditioning and flow control equipment. c. Water Purity During a Condenser Leakage The condensate cleanup system is designed to maintain the reactor water chloride concentration below 200 ppb during a condenser tube leak of 50 gallons per minute for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. To protect against a major condenser tube leak, ion exchange capacity of 50 percent of theoretical is maintained during normal
operation. A. Regulatory Guide 1.56 General Compliance or Alternative Approach Assessment:
For commitment, revision number, and scope see section 1.8.
CPS/USAR CHAPTER 05 5.2-19 REV. 11, JANUARY 2005 This guide describes an acceptable method of implementing GDC 13, 14, 15, and 31 of 10CFR50 Appendix A with regard to minimizing the probability of corrosion-induced failure of the RCPB in BWR's by maintaining acceptable purity levels in the reactor coolant, and acceptable instrumentation to determine the condition of the reactor coolant. As previously mentioned, the materials in the primary system are primarily austenitic stainless steel and Zircaloy cladding. The reactor water chemistry limits have been established to
provide an environment favorable to these materials. Design Engineering and Operational Requirements Manual limits are placed on conductivity and chloride concentrations.
Operationally, the conductivity is limited because it can be continuously and reliably measured and gives an indication of abnormal conditions and the presence of unusual materials in the coolant. Chloride limits are specified to prevent stress corrosion cracking of stainless steel. The water quality requirements are further supported by General Electric topical report NEDO-10899, Reference 2. 5.2.3.2.3 Compatibility of Construction Materials with Reactor Coolant The materials of construction exposed to the reactor coolant consist of the following: (1) Solution annealed austenitic stainless steels (both wrought and cast) Types 304, 304L, 316 and 316L. (2) Nickel base alloys - Inconel 600 and Inconel 750X.
(3) Carbon steel and low alloy steel.
(4) Some 400 series martensitic stainless steel (all tempered at a minimum of 1100°F). (5) Colmonoy Stellite or any other material that has been shown by an engineering evaluation to have similar resistance to stress corrosion and general corrosion can be used as hard facing material. All of these materials of construction are resistant to stress corrosion in the BWR coolant. General corrosion on all materials, except carbon and low alloy steel, is negligible.
Conservative corrosion allowances are provided for all exposed surfaces of carbon and low alloy steels. Contaminants in the reactor coolant are controlled to very low limits by the reactor water quality specifications. No detrimental effects will occur on any of the materials from allowable contaminant levels in the high purity reactor coolant. Expected radiolytic products in the BWR coolant have no adverse effects on the construction materials. 5.2.3.2.4 Compatibility of Construction Materials with External Insulation and Reactor Coolant Metallic insulation normally is applied to the reactor coolant pressure boundary and austenitic stainless steel piping inside the containment. Some mass type insulation, amounting to less than 1% of the square footage of insulation, is employed on these surfaces. Where mass type CPS/USAR CHAPTER 05 5.2-20 REV. 11, JANUARY 2005 insulation is used, it is completely encased in steel sheeting or inside a booted penetration seal. Therefore there is no problem of compatibility with construction materials. 5.2.3.3 Fabrication and Processing of Ferritic Materials 5.2.3.3.1 Fracture Toughness 5.2.3.3.1.1 Compliance with Code Requirements (1) The ferritic materials used for piping, pumps, and valves of the reactor coolant pressure boundary are 2-1/2 inches or less in thickness. Impact testing was performed in accordance with NB-2332 for thicknesses of 2-1/2 inches or less. (2) Materials for bolting with nominal diameters exceeding one inch was required to meet both the 25 mils lateral expansion specified in NB-2333 and the 45 ft.-lb Charpy V value specified in Appendix G of 10 CFR 50. (3) The reactor vessel complies with the requirements of NB-2331. The reference temperature, RT NDT, has been established for all required pressure retaining materials used in the construction of Class I vessels. This includes plates, forgings, weld material, and heat affected zone. The RT NDT differs from the nil-ductility temperature, NDT, in that in addition to passing the drop test, three Charpy-V-Notch specimens (traverse) must exhibit 50 ft-lbs absorbed energy and 35 mil lateral expansion at 60°F above the RTNDT. The core beltline material must meet 75 ft-lbs absorbed upper shelf energy. 5.2.3.3.2 Control of Welding 5.2.3.3.2.1 Control of Preheat Temperature Employed for Welding of Low Allow Steel.
Regulatory Guide 1.50 A. Regulatory Guide 1.50 General Compliance or Alternate Approach Assessment:
For commitment, revision number, and scope see section 1.8. This guide delineates preheat temperature control requirements and welding procedure qualifications supplementing those in ASME Sections III and IX. The use of low alloy steel was initially restricted to the reactor pressure vessel. Other ferritic components in the reactor coolant pressure boundary were initially fabricated from carbon steel materials. During plant construction the use of low-alloy steel was restricted to the reactor pressure vessel. For fabrication of the reactor pressure vessel welding preheat control complied with Regulatory Guide 1.50. Low-alloy steels were not used on the remainder of the reactor coolant pressure boundary (RCPB) during plant construction, therefore, control of preheat temperature for welding as required by Regulatory Guide 1.50 was not applicable to those portions of the RCPB at that time. Monitoring of plant operation has revealed certain sections of piping to be susceptible to Flow Accelerated Corrosion (FAC). Low-alloy steels, such as 21/4 Cr - 1 Mo, may be used as repair/replacement materials in these piping sections. Where low-alloy steel is used the requirements of Regulatory Guide 1.50 for control of welding preheat temperature will be complied with.
CPS/USAR CHAPTER 05 5.2-21 REV. 11, JANUARY 2005 Preheat temperatures employed for welding of low alloy steel meet or exceed the recommendations of ASME section III, subsection NA. Components were either held for an
extended time at preheat temperature to assure removal of hydrogen, or preheat was maintained until post weld heat treatment. The minimum preheat and maximum interpass temperatures were specified and monitored. All welds were nondestructively examined by radiographic methods. In addition, a supplemental ultrasonic examination was performed. 5.2.3.3.2.2 Control of Electroslag Weld Properties. Regulatory Guide 1.34 No electroslag welding was performed on BWR components.
5.2.3.3.2.3 Welder Qualification for Areas of Limited Accessibility. Regulatory Guide 1.71. Qualification for areas of limited accessibility is discussed in section 5.2.3.4.2.3.
5.2.3.3.3 Nondestructive Examination of Ferritic Tubular Products. Regulatory Guide 1.66.
A. Regulatory Guide 1.66 General Compliance or Alternate Approach Assessment:
For commitment, revision number, and scope see section 1.8. This guide describes a method of implementing r equirements acceptable to NRC regarding non-destructive examination requirements of tubular products used in RCPB. Wrought tubular products were supplied in accordance with applicable ASTM/ASME material specifications. Additionally, the specification for the tubular product used for CRD housings specified ultrasonic examination to paragraph NB-2550 of ASME Code Section III.
These RCPB components met the requirements of ASME Codes existing at time of placement of order which predated Regulatory Guide 1.66. At the time of the placement of the orders, 10 CFR 50 Appendix B requirements and the ASME code requirements assured adequate control of quality for the products. This Regulatory Guide was withdrawn on S eptember 28, 1977 by the NRC because the additional requirements imposed by the guide were satisfied by the ASME Code. 5.2.3.3.4 Moisture Control for Low Hydrogen, Covered Arc-Welding Electrodes All low hydrogen covered welding electrodes are stored in controlled storage areas. Electrodes are received in hermetically sealed cannisters. After removal from the sealed containers, electrodes which are not immediately used are placed in storage ovens. Electrodes are distributed from sealed containers or ovens as required. Electrodes which are damaged, wet, or contaminated are discarded. If any electrodes are inadvertently left out of the ovens for more than one shift, they are discarded.
CPS/USAR CHAPTER 05 5.2-22 REV. 11, JANUARY 2005 5.2.3.4 Fabrication and Processing of Austenitic Stainless Steels 5.2.3.4.1 Avoidance of Stress Corrosion Cracking 5.2.3.4.1.1 Avoidance of Significant Sensitization A. Regulatory Guide 1.44: Clinton Power Station complies with Regulatory Guide 1.44. B. NUREG 0313: Clinton Power Station complies with NUREG 0313, Rev. 1. C. Method of compliance: With the exception of the reactor recirc pipe, all wrought austenitic stainless steel in contact with the reactor coolant is 316 L stainless steel and, therefore, has less than 0.03% carbon content. The reactor recirculation piping is fabricated primarily of 304 stainless steel. Certain portions have been changed to "nuclear grade" type 316 which contains less than 0.03%
carbon. The remainder has had "corrosion-resistant clad" applied in the vicinity of field welds so that no heat-affected type 304 will be in contact with the coolant. The piping assemblies were all solution annealed after all shop welding and application of the cladding. The following additional process controls were applied in addition to material selection.
All austenitic stainless steel was purchased in the solution heat treated condition in accordance with applicable ASME and ASTM specifications. Carbon content was limited to 0.08% maximum, and cooling rates from solution heat treating temperatures were required to be rapid enough to prevent sensitization. Welding heat input was restricted to 110,000 joules per inch maximum, and interpass temperature to 350 °F. High heat welding processes such as block welding and electroslag welding were not permitted. All weld filler metal and castings were required by specification to have a minimum of 5% ferrite. Whenever any wrought austenitic stainless steel was heated to temperatures over 800° F, by means other than welding or thermal cutting, the material was solution heat treated. These controls were used to avoid severe sensitization and to comply with the intent of Regulatory Guide 1.44, "Control of the Use of Sensitized Stainless Steel". Since CPS complies with NUREG 0313, no additional inservice ins pection or leak detection is required.
CPS/USAR CHAPTER 05 5.2-23 REV. 11, JANUARY 2005 5.2.3.4.1.2 Process Controls to Minimize Exposure to Contaminants Exposure to contaminants capable of causing stress corrosion cracking of austenitic stainless steel components was avoided by carefully controlling all cleaning and processing materials which contact the stainless steel during manufacture and construction. To further reduce the probability of cracking in small lines, three inch and smaller lines were fabricated from Type 316L, even though they are not classified as "service sensitive." This extra precaution has been taken because piping cracks have been confined to smaller piping. When stress corrosion is not predicted due to low stress, General Electric has chosen to control processing of stainless steel to minimize susceptibility. These controls include, but are not limited to, reduced weld heat input, control of cold work, and control of solution heat treatment. As summarized above, General Electric has complied with the intent of Regulatory Guide 1.44 by controlling processing of stainless steel to avoid severe sensitization which could lead to stress corrosion cracking. In addition, areas where a concern for stress corrosion cracking exists due to cracks in earlier designs have been redesigned to eliminate the possibility of stress corrosion cracking. Special care was exercised to insure removal of surface contaminants prior to any heating operations. Water quality for cleaning, rinsing, flushing, and testing was controlled and monitored. Suitable packaging and protection was provided for components to maintain cleanliness during shipping and storage. The degree of surface cleanliness obtained by these procedures meets the requirements of Regulatory Guide 1.44. 5.2.3.4.1.3 Cold Worked Austenitic Stainless Steels Austenitic stainless steels with a yield strength greater than 90,000 psi are not used. 5.2.3.4.2 Control of Welding 5.2.3.4.2.1 Avoidance of Hot Cracking A. Regulatory Guide 1.31 General Compliance or Alternate Approach Assessment:
For commitment, revision number, and scope see section 1.8. Regulatory Guide 1.31 describes an acceptable method of implementing requirements with regard to the control of welding when fabricating and joining austenitic stainless steel
components and systems. All austenitic stainless steel weld filler materials were supplied with a minimum of 5% delta ferrite. This amount of ferrite is considered adequate to prevent microfissuring in austenitic stainless steel welds. An extensive test program performed by General Electric Company, with the concurrence of the Regulatory Staff, has demonstrated that controlling weld filler metal ferrite at 5% minimum produces production welds which meet the requirements of Regulatory Guide 1.31.
CPS/USAR CHAPTER 05 5.2-24 REV. 11, JANUARY 2005 A total of approximately 400 production welds in five BWR plants were measured and all welds met the requirements of the Interim Regulatory Position. 5.2.3.4.2.2 Electroslag Welds. Regulatory Guide 1.34.
Electroslag welding was not employed for reactor coolant pressure boundary components. 5.2.3.4.2.3 Welder Qualification for Areas of Limited Accessibility. Regulatory Guide 1.71. A. Regulatory Guide 1.71 General Compliance or Alternate Approach Assessment:
For commitment, revision number, and scope see section 1.8. Regulatory Guide 1.71 requires that weld fabrication and repair for wrought low-alloy and high-alloy steels or other materials such as static and centrifugal castings and bimetallic joints should comply with fabrication requirements of Section III and Section IX of the ASME Boiler and Pressure Vessel Code. It also requires additional performance qualifications for welding in areas of limited access. All ASME Section III welds were fabricated in accordance with the requirements of Sections III and IX of the ASME Boiler and Pressure Vessel Code. There are few restrictive welds involved in the fabrication of BWR components. Welder qualification for welds with the most restrictive access was accomplished by mock-up welding. Mock-ups were examined with radiography or sectioning. 5.2.3.4.3 Nondestructive Examination of Tubular Products. Regulatory Guide 1.66.
For discussion of compliance with Regulatory Guide 1.66 see 5.2.3.3.3.
5.2.4 Inservice Inspection and Testing of Reactor Coolant Pressure Boundary 5.2.4.1 Inservice Inspection Program The reactor pressure vessel, system piping, pumps, valves and components (including supports and pressure-retaining bolting) within the reactor coolant pressure boundary (RCPB), defined as Quality Group A (ASME Code Section III, Class 1) were designed and fabricated to permit full compliance with the edition and addenda of Section XI in effect at the time of their construction.
Engineering and design considerations were taken to ensure the reactor coolant pressure boundaries are inspectable, with access provided for volumetric examination of pressure-retaining welds from the external surfaces. Periodic design reviews are performed to ascertain if the accessibility requirements of later code editions and addenda recognized in 10 CFR 50 can be met. Examination plans will be developed prior to each inspection interval. 5.2.4.1.1 Examination Plans The preservice and inservice inspection plans are the means used to implement and requirements of Section XI of the ASME Code. A description of each plan follows.
CPS/USAR CHAPTER 05 5.2-25 REV. 11, JANUARY 2005 5.2.4.1.1.1 Preservice Examination Plan This subsection is historical.
The preservice examination plan consists of a list of piping, pumps, valves and components (including their supports and pressure-retaining bolting) subject to examination during preoperational testing. Coverage for the preservice examination uses the indicated edition/addenda, ASME Code, Section CI, of Table 5.2-3. The nondestructive examination will be performed in accordance with the examination categories and methods specified in Article IWB-2000. Pump operability and valve functional testing will be conducted in accordance with Articles IWP and IWV, respectively, of the Code. The Inspection Agency will supply supporting data which consists of weld identification isometric drawings, mechanized examination scan plans, nondestructive examination procedures and ultrasonic calibration standard drawings which will be used during the preservice examination. The preservice examination of piping welds at Clinton will be conducted in accordance with the requirements of Appendix III to Section XI for ferritic piping welds and Article 5 of Section V for austenitic piping welds. This is consistent with IWA-2232 of the ASME Code,Section XI. The piping calibration blocks have been manufactured to permit either method of examination to be performed. Appendix III to Section XI may be used for examination of austenitic piping welds during subsequent inservice inspections. The feasibility of using this method is under evaluation, and its applicability will be determined prior to the submittal of the inservice inspection program for
the first 10-year interval. The use of Article 5 of Section V for austenitic piping welds conforms to IWA-2232 of Section XI. During the examination of either ferritic or austenitic piping welds using Appendix III to Section XI, any crack-like indications, regardless of amplitude, determined by an examiner to be other than geometrical or metallurgical in nature shall be recorded and investigated by a Level II or
Level III examiner to the extent necessary to determine the shape, identification, and the location of the reflector. The applicable nondestructive examination procedure submitted with the Preservice Inspection Program on February 23, 1982 is under revision to incorporate this change. The revision will be submitted to the Authorized Nuclear Inspection Agency for review and approval and incorporated into the Preservice Inspection Program Plan by revision. Any reflector found to be other than geometrical or metallurgical in nature will be evaluated to determine the corrective action necessary to disposition the indication. The evaluation will be conducted in accordance with Article IWA-3000 of the 1977 Edition, through Summer 1978 Addenda to Section XI of the ASME Code. (Q&R 250.1) On February 23, 1982 a copy of the Preservice Inspection Program for the Clinton Power Station Unit 1 was submitted for review. The submittal contained the list of welds and component support to be examined by class, ASME Section XI item number, ASME Section XI category, weld identification number, examination method, nondestructive examination procedure to be used, applicable calibration block identification, and figure number for the weld CPS/USAR CHAPTER 05 5.2-26 REV. 11, JANUARY 2005 isometric which identifies the location of the weld in its respective system. Supplemental information will be provided for those items in the submittal which were not complete due to insufficient information at the time of submittal. If during the course of examination it is found that an examination does not receive a complete Section XI preservice examination, a relief request will be submitted. The relief request will identify the primary reason for the partial examination, e.g., restricted access or exam performed from one side due to fitting-to-fitting configuration. The relief request will also contain the extent of examination possible, weld identification number and location, and the physical configuration of the weld. Upon completion of the preservice examination, a summary report will be available for inspection identifying all examinations performed, results of the examination, and the evaluation and resolution of any indication found exceeding the requirements of the ASME Code. (Q&R 250.2) 5.2.4.1.1.2 Inservice Examination Plan The inservice inspection plan consists of a list of piping, pumps, valves and components (including their supports and pressure-retaining bolting) subject to examination during a specific inspection interval. The inspection program is divided into four intervals, each having a duration of 10 years. Each interval will have its own inspection plan consisting of the schedule of component examination and the inspection techniques to be used. The plans will be updated to later editions and addenda as required by 10 CFR 50. 5.2.4.2 System Boundaries Subject to Inspection ASME Code Class I components (including supports and pressure-retaining bolting) are examined in accordance with the inspection requirements of Section XI of the Code, except for those components exempted under IWB-1220 or when specific relief is granted by the NRC in accordance with the provisions of 10 CFR 50.55a (g) (6) (i).Section XI, Article IWB-2000 defines the examination category and methods to be used. The boundaries subject to inspection include the pressure vessel, piping, pumps and valves which are part of or connected to the reactor coolant system, up to and including: (1) The outermost containment isolation valve in system piping that penetrates the primary reactor containment; (2) the second of two valves normally closed during normal reactor operation in system piping that does not penetrate the primary reactor containment; and (3) the reactor coolant system safety and relief valves. The boundaries subject to inspection include the pressure vessel, piping, pumps, valves, pressure-retaining bolting and supports extending out to and including the first isolation valve outside the containment. A list of the sy stems and components to be examined within the RCPB is included in Table 3.2-1. 5.2.4.3 Provision for Access to Reactor Coolant Pressure Boundary Access and design considerations were taken to ensure the reactor coolant pressure boundaries were inspectable in accordance with the requirements of the 1974 Edition of ASME Section XI Summer 1975 Addenda.
CPS/USAR CHAPTER 05 5.2-27 REV. 11, JANUARY 2005 5.2.4.3.1 Reactor Pressure Vessel Access for examination of the reactor pressure vessel has been incorporated into the design of the vessel to meet the requirements of IWA-1500 "Accessibility" of Section XI. The vessel and nozzles were examined in place during the preservice examination using the same type equipment expected to be used for subsequent inservice examinations. A description of the access provisions follows:
(1) Nozzles Access to inspect the nozzles is provided by openings in the reactor shield wall (RSW) designed to afford a nominal 9-inch annulus between the nozzle piping and the RSW. The space will provide: (1) the necessary clearance for mechanized nozzle and piping inspection equipment to operate, and (2) the necessary space to repair and reinspect nozzles or piping in the event structural defects or indications are revealed. Access is provided to a nominal 30-inch annulus between the RSW insulation and the reactor pressure vessel through access doors in the RSW. This space permits examination of the nozzle-to-vessel welds located wihtin the RSW. Removable thermal insulation and personnel platforms are provided at each nozzle to further facilitate examination. (2) Reactor Vessel Welds Access to welds above the RSW, including the vessel-to-flange weld, is accomplished by removable thermal insulation and a circumferential platform located around the top of the RSW. Access to the top head is accomplished by removable thermal insulation. Laydown areas have been provided for the vessel head and bolting to permit
their examination. Access to the core support structures and vessel interior cladded surfaces is provided by removing the steam dryer and separator assembly. Laydown areas have been provided for the dryer and separator in the upper containment pools. Access doors are provided in the RSW to permit access to the annulus between it and the reactor vessel. Welds within the annulus are made accessible by standoff thermal insulation and two personnel platforms extending around the annulus between the reactor vessel and the RSW. Access holes are provided in the vessel support skirt to allow examination of the bottom head welds. The examinations performed include the circumferential, longitudinal, bottom head, and bottom head penetration welds, as well as accessible welds in the housings of the peripheral CRD.
CPS/USAR CHAPTER 05 5.2-28 REV. 11, JANUARY 2005 5.2.4.3.2 Pipe, Pumps and Valves (1) Physical Arrangement Physical arrangements of pipe, pumps, and valves provide: personnel access to each piping weld, pump and valve, and work space to permit repair and reexamination of welds and components if defects or indications are revealed. Personnel platforms and storage areas are provided to facilitate examinations.
Removable thermal insulation is provided on those welds and components which require frequent access for examination. Design considerations incorporate provisions for the use of lifting equipment for the removal of insulation and pump and valve parts whose removal is necessary to permit access for examination or repair. (2) Welds Welds are located to permit ultrasonic examination from at least one side but where component configuration permits, access from both sides is provided.
Consideration was given during design and fabrication to weld joint configuration and surface finish to permit thorough ultrasonic examination. 5.2.4.4 Examination Techniques and Procedures Examination techniques and procedures, including any special techniques and procedures, were written and performed in accordance with the requirements of IWA-2210 - Visual Examination, IWA-2220 - Surface Examination, and IWA-2230 - Volumetric Examination of ASME Section XI of the Code. For piping, the examination shall be in accordance with Appendix III,Section XI, instead of Article 5,Section V, and all reflectors that produce response greater than 50% of the reference level shall be recorded. The extent of surface and volume examination for piping shall be as depicted in Figure IWB-2500-8 of ASME Code Section XI. The reactor pressure vessel welds were examined in accordance with NRC Regulatory Guide 1.150. Refer to USAR Section 1.8. Where alternative examinations are used, they will comply with the requirements of Section XI, IWA-2240. 5.2.4.5 Equipment for Inservice Inspection Manual ultrasonic examination was planned for t he preservice examination and subsequent inservice inspection examinations of the reactor pressure vessel top and bottom heads, the flange-to-vessel weld, pressure-retaining bolting, and component bodies and casings. (1) Reactor Pressure Vessel Remote mechanized ultrasonic scanning equipment was employed to examine the reactor vessel longitudinal and circumferential welds located within the RSW. The equipment operated between the vessel thermal insulation and the vessel wall. The ultrasonic devices were supported by means of ring and pole-type tracks. The ring tracks were employed for examination of the vessel CPS/USAR CHAPTER 05 5.2-29 REV. 11, JANUARY 2005 circumferential welds and the pole tracks for examining the vessel longitudinal welds. (2) Reactor Vessel Nozzle Welds Remote mechanized ultrasonic scanning equipment was employed for examination of the nozzle-to-vessel welds. The ultrasonic equipment was supported and guided from the pipe extending from the nozzle. The equipment provided radial and circumferential motion to the ultrasonic transducer while rotatinq about the nozzle. Attachment of the equipment can be accomplished manually through the access openings in the RSW. (3) Reactor Vessel Internals The reactor vessel internals were inspected primarily by remote visual method; however, surface replication may be used. Underwater viewing equipment and binoculars were used for the examination. 5.2.4.6 Inspection Intervals The inspection intervals will be in accordance with IWA-2400 and IWB-2400 of ASME Code Section XI, with each interval having a nominal 10-year duration. The inspections are concurrent with plant refueling and/or maintenance shutdowns. 5.2.4.7 Examination Categories and Requirements The examination categories and requirements will be in compliance with Article IWB-2000 of ASME Code Section XI. 5.2.4.8 Evaluation of Examination Results Evaluation of the preservice and subsequent inservice examination results was conducted in accordance with the requirements of Section XI, IWA-3000 and IWB-3000. The data obtained from the preservice inspection established the initial base line for subsequent inservice inspections. The base line data for the reactor pressure vessel was obtained with the vessel installed at the site. 5.2.4.9 Coordination of Inspection Equipment with Access Provisions This subsection is historical. Development of remotely controlled inspection equipment to be used on CPS is followed closely to assure that inservice inspection access provisions are adequate to permit its use. Assistance in design, review and recommendations concerning conformity are obtained from an experienced consulting firm. Periodic meetings are held with the consultants to assure that the design of the remotely controlled equipment is compatible with station design. 5.2.4.10 System Leakage and Hydrostatic Tests Pressure-retaining Code Class 1 component and system leakage and hydrostatic testing are conducted in accordance with the requirements of Section XI, IWB-5000. The temperature-CPS/USAR CHAPTER 05 5.2-30 REV. 12, JANUARY 2007 pressure relationship of the system at test will be maintained within the values specified in Section XI, IWB-5222 and technical specification requirements for operating limitations during heatup, cooldown and system hydrostatic pressure testing. 5.2.4.11 Ultrasonic Calibration Standards Ultrasonic calibration standards or material for their fabrication have been procured for all examination categories of Table IWB-2600, 1974 Edition, Summer 1975 Addenda of the ASME Code,Section XI, requiring volumetric examination. These standards will be maintained by CPS plant staff as required by IWA-1400 of ASME Code Section XI. 5.2.4.12 Augmented Inservice Inspection 5.2.4.12.1 Feedwater Nozzles and CRD Return Line Nozzle Examinations The feedwater nozzles (triple thermal sleeve design) and CRD return line (CRDRL) nozzle (capped without rerouting CRDRL) will be examined using the methods, techniques and frequency outlined in NUREG 0619. For Feedwater Nozzles only, the BWR Owner's Group Topical Report GE-NE-523-A71-0594-A, Alternate BWR Feedwater Nozzle Inspection Requirements, will be utilized in lieu of NUREG 0619. 5.2.4.12.2 Examination of Piping Susceptible to Intergranular Stress Corrosion Cracking Piping susceptible to intergranular stress corrosion cracking (IGSCC) will be examined using procedures that have demonstrated the ability to detect IGSCC. Personnel performing such examinations shall be certified for using these procedures. 5.2.4.12.3 Examination of Containment Penetration Head Fittings Containment penetration head fittings associated with high energy piping systems will be examined by a surface examination technique during ISI. 5.2.4.12.4 Examination of Break Exclusion Region During the first ten-year inservice inspection (ISI) interval, high energy Class 1 piping located between the containment isolation valves (in the break exclusion area) was examined as follows: One hundred percent of all circumferential and longitudinal welds of piping larger than 1 inch nominal pipe size. Starting in the second ten-year ISI interval, in lieu of the above requirements, EPRI Topical Reports Risk-Informed ISI (TR-112657 Revision B-A), Break Exclusion Region (TR-1006937 Revision 0-A), and ASME Code Case N-578-x are used to establish the risk evaluation, selection criteria, and examination methods. The NRC approved the use of this alternate method in an SER dated June 27, 2002. The weld population subject to examination under the Risk-Informed BER Program are non-exempted piping welds as determined in accordance with the rules of ASME Section XI IWB-1220, Edition and Addenda as applicable to the existing ISI program.
5.2.4.13 Repairs If structural defects or indications found during examination require repair, subsequent repairs will be based on the requirements of IWA-4000 and IWB-4000 of Section XI, ASME Code.
CPS/USAR CHAPTER 05 5.2-30a REV. 12, JANUARY 2007 5.2.5 Reactor Coolant Pressure Boundary and ECCS System Leakage Detection System 5.2.5.1 Leakage Detection Methods The Nuclear Boiler Leak Detection System consists of temperature, pressure, flow, airborne gaseous and particulate fission product sensors, and process radiation sensors with associated instrumentation used to indicate and alarm leakage from the reactor coolant pressure boundary and, in certain cases, to initiate signals used for automatic closure of isolation valves to shut off leakage external to the drywell. The system is designed to be in conformance with NRC Regulatory Guide 1.45 and reference section IEEE 279 except as described in USAR section 1.8. The Leak Detection System P&ID is shown on Drawing M05-1041. Abnormal leakage from the following systems within the primary containment and within selected areas of the plant outside the primary containment is detected, indicated, alarmed and in certain cases isolated: (1) Main steam lines CPS/USAR CHAPTER 05 5.2-31 REV. 12, JANUARY 2007 (2) Reactor Water Cleanup System (RWCS) (3) Residual Heat Removal System (RHR)
(4) Reactor Core Isolation Cooling System (RCIC)
(5) Feedwater System (6) High Pressure Core Spray (HPCS) (7) Coolant Systems within the primary containment (8) Low Pressure Core Spray (LPCS)
(9) Reactor pressure vessel (10) Miscellaneous systems Leak detection methods differ for plant areas inside the primary containment as compared to these areas located outside the primary containm ent. These areas are considered separately as follows: 5.2.5.1.1 Detection of Leakage within the Drywell The primary detection methods for small unidentified leaks within the drywell include monitoring of drywell floor drain sump flow rate, and drywell cooler condensate flow rate increases. These variables are continuously indicated and/or recorded in the control room. If the unidentified leakage increases to 3.6 gpm, as sensed by the drywell floor drain sump flow rate instrumentation the channel(s) will trip and activate an alarm in the control room. If the unidentified leakage exceeds an increase of 2 gpm in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, as sensed by the drywell floor drain sump flow rate instrumentation, the channel(s) will trip and activate an alarm in the control room. If the unidentified leakage increases to 2 gpm for each of the drywell cooler condensate flow rate instruments, the channel(s) will trip and activate an alarm in the control room. No isolation trip will occur. The secondary detection methods, i.e., the monitoring of pressure and temperature of the drywell atmosphere and airborne gaseous and particulate radioactivity increases are used to detect gross unidentified leakage. High drywell pressure will alarm and trip the isolation logic which will result in closure of the selected containment isolation valves. The detection of small identified leakage within the drywell is accomplished by monitoring drywell equipment drain sump fillup time and pumpout time. The fillup and/or pumpout timers will activate an alarm in the control room. In addition, a flow element is installed in the sump pump discharge line which, in combination with a differential pressure transmitter, is used to provide a signal to a control room totalizer, which identifies gallons pumped, and a PLC, which provides signals for identification of drywell equipment leakage.
CPS/USAR CHAPTER 05 5.2-32 REV. 13, JANUARY 2009 The determination of the source of identified leakage within the drywell is accomplished by monitoring the drain lines to the drywell equipment drain sumps from various potential leakage sources. These include upper containment pool seal drain flow, reactor recirculation pump seal drain flow, valve stem leakoff drain line temperatures and reactor vessel head seal drain line pressure. Additionally, temperature is monitored in the safety/relief valve discharge lines to the suppression pool to detect leakage through each of the safety/relief valves. All of these monitors, except the reactor recirculation seal drain flow monitor and the reactor vessel head seal drain line pressure monitor, continuously indicate and/or record in the control room. All of these monitors will trip and activate an alarm in the control room on detection of leakage from monitored components. Excessive leakage inside the drywell (e.g., process line break or loss of coolant accident within the drywell) is detected by high drywell pressure, low reactor water level or steam line flow (for breaks down stream of the flow elements). The instrumentation channels for these variables will trip when the monitored variable exceeds a predetermined limit to activate an alarm and trip the isolation logic which will close appropriate isolation valves (see Table 5.2-9b). The alarms, indication and isolation trip functions initiated by the leak detection systems are summarized in Tables 5.2-9a and 5.2-9b. 5.2.5.1.2 Detection of Leakage External to the Drywell The detection of leakage external to the drywell is accomplished by detection of increases in containment building floor drain sump and containment building equipment drain sump fillup time and pumpout time. The containment building floor drain sump monitors will detect unidentified leakage increases relative to normal background and activate an alarm in the control room when total leakage reaches 5 gpm. The containment building equipment drain sump instrumentation will detect identified leakage increase relative to normal background leakage and will activate an alarm in the control room when total leakage reaches 25 gpm. Identified leakage to the containment building floor drain sump from the upper containment pool liner is monitored for flow. High flow in a drain line will activate an alarm in the control room. 5.2.5.1.3 Detection of Leakage External to Containment Building The areas outside the containment building which are monitored for primary coolant leakage are: equipment areas in the auxiliary building, the main steam tunnel and the turbine building.
The process piping for each system to be monitored for leakage is located in compartments or
rooms separate from other systems where feasible so that leakage may be detected by area temperature indications. Each leakage detection system will detect leak rates that are less than the established leakage limits. (1) Ambient temperatures of the equipm ent areas are monitored by dual element thermocouples. The ambient temperature sensing elements are located or shielded so that they are sensitive to air temperatures only and not radiated heat from hot piping or equipment. Individual area differential te mperatures are monitored from temperature elements which sense the differential between the cooling water inlet and outlet of the respective area coolers. Increases in ambient and/or differential temperature will indicate leakage of reactor coolant into the area.
CPS/USAR CHAPTER 05 5.2-33 REV. 11, JANUARY 2005 These monitors have sensitivities suitable for detection of reactor coolant leakage into the monitored areas of 25 gpm or less. The temperature trip setpoints are a function of room size and the type of ventilation provided. Ambient temperature monitors provide alarm and indication and recording in the control room and will trip the isolation logic to close selected isolation valves as listed in Table 5.2-9b. (2) Excess leakage external to the containment (e.g., process line break outside containment) is detected by low reactor water level, high process line flow, high ambient temperature in the piping or equipment areas, and high differential flow. These monitors provide alarm and indication in the control room and will trip the isolation logic to cause closure of appropriate system isolation valves on indication of excess leakage (e.g., the main steam tunnel monitors will close the main steam line and MSL drain isolation valves and others; see Table 5.2-9b). Differential temperature monitors in these areas provide indication only. (3) The detection of small amounts of leakage within the LPCS, HPCS, RCIC and RHR pump cubicles is accomplished by det ection of increases in cubicle floor drain sump fillup time and pumpout time. These monitors will detect unidentified leakage increases relative to normal background and will activate an alarm in the main control room when leakage exceeds 5 gpm. 5.2.5.1.4 Intersystem Leakage Monitorinq Radiation monitors are used to detect reactor coolant leakage into cooling water systems supplying the RHR heat exchangers and the RWCU heat exchangers. These monitoring channels are part of the Process Radiation Monitoring System. Monitors are also provided downstream of each fuel pool heat exchanger and on the service water effluent. A process radiation monitoring channel monitors for leakage into each cooling water header downstream of the RHR heat exchangers and on the common header downstream of the RWCU non-regenerative heat exchangers. Each channel will alarm on high radiation conditions indicating process leakage into the cooling water. No isolation trip functions are performed by these monitors. 5.2.5.2 Leak Detection Instrumentation and Monitoring 5.2.5.2.1 Leak Detection Instrumentation and Monitoring Inside Drywell (1) Floor Drain Sump Measurement The normal design leakage collected and piped to the floor drain sump includes unidentified leakage from the control rod drives, valve flange leakage, component cooling water, service water, air cooler drains, and any leakage not connected to the equipment drain sump. There are two systems for monitoring unidentified leakage. One floor drain monitoring system measures pump discharge flow to determine average leakage rate. A second floor drain monitoring system measures sump level rate of change to determine average leakage rate at one minute intervals. Abnormal leakage rates are alarmed in the main control room. Collection in excess of background leakage would indicate an increase in reactor coolant leakage from an unidentified source.
CPS/USAR CHAPTER 05 5.2-34 REV. 11, JANUARY 2005 (2) Equipment Drain Sump The equipment drain sump collects only identified leakage. This sump receives piped drainage from pump seal leakoff, reactor vessel head flange vent drain, and valve stem packing leak off. Collection in excess of background leakage would indicate an increase in reactor coolant from an identified source. (3) Cooler Condensate Drain Condensate from the drywell coolers is routed to the floor drain sump and is monitored by use of a flow transmitter which measures flow in the condensate drain line and sends signals for indication and alarm instrumentation in the control room. An adjustable alarm is set to annunciate on the condensate high flow rate approaching the unidentified discharge rate limit. (4) Temperature Measurement The ambient temperature within the drywell is monitored by four single element thermocouples located equally spaced in the drywell. An abnormal increase in drywell temperature could indicate a leak within the drywell. The drywell exit end of the containment penetration guard pipe for the main steam line is also monitored for abnormal temperature rise caused by leakage from the main steam line. Ambient temperatures within the drywell are recorded and alarmed on the leakage detection and isolation system (LD&IS) control room panel. (5) Fission Product Monitoring The Primary Containment Air Sampling System is used along with the temperature, pressure, and flow variation described above to detect leaks in the nuclear system process barrier. The system continuously monitors the drywell atmosphere for airborne radioactivity (iodine, noble gases and particulates), for details see section 5.2.5.2.2. The sample is drawn from the drywell. A sudden increase of activity, which may be attributed to steam or reactor water leakage, is annunciated in the control room (see Section 7.6). (6) Drywell Pressure Measurement The drywell is at a slightly positive pressure during reactor operation. The drywell is monitored by pressure sensors. The pressure fluctuates slightly as result of barometric pressure changes and outleakage. A pressure rise above the normally indicated values will indicate a possible leak within the drywell.
Pressure exceeding the preset values will be annunciated in the main control room and safety action will be initiated. (7) Reactor Vessel Head Seal The reactor vessel head closure is provided with double seals with a leak off connection between the seals that is piped through a normally closed manual valve to the equipment drain sump. Leakage through the first seal is annunciated in the control room. This annunciator is verified "not in" at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. When pressure between the seals increases, an alarm in the CPS/USAR CHAPTER 05 5.2-35 REV. 11, JANUARY 2005 control room is actuated. The second seal then operates to contain the vessel pressure. (8) Reactor Water Recirculation Pump Seal Reactor water recirculation pump seal leaks are detected by monitoring flow in the seal drain line. Leakage, indicated by high flow rate, alarms in the control room. The leakage is piped to the equipment drain sump. (9) Safety/Relief Valves Temperature sensors connected to a multipoint recorder are provided to detect safety/relief valve leakage during reactor operation. Safety/relief valve temperature elements are mounted, using a thermowell, in the safety/relief valve discharge piping several feet downstream from the valve body. Temperature rise above ambient is annunciated in the main control room. See the nuclear boiler system piping and instrumentation diagram, 796E724. (10) Valve Stem Packing Leakage Valve stem packing leakage from some of the power-operated valves in systems connected to the Reactor Coolant Pressure Boundary inside the drywell is detected by monitoring packing leakoff. High temperature is recorded and annunciated by an alarm in the main control room. Refer to the system P&IDs which detail the specific valves equipped with stem packing leakoff lines and associated temperature monitoring instrumentation. (11) High Flow in Main Steam Lines (for leaks downstream from flow elements) High flow in each main steam line is monitored by differential pressure sensors that sense the pressure difference across a flow element in the line. Steam flow exceeding preset values for any of the four main steam lines results in annunciation and isolation of all the main steam and steam drain lines. (12) Reactor Water Low Level The loss of water in the reactor vessel (in excess of make up) as the result of a major leak from the reactor coolant pressure boundary is detected by using the same nuclear boiler system low reactor water level signal that alarms and isolates selected primary system isolation valves. (13) RCIC Steam Line Flow (for leaks downstream from flow elements) The steam supply line for motive power for operation of the RCIC turbine is monitored for abnormal flows. Steam flows exceeding preset values initiate annunciation and isolation of the RCIC steam lines. (14) High Differential Pressure Between ECCS Injection Lines (for leakage internal to reactor vessel only)
CPS/USAR CHAPTER 05 5.2-36 REV. 11, JANUARY 2005 A break internal to the vessel between ECCS injection nozzles and vessel shroud is detected by monitoring the differential pressure between RHR "A" and LPCS, RHR "B" and "C", and HPCS and reactor vessel plenum. These differential pressure instruments are connected to the ECCS (RHR/LPCI, LPCS, HPCS) injection lines downstream of the testable check valves and provide indication and alarm only in the m ain control room; they do not provide ECCS isolation. (15) Upper Pool Leakage The upper pool liner and bellows seal is monitored for leakage by means of flow transmitters locally mounted on the upper pool drain line. Indicator and alarm are located in the main control room. Tables 5.2-9a and 5.2-9b summarize the actions taken by each leakage detection function. The tables show that those systems which detect gross leakage initiate immediate automatic isolation. The systems which are capable of detecting small leaks initiate an alarm in the control room. The operator may manually isolate the leakage source or take other appropriate action. 5.2.5.2.2 Containment/Drywell Airborne Radioactivity Monitoring The radioactivity monitors for detecting RCPB leakage are subject to substantial limitations of their usefulness as described below. The particulate and iodine monitors are not effective due to the significant amount of plateout (see Ref. 7). The noble gas monitor is used to alarm for large leaks and pipe breaks. The reliability, sensitivity and response times of radiation monitors to detect 1GPM in one hour of reactor coolant pressure boundary (RCPB) leakage will depend on many complex factors. The major limiting factors are discussed below. 5.2.5.2.2.1 Source of Leakage
- a. Location of Leakage - The amount of activity that would become airborne following a 1GPM leak from the RCPB will vary depending on the leak location and the coolant temperature and pressure. For example, a feedwater pipe leak may have concentration factors of 100 to 1000 lower than a recirculation line break. A steam line break may be a factor of 50 to 100 lower in iodine and particulate concentrations than the recirculation line leak, but the noble gas concentrations may be comparable. An RWCS leak upstream of the demineralizers and heat exchangers may be a factor of 10 to 100 higher than downstream, except for noble gases. Differing coolant temperatures and pressures will affect the flashing fraction and partition factor for iodines and particulates. Thus, an airborne concentration cannot be directly correlated to quantity of leakage without knowing the source of the leakage. b. Coolant Concentrations - Variations in iodine and particulate concentrations within the reactor coolant during operation can be as much as two orders of magnitude, within a time frame of several hours. These effects are mainly due to spiking during power transients or changes in the use of the RWCS. An increase in the coolant CPS/USAR CHAPTER 05 5.2-37 REV. 11, JANUARY 2005 concentrations could give increased drywell concentrations without an increase in unidentified leakage. c. Other Sources of Leakage - Because the unidentified leakage is not the sole source of activity in the containment, changes in other sources will result in changes in the containment airborne concentrations. For example, identified leakage is piped to the equipment drain tank in the drywell, but the tank is vented to the drywell atmosphere allowing the release of noble gases and some small quantities of iodines and particulates from the drain tank. 5.2.5.2.2.2 Drywell Conditions Affecting Monitor Performance
- a. Equilibrium Activity Levels - During nor mal operation, the activity release from acceptable quantities of identified and unidentified leakage will build up to significant amounts in the drywell air. Due to these high equilibrium activity levels, the activity increase due to a small increase in leakage may be difficult to detect within a short
period of time. b. Purge and Pressure Release Effects - Changes in the detected activity levels have occurred during containment venting operations. These changes are of the same order of magnitude as approximately a 1GPM leak and are sufficient to invalidate the results from iodine and particulate monitors. c. Plateout, Mixing, Condensation, Fan Coolant Depletion - Plateout effects on measured iodine and particulate levels will vary with the distance from the coolant release point to the detector. Larger travel distances would result in more plateout. In addition, the pathway of the leakage will influence the plateout effects. For example, a leak from a pipe with insulation will have greater plateout than a leak from an uninsulated pipe. Although the drywell air will be mixed by the fan coolers, it may be possible for a leak to develop in the vicinity of the radiation detector sample lines. In addition, condensation in the coolers and sample lines will remove iodines and particulates from the air.
Variations in flow, temperature, and number of coolers will affect the plateout fractions. Plateout within the detector sample chamber will also add to the reduction of the iodine and particulate activity levels. The uncertainties in any estimate of plateout effects could be as much as one or two orders of magnitude. 5.2.5.2.2.3 Capabilities of the Detector
- a. Monitor Uncertainties - At high count rates the monitors have dead time uncertainties and the potential for saturating the monitor or the electronics. Uncertainties in calibration (plus or minus 5%), sample flow (plus or minus 10%), and other instrument design parameters tend to make the uncertainty in a count rate closer to 20 to 40% of the equilibrium drywell activity. b. Monitor Setpoints - Due to the uncertainty and extreme variability of the radioactivity concentrations to be measured in the containment, the use of tight alarm setpoints on the radioactivity monitor would not be practical or useful. The setpoint, which would be required to alarm at 1 GPM, would be well within the bounds of uncertainty of the measurements. The use of such setpoints would result in many unnecessary alarms and the frequent resetting of setpoints. The alarm setpoints for the radiation monitors are set significantly above normal readings to prevent nuisance alarms.
CPS/USAR CHAPTER 05 5.2-38 REV. 11, JANUARY 2005 c. Operator Action - There is no direct correlation or known relationship between the detector count rate and the leakage rate because the coolant activity levels, source of leakage, and background radiation levels (from leakage alone) are not known and cannot be cost-effectively determined in existing reactors. There are also several other sources of containment airborne activity (e.g., safety relief valve leakage) that further complicate the correlation. Thus, the procedure for the control room operator is to set an alarm setpoint on the sump level monitor (measuring water collected in the sump that may not exactly correspond to water leaking from an unidentified source). When the alarm is actuated, the operator will review all other monitors (e.g., noble gas, containment temperature and pressure, air cooler condensate flow, etc.) to determine if the leakage is from the primary coolant pressure boundary and not from an SRV or cooling water system, etc. Appropriate actions will then be taken in accordance with Technical Specifications as applicable. The review of other monitors will consist of comparisons of the increases and rates of increase in the values previously recorded. Increases in all parameters except sump flow will not be correlated to a RCPB leakage rate. Instead, the increases will be compared to normal operating limits and limitations, and abnormal increases will be investigated. Radiation monitor alarms are not set to levels that are intended to correspond to the RCPB leakage levels because such correlations are not valid. Because the containment airborne activity levels vary by orders of magnitude during operation due to power transients, spiking, steam leaks, and outgasing from sumps, an appropriate alarm setpoint is determined by the operator based on experience with the specific plant. A setpoint level of up to 10 times the level during full power steady state operation may be useful for alarming large leaks and pipe breaks, but it would not always alarm for 1 GPM in one hour and, therefore, could not be considered as any more than a qualitative indication of the presence of abnormal leakage. Due to the sum total of the uncertainties identified in the previous paragraphs, iodine and particulate monitors are not relied upon for immediate leak detection purposes. The noble gas monitor is used to give supporting information to that supplied by the sump discharge monitoring, and it would be able to give an early warning of a major leak, especially if equilibrium containment activity levels are low. However, the uncertainties and variations in noble gas leaks and concentrations would preclude the setting of a meaningful alarm setpoint. Grab sampling and laboratory analyses of airborne particulate, noble gas, and iodine may be used to characterize leakage detected by other means. 5.2.5.2.3 Leak Detection Instrumentation and Monitoring External to the Drywell (1) Containment Building Sump In-Leakage Measurement Instrumentation monitors and indicates the amount of unidentified leakage into the containment building floor drainage system outside the drywell. Identified leakage within primary containment, which includes the upper containment pool, transfer pool liner and separator liner leakage, is piped to the containment floor drain sump. The containment building floor and equipment drain sump instrumentation is similar to the normal drywell floor and equipment drain sump instrumentation. Alternate monit oring systems are not provided.
CPS/USAR CHAPTER 05 5.2-39 REV. 11, JANUARY 2005 (2) Visual and Audible Inspection Accessible areas are inspected periodically and the temperature and flow indicators discussed in this subsection are monitored regularly. Any instrument indication of abnormal leakage will be investigated. (3) Differential Flow Measurement (Reactor Water Cleanup System Only) Because of its arrangement the reactor water cleanup system uses the differential flow measurement method to detect leakage. The flow into the cleanup system is compared with flow from the system. An alarm in the control room and an isolation signal are initiated when high differential between flow into
the system and flow from the system and/or the main condenser indicates that a leak equal to the established leak rate limit may exist. (4) Main Steam Line Area Temperature Monitors High temperature in the main steam line tunnel area is detected by dual element thermocouples. Some of the dual element thermocouples are used for
measuring main steam tunnel ambient temperatures and are located in the area of the main steam and RCIC steam lines. The remaining dual elements are used in pairs to provide measurement of differential temperature across the chilled water inlet and outlet of the tunnel area ventilation system coolers. The turbine building main steamlines and steam header are monitored by temperature elements sensing ambient temperature only. All temperature elements are located or shielded so as to be sensitive to air temperatures and not to the radiated heat from hot equipment. One thermocouple of each differential temperature pair is located so as to be unaffected by tunnel temperature. High ambient temperature will alarm in the control room and provide a signal to close the main steam line and steam drain line isolation valves, RCIC steam line isolation valves, and the reactor water cleanup system isolation valves. A high temperature or differential temperature alarm may also indicate leakage in the reactor feedwater line which passes through the main steam tunnel. (5) Temperature Monitors in Equipment Areas Dual element thermocouples are installed in the equipment areas and in the inlet and outlet of ventilation cooling water to the RCIC, RHR, and RWCS equipment rooms for sensing high ambient or high differential temperature. The RCIC has two ambient and two pairs of differential temperature elements for its equipment area. The RHR has four ambient and two pairs of differential temperature elements. The RWCS has ten ambient and ten pairs of differential temperature elements. These elements are located or shielded so that they are sensitive to air temperature only and not radiated heat from hot equipment. High ambient temperatures are alarmed in the control room and provide trip signals for closure of isolation valves of the respective system in the monitored area. High differential temperatures provide indication only. (6) Intersystem Leakage Monitoring CPS/USAR CHAPTER 05 5.2-40 REV. 11, JANUARY 2005 The Intersystem Leakage Monitoring is included in the Process Radiation Monitoring System to satisfy the requirements of that system. Refer to Section 11.5. (7) Large Leaks External to the Drywell The main steam line high flow, RCIC steam line high flow and reactor vessel low water level monitoring discussed in section 5.2.5.2.1, paragraphs 11, 12 and 13 can also indicate large leaks from the reactor coolant piping external to the
drywell. (8) The detection of unidentified leakage within the LPCS, HPCS, RCIC and RHR pump cubicles is accomplished by detection of increases in cubicle floor drain sump fillup time and pumpout time. Alarms are provided in the main control room when excessive leakage is detected. 5.2.5.2.4 Summary Tables 5.2-9a and 5.2-9b summarize the actions taken by each leakage detection function. The table shows that those systems which detect gross leakage initiate an alarm and immediate automatic isolation. The systems which are capable of detecting small leaks initiate only an alarm in the control room. In addition, the tables show that two or more leakage detection systems are provided for each system or area that is a potential source of leakage. Plant operating procedures will dictate the action an operator is to take upon receipt of an alarm from any of these systems. The operator can manually isolate the violated system or take other appropriate action. A time delay is provided before automatic isolation of the Reactor Core Isolation Cooling System on a high ambient temperature in the main steam tunnel so that the MSIV's and RWCS can be isolated first and thereby preserve the operation of the RCIC system for core cooling. A time delay is also provided for the RWCS differential flow to prevent normal system surges from isolating the system.
The Leak Detection System is a multi-dimensional system which is redundantly designed so that failure of any single element will not interfere with a required detection of leakage or isolation. In the four division portion of the LD&IS, applied where inadvertent isolation could impair plant performance (e.g., Main Steamline Isolation Valves), any single channel or divisional component malfunction will not cause a false indication of leakage or false isolation trip because it will only trip one of four channels. It thus combines a very high probability of operating when needed with a very low probability of operating falsely. The system is testable during plant operation. 5.2.5.3 Indication in Control Room Leak detection methods are discussed in subsection 5.2.5.1. Details of the leakage detection system indications are included in subsection 7.6.1.4.3 and 7.7.1.24.10.
CPS/USAR CHAPTER 05 5.2-41 REV. 11, JANUARY 2005 5.2.5.4 Limits for Reactor Coolant Leakage 5.2.5.4.1 Total Leakage Rate The total leakage rate consists of all leakage, identified and unidentified, that flows to the drywell floor drain and equipment drain sumps. The total leakage rate limit is well within the makeup capability of the RCIC system and is established low enough to prevent overflow of the sumps. The equipment sump and the floor drain sump, which collect all leakage, are each pumped out by two 100% capacity pumps. The limit for acceptable identified leakage (associated with the drywell equipment sump) is established at 25 gpm. The limit for acceptable unidentified leakage (associated with the drywell floor drain sump) is established at 5 gpm. 5.2.5.4.2 Identified Leakage Inside Drywell The pump packing glands, valve stems, and other seals in systems that are part of the reactor coolant pressure boundary and from which normal design identified source leakage is expected are provided with leak-off drains. Nuclear system valves and pumps inside the drywell are equipped with double seals. Leakage from the primary recirculation pump seals is monitored for flow in the drainline and piped to the equipment drain sump. Leakage from the main steam safety/relief valves discharging to the suppression pool is monitored by temperature sensors that transmit to the control room. Any temperature increase above the ambient temperature detected by these sensors indicates valve leakage. Thus, the leakage rates from pumps, valve stem packings, and the reactor vessel head seal, which all discharge to the equipment drain sump, are measured during plant operation. 5.2.5.5 Unidentified Leakage Inside the Drywell 5.2.5.5.1 Unidentified Leakage Rate The unidentified leakage rate is the portion of the total leakage rate received in the drywell sumps that is not identified as previously described. A threat of significant compromise to the nuclear system process barrier exists if the barrier contains a crack that is large enough to propagate rapidly (critical crack length). The unidentified leakage rate limit must be low because of the possibility that most of the unidentified leakage rate might be emitted from a single crack in the nuclear system process barrier. An allowance for leakage that does not compromise barrier integrity and is not identifiable is made for normal plant operation. The unidentified leakage rate limit is established at 5 gpm rate to allow time for corrective action before the process barrier could be significantly compromised. This 5 gpm unidentified leakage rate is a small fraction of the calculated flow from a critical crack in a primary system pipe (Figure 5.2-13). 5.2.5.5.2 Sensitivity and Response Times Sensitivity, including sensitivity tests and response time of the leak detection system, is covered in Section 5.2.5.10.
CPS/USAR CHAPTER 05 5.2-42 REV. 11, JANUARY 2005 5.2.5.5.3 Length of Through-Wall Flaw Experiments conducted by GE and Battelle Memorial Institute, (BMI), permit an analysis of critical crack size and crack opening displacement (Reference 4). This analysis relates to axially oriented through-wall cracks. (1) Critical Crack Length Satisfactory empirical expressions to predict critical crack length have been developed to fit test results. A simple equation which fits the data in the range of normal design stresses (for carbon steel pipe) is h D 15000 L C= (see data correlation on Figure 5.2-14) where L c = critical crack length (in.) D = mean pipe diameter (in.) h = nominal hoop stress (psi). (2) Crack Opening Displacement The theory of elasticity predicts a crack opening displacement of E L 2= where L = crack length = applied nominal stress E = Young's modulus Measurements of crack opening dis placement made by BMI show that local yielding greatly increases the crack opening displacement as the applied stress approaches the failure stress f. A suitable correction factor for plasticity effects is:
C= sec ( ) (2 f) (5.2-2) The crack opening area is given by f 2 2 sec E 2 L L 4 C A== (5.2-3)
CPS/USAR CHAPTER 05 5.2-43 REV. 11, JANUARY 2005 For a given crack length L, f = 15,000 D/L. (3) Leakage Flow Rate The maximum flow rate for blowdown of saturated water at 1000 psi is 55 lb/sec- in 2 and for saturated steam the rate is 14.6 lb/sec-in 2, (Reference 5). Friction in the flow passage reduces this rate, but for cracks leaking at 5 gpm (0.7 lb/sec) the effect of friction is small. The required leak size for 5 gpm flow is A = 0.0126 in 2 (saturated water)
A = 0.0475 in 2 (saturated steam) From this mathematical model, the critical crack length and the 5 gpm crack length have been calculated for representative BWR pipe size (Schedule 80) and pressure (1050 psi). The lengths of through-wall cracks that would leak at the rate of 5 gpm given as a function of wall thickness and nominal pipe size are:
Nominal Pipe Size (Sch 80), in. Average Wall Thickness, in. Crack Length Steam Line L, in. Water Line 4 0.337 7.2 4.9 12 0.687 8.5 4.8 24 1.218 8.6 4.6 The ratios of crack length, L, to the critical crack length, Lc as a function of nominal pipe size are: Ratio L/Lc Nominal Pipe Size (Sch 80), in. Steam Line Water line 4 0.745 0.510 12 0.432 0.243 24 0.247 0.132 It is important to recognize that the failure of ductile piping with a long, through-wall crack is characterized by large crack opening displacements which precede unstable rupture. Judging from observed crack behavior in the GE and BMI experimental pr ograms, involving both circumferential and axial cracks, it is estimated that leak rates of hundreds of gpm will precede crack instability. Measured crack opening displacements for the BMl experiments were in the range of 0.1 to 0.2 in. at the time of incipient rupture, corresponding to leaks of the order of 1 sq in. in size for plain carbon steel piping. For austenitic stainless steel piping, even larger leaks are expected to precede crack instability, although there are insufficient data to permit quantitative prediction. The results given are for a longitudinally oriented flaw at normal operating hoop stress. A circumferentially oriented flaw could be subjected to stress as high as the 550°F yield stress, assuming high thermal expansion stresses exist. It is assumed that the longitudinal crack, subject to a stress as high as 30,000 psi, constitutes a "worst case" with regard to leak rate versus critical size relationships. Given the same stress level, differences between the circumferential and longitudinal orientations are not expected to be significant in this comparison.
CPS/USAR CHAPTER 05 5.2-44 REV. 11, JANUARY 2005 Figure 5.2-13 shows general relationships between crack length, leak rate, stress, and line size, using the mathematical model described previously. The asterisks denote conditions at which the crack opening disp]acement is 0.1 in., at which time instability is imminent as noted previously under "Leakage Flow Rate". This provides a realistic estimate of the leak rate to be expected from a crack of critical size. In every case, the leak rate from a crack of critical size is significantly greater than the 5 gpm criterion. If either the total or unidentified leak rate limits are exceeded, an orderly shutdown is initiated and the reactor is placed in a cold shutdown condition within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. 5.2.5.5.4 Margins of Safety The margins of safety for a detectable flaw to reach critical size are presented in subsection 5.2.5.5.3. Figure 5.2-13 shows general relationships between crack length, leak rate, stress and line size using the mathematical model. 5.2.5.5.5 Criteria to Eva]uate the Adequacy and Margin of the Leak Detection System For process lines that are normally open, there are at least two different methods of detecting abnormal leakage from each system within the nuclear system process barrier located in the drywell, reactor building, and auxiliary building as shown in Tables 5.2-9a and 5.2-9b. The instrumentation is designed so it can be set to provide alarms at established leakage rate limits and isolate the affected system, if necessary. The alarm points are determined analytically or based on measurements of appropriate parameters made during startup and preoperational tests. The unidentified leakage rate limit is based, with an adequate margin for contingencies, on the crack size large enough to propagate rapidly. The established limit is sufficiently low so that, even if the entire unidentified leakage rate were coming from a single crack in the nuclear system process barrier, corrective action could be taken before the integrity of the barrier would be threatened. The leak detection system will satisfactorily detect unidentified leakage of 5 gpm.
5.2.5.6 Differentiation Between Identified and Unidentified Leaks Subsection 5.2.5.1 describes the systems that are monitored by the leak detection system. The ability of the leak detection system to differentiate between identified and unidentified leakage is discussed in subsections 5.2.5.4, 5.2.5.5, and 7.6. 5.2.5.7 Sensitivity and Operability Tests Sensitivity, including sensitivity testing and response time of the leak detection system, and the criteria for shutdown if leakage limits are exceeded, are covered in section 7.6. Testability of the leakage detection system is contained in section 7.6. 5.2.5.8 Safety Interfaces The Balance of Plant-GE Nuclear Steam Supply System safety interfaces for the Leak Detection System are the signals from the monitored balance of plant equipment and systems which are CPS/USAR CHAPTER 05 5.2-45 REV. 13, JANUARY 2009 part of the nuclear system process barrier, and associated wiring and cable lying outside the Nuclear Steam Supply System Equipment. 5.2.5.9 Testing and Calibration Provisions for testing and calibration of the leak detection system are covered in Chapter 14.0 "Initial Test Program". In addition, the drywell floor drain sump inlet piping is verified to be unblocked every 48 months during plant shutdown. This ensures that leakage from unidentified sources inside the drywell is being collected in drywell floor drain sump and is being monitored. 5.2.5.10 Regulatory Guide 1.45 Compliance The detection of leakage through the reactor coolant pressure boundary, described in the preceeding subsections, is in compliance with Regulatory Guide 1.45. Details of compliance are discussed in the following: Leakage is separated into identified and unidentified categories and each is independently monitored, thus meeting position C.1 of Regulatory Guide 1.45. Leakage from unidentified sources inside the drywell is collected into the floor drain sump and monitored with an accuracy better than 1 gallon per minute, thus meeting position C.2 of Regulatory Guide 1.45. By monitoring 1) floor drain sump flow, 2) airborne gases or particulates, and 3) air coolers condensate flow rate, position C.3 is satisfied. Monitoring intersystem leakage into the Component Cooling Water System using the surge tank level instrument, and monitoring of cooling water for radiation from the RHR and RWCS heat exchangers satisfies position C.4. For radiation monitoring system detail, see Process Radiation Monitoring System, Section 11.5. The floor drain sump monitoring and air cooler condensate monitoring are designed to detect leakage rates of 1 gpm within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> except as described in USAR section 1.8. The air particulate monitor will not detect leakage rates of 1 gpm in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> due to substantial limitations as discussed in Section 5.2.5.2.2. This is an exception to position C.5. The particulate channel of the fission products monitoring sub-system is qualified for SSE. The containment floor drain sump and air coolers are not required to operate during and after seismic events, thus meeting position C.6. It must be noted, however, that administrative procedures can be utilized to verify operability following a seismic event if required. Procedures for converting various indications to a common leakage equivalent are available to the operators. The calibration of the indicators accounts for needed independent variables.
Leak detection indicators and alarms are provided in the main control room. This satisfies position C.7. The leakage detection system is equipped with provisions to permit testing for operability and calibration during the plant operation using the following methods:
CPS/USAR CHAPTER 05 5.2-46 REV. 11, JANUARY 2005 (1) simulation of signals into trip units (2) comparing channel "A" to channel "B" of the same leak detection method (e.g., area temperature monitoring) (3) operability checked by comparing one method versus another (e.g., sump fillup versus pumpout, particulate monitoring air cooler condensate flow versus sump fillup rate) (4) continuous monitoring of floor drain sump level is provided These satisfy position C.8.
The Bases for the Technical Specifications discuss the various types of leak detection instrumentation. The limits and applicability are stated in the Technical Specifications. Limiting unidentified leakage to 5 gpm and identified leakage to 25 gpm satisfies position C.9.
5.2.6 References
(1) R. Linford, "Analytical Methods of Plant Transient Evaluation for the General Electric Boiling Water Reaction," NEDO-10802, April 1973. (2) J. M. Skarpelos and J. W. Bagg, "Chloride Control in BWR Coolants," June, 1973, NEDO-10899. (3) W. L. Williams, Corrosion, Vol. 13, 1957, p. 539t. (4) GEAP-5620, Failure Behavior in ASTM A106B Pipes Containing Axial Through-Wall Flaws, by M. B. Reynolds, April, 1968. (5) "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactor Plants," NUREG-76/067, NRC/PCSG, dated October
1975. (6) "Vessel Overpressure Transient Analysis", GE Document No. 457HA213. (7) Standard for Light Water Reactor Coolant Pressure Boundary Leak Detection, ANSI/ISA 67.03-1982. (8) "SRV Safety Setpoint Tolerance and Out-of-Service Analysis for Clinton Power Station," General Electric Company Report NEDC-32202P, August 1993.
CPS/USAR CHAPTER 05 5.2-47 REV. 11, JANUARY 2005 TABLE 5.2-1 REACTOR COOLANT PRESSURE BOUNDARY COMPONENTS APPLICABLE CODE CASES APPLICABLE COMPONENT 1141-1 RPV Foreign Produced Steel 1332-6 RPV Requirements for Steel Forgings 1361-2 CRD Socket Welds 1535-2 MSIV Hydrostatic Testing of Section III Class I Valves 1557-2 RPV Steel Product Refined by Secondary Remelting 1571 Main Steam Additional Material for SA234 Carbon Steel FittingsSection III System Pipe 1572 RPV Fracture Toughness,Section IV, Class 1 Components 1620 RPV Stress Category for Partial Penetration Welded PenetrationsSection III, Class 1 Construction 1622 MSIV PWHT of Repair Welds in Carbon Steel Castings,Section III, Classes 1, 2, and 3. 1637 Recirc. Pump, Effective date for Compliance with NA-3700 of Section III HPCS Valve N207 CRD Use of Modified SA-479 Type XM-19 for Section III, Div. 1, Class 1, 2 or 3 Construction.
1567 HPCS Valve Testing Lots of Carbon and Low-Alloy steel covered electrodes,Section III.
CPS/USAR CHAPTER 05 5.2-48 REV. 11, JANUARY 2005 TABLE 5.2-2 NUCLEAR SYSTEM SAFETY/RELIEF SET PRESSURES AND CAPACITIES (See Reference 6)
Low-Low Set Relief No. of Valves Spring Set Pressure (Psig) ASME Rated Capacity @
103% Spring Set Pressure (1lb/hr each)
Relief Pressure Set Pressure (psig) No. of Valves Setpoint Open/Close 7 1165 895,000 5 1180 906,000 4 1190 913,000 1 1103* 1 1033/926 8 1113* 1 1073/936 3 1113/946 7 1123*
- Closing setpoint is 100 psi below opening setpoint. Note: Seven of the Safety/Relief Valves serve in the Automatic Depressurization Function.
CPS/USAR CHAPTER 05 5.2-49 REV. 11, JANUARY 2005 TABLE 5.2-3 PRESERVICE EXAMINATION COVERAGE Code Edition/Addenda Code Class Coverage 1974/ Summer 1975 1977/ Summer 1978 1 Selection/Exemption Criteria Components, supports, bolting X 1 NDE Methods and Acceptance Criteria Components (except piping), bolting X 1 Piping, supports X 1 Visual Methods and Acceptance Criteria Component, supports, bolting X CPS/USAR CHAPTER 05 5.2-50 REV. 11, JANUARY 2005 TABLE 5.2-4 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS COMPONENT FORM MATERIAL SPECIFICATION (ASTM/ASME)
Reactor Vessel Heads, Shells Rolled Plate or Forgings Low Alloy Steel SA 533 Gr. B Class 1 or SA 508 Cl. 2 Welds Low Alloy Steel SFA 5.5 Closure Flange Forged Ring Low Alloy Steel SA 508 Cl. 2 Welds Low Alloy Steel SFA 5.5 Nozzles Forged Shapes Low Alloy Steel SA 508 Cl. 2 Welds Low Alloy Steel SFA 5.5 Nozzle Safe Ends Forgings or Plate Stainless Steel SA 182, F304, or F316SA 336, F8 or F8MSA 240, 304 or 316 Welds Stainless Steel SFA 5.9 TP. 308L or 316LSFA 5.4 TP. 308L or 316L Nozzle Safe Ends Forgings Ni-Cr-Fe SB166 or SB167 Welds Ni-Cr-Fe SFA 5.14 TP. ER Ni-Cr-3 or SFA 5.11 TP. EN Cr Fe-3 Nozzle Safe Ends Forgings Carbon Steel SA 105 Gr 2, SA 106 Gr B or SA 508 CL. 1 Welds Carbon Steel SFA 5.1, SFA 5.18 GPA, or SFA 5.17 F70. Cladding Weld Overlay Austenitic Stainless Steel N/A Main Steam Piping Pipe Seamless Pipe Carbon Steel SA333GR.6(G.E.B50yP15z)
L. R. Elbow Fitting Carbon Steel SA-234GR.WPBW with Code Case 1571 Nozzle Forging Carbon Steel SA-105 Lugs Plate Carbon Steel SA-516 GR.70 Relief Valve Piping Pipe Seamless Carbon Steel SA-106 GR.B Elbow Fitting Carbon Steel SA-234 GR.WPB Pipe Seamless Carbon Steel SA-106 GR.B Boss Plate Carbon Steel SA-516 GR.70 CPS/USAR TABLE 5.2-4 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS (Continued) CHAPTER 05 5.2-51 REV. 11, JANUARY 2005 COMPONENT FORM MATERIAL SPECIFICATION (ASTM/ASME) Mounting Flange Plate Carbon Steel SA-516 GR.70 Flange Weld Neck Carbon Steel SA-105 Ball Joint Fitting Carbon Steel SA-234 GR.WPB
Ricirculation Piping Pipe Welded Pipe Stainless SA-358-GR.304 Class 1 Pipe Seamless Stainless SA-376-TP.304 Cross Fitting Stainless SA-403GR.WP304 Red Tee Fitting Stainless SA-403GR.WP304W L.R. Elbow Fitting Stainless SA-403GR.WP304W Conc. Reducer Fitting Stainless SA-403GR.WP304 or WP304W Std. Cap Fitting Stainless SA-403GR.WP304 or WP304W Contour Nozzle Fitting Stainless SA-403GR.WP304 Flange Forging Stainless SA-182 GR.F316 Decon. Flange Bolt Stainless SA-193GR.B7 Decon. Flange Hexnut Stainless SA-194GR.7 Pipe Seamless SA-376*
Pipe Welded Pipe SA-358* Elbow Fitting SA-403*
CRD CRD Flanges Forging Austenitic Stainless Steel SA182 CRD Nut, base Bar XM-19 SA-479 CRD Indicator Tube Pipe Austenitic Stainless Steel SA312GR.TP316 CRD Housing Tube Stainless Steel SA312 Tube Inconel 600 SB167
- TP316 Carbon .020 Wt/% Max CPS/USAR TABLE 5.2-4 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS (Continued) CHAPTER 05 5.2-52 REV. 11, JANUARY 2005 COMPONENT FORM MATERIAL SPECIFICATION (ASTM/ASME) Flange Forging Stainless Steel SA182 Welds Stainless Steel SFA5.9 ER308L or ER308Si SFA5.4 E308L Welds Inconel SFA 5.11 ENiCrFe-3 SFA 5.14 ERNiCr-3 Incore Housing Tube Inconel SB167 Flange Forging Stainless Steel SA 182 Welds Inconel SFA 5.11 ENiCrFe-3 SFA 5.14 ERNiCr-3
Main Steamline Flow Element Forged Carbon steel SA105 Main Steam Isolation Valve Body Casting Carbon Steel SA216GrWCB Disc Forging Carbon steel SA350GRLF2 Cover Forging Carbon steel SA-105 Stem Rod Stainless steel SA564GR630 Studs Bolt Alloy Steel SA540 B23 CL5 Nuts Bolt Alloy Steel SA540 B23 CL5
Main Steam Safety Relief Valve Body Casting Carbon Steel SA 352 LCB Seat Forging Carbon Steel SA 350 LF2 Disc Casting Stainless Steel SA 351 CF3A
CPS/USAR TABLE 5.2-4 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS (Continued) CHAPTER 05 5.2-53 REV. 11, JANUARY 2005 COMPONENT FORM MATERIAL SPECIFICATION (ASTM/ASME) Recirculation Gate Valves Body Casting Stainless Steel SA351 GR CF8M Bonnet Casting Stainless Steel SA351 GR CF8M Stem Bar Stainless Steel SA564 Type 630 Condition 1150 Disc Casting or Stainless Steel Forged Stainless Steel SA351 CF3A SA182 Gr F347 Nuts Bar Carbon Steel SA194GR7 Bolts Bar Carbon Steel SA193GRB7
- Only for 1B21-F022B,C,D and 1B21-F028A.
Recirculation Pump Pump Case Casting Cast Stainless St. SA351 GR CF8M Lifting Lug Plate Stainless St. SA240 Type 304/316 Shock Suppressor Lug Plate Stainless St. SA240 Type 316 Shock Suppressor Lug Plate Stainless St. SA240 Type 316 Shock Suppressor Lug Plate Stainless St. SA240 Type 316 Stud-Case to Stuff. Box (31/4-8N) Bar Alloy Steel SA540 GR B23 C1 5 Stud Nut (31/4-8N) Bar Alloy Steel SA194 Gr 7 Stuffing Box Casting Cast Stainless St. SA351 CF8M Nozzle - 1" Forging Stainless St. SA182 Type F304/F316 Nozzle - 1" Forging Stainless St. SA182 Type F304/F316 Nozzle - 3/4" Forging Stainless St. SA182 Type F304/F316 Flange Nozzle - 1" Forging Stainless St. SA182 Type F304/F316 Flange 1" - 150# ASA Soc Weld Forging Stainless St. SA182 Type F304/F316 Lifting Lugs Plate Stainless St. SA240 Type 304/316 CPS/USAR TABLE 5.2-4 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS (Continued) CHAPTER 05 5.2-54 REV. 11, JANUARY 2005 COMPONENT FORM MATERIAL SPECIFICATION (ASTM/ASME) Flange Nozzle 3/4" Forging Stainless St. SA182 Type F304/F316 Flange 3/4" - 1500#
Soc Weld Forging Stainless St. SA182 Type F304/F316 Thrust Ring Forging Stainless St. SA182 Type F304/F316 Pump Flange Forging Carbon St. SA350 Gr LF2 Motor Stand Barrel Plate Carbon St. SA516 Gr 70 Brace Plate Carbon St. SA516 Gr 70 Brace Plate Carbon St. SA516 Gr 70 Strut Lug Plate Carbon St. SA36 Strut Lug Plate Carbon St. SA36 Seal Holder Cast Stainless St. SA351 GR. CF 8 Plug Forging Stainless St. SA182 GR. F304 Upper Seal Gland Cast Stainless St. SA351 GR. CF 8 Clamp - 1" Pipe Size Cast Stainless St. SA351 Gr CF8/CF8M Stud Complete w/Nuts Bar Alloy St. SA193 Gr B8/ASME SA194 GR 8 Pipe - 1" Sch 80
(.179 Wall) Pipe Stainless St. SA312 Gr TP 304/316 Hub - 1" - Soc Weld Forging Stainless St. SA182 Type F304/F316 Tee - 1" Pipe 3000#
Soc Weld Forging Stainless St. SA182 Type F304/ F316 Thermowell for 1" Tee Forging Stainless St. SA182 Type F304/ F316 Pipe - 1" Sch 80
.179 Wall) Pipe Stainless St. SA312 Gr TP 304/316 Flange-1"-1500# Soc Weld Lg
Grv Forging Stainless St. SA182 Type F304/ F316 Hub-1" Soc Weld Forging Stainless St. SA182 Type F304/ F316 Tee-1" Pipe3000#
Soc Weld Forging Stainless St. SA182 Type F304/ F316 Thermowell for 1" Tee Forging Stainless St. SA182 Type F304/ F316 CPS/USAR TABLE 5.2-4 REACTOR COOLANT PRESSURE BOUNDARY MATERIALS (Continued) CHAPTER 05 5.2-55 REV. 11, JANUARY 2005 COMPONENT FORM MATERIAL SPECIFICATION (ASTM/ASME) Pipe Plug-3/4" NPT Forging Stainless St. SA182 Type F304/ F316 Pipe 3/4 Sch 80
(.154 Wall) Pipe Stainless St. SA312 Gr TP 304/ F316 Tee 3/4" Pipe 3000# Soc
Weld Forging Stainless St. SA182 Type F304/ F316 Thermowell for 3/4" Tee Forging Stainless St. SA182 Type F304/ F316 Flange 3/4-1500# Soc Weld Lg
Grv Forging Stainless St. SA182 Type F304/ F316 Hub - 3/4" Soc Weld Forging Stainless St. SA182 Type F304/ Valve Body Plate Stainless St. SA240 Type 304/316 Valve Bonnet Plate Stainless St. SA240 Type 304/316 Coil Inner 1 1/4 Tube x .065
wall Pipe Stainless St. SA213 Gr TP 316 Tee 1 1/4 Tube x 1" Pipe Run 3000# Forging Stainless St. SA182 Type F304/F316 Pipe Cap 1" Soc Weld - 3000# Forging Stainless St. SA182 Type F304/F316 Flange 1" -1500# Soc Weld Lg
Groove Forging Stainless St. SA182 Type F304/F316 Hub 1" Soc Weld Forging Stainless St. SA182 Type F304/F316 Pipe 1" Sch 80
(.179 wall) Pipe Stainless St. SA312 Gr TP 304/TP 316 CPS/USAR CHAPTER 05 5.2-56 REV. 11, JANUARY 2005 TABLE 5.2-5 RCPB PUMP AND VALVE DESCRIPTION
THIS TABLE HAS BEEN DELETED.
CPS/USAR CHAPTER 05 5.2-57 REV. 11, JANUARY 2005 TABLE 5.2-6 TYPICAL BWR WATER CHEMISTRY A CONCENTRATIONS - PARTS PER BILLION (ppb) CONDUCTIVITY (µmho/cm - (pH - IRON COPPERCHLORIDE OXYGEN 25°C) 25°C Condensate (1)* 15-30 3-5 20 20-50 0.1 7 Condensate Treatment Effluent (2)*
5-15 1 0.2 20-50 0.1 7 Feedwater (3)* 5-15 1 0.2 20-50 0.1 7 Reactor Water (4)* Mode 1 10-50 20 200 100-300 1.0 5.6-8.6 Mode 2 and 3 10-50 20 100 100-300 2.0 5.6-8.6 Mode 4 and 5 10-50 20 500 8000 10.00 5.3-8.6 Steam (5)* 0 0 0 10000-30000 0.1 Control Rod Drive Cooling
Water (6)* 50-500 - 20 50 0.1 7
- Numerals in parentheses refer to locations delineated on Figure 5.2-11 Represents the word approximately A Chemistry limits are specified in plant procedures CPS/USAR CHAPTER 05 5.2-58 REV. 11, JANUARY 2005 TABLE 5.2-7 SYSTEMS WHICH MAY INITIATE DURING OVERPRESSURE EVENT SYSTEMS INITIATING/TRIP SIGNAL (S)
- Reactor Protection System RCIC Reactor trips "OFF" on High Flux "ON" when Reactor Water Level at L2 "OFF" when Reactor Water Level at L8 HPCS "ON" when Reactor Water Level at L2 "ON" when Drywell Pressure at 2 psig "OFF" when Reactor Water Level at L8 Recirculation System "OFF" when Reactor Water Level at L2 "OFF" when Reactor Pressure at 1127 psig RWCU "OFF" when Reactor Water Level at L2
- Vessel level trip settings are shown on Figure 5.3-2.
CPS/USAR CHAPTER 05 5.2-59 REV. 11, JANUARY 2005 Table 5.2-8 WATER SAMPLE LOCATIONS Conductivity (µmho/cm) Sample Origin Sensor Location Indicator Location Recorder Location Range Alarm High Setpoint Low Minimum Loop Accuracy Reactor Water Recirculation Loop Sample Line Panel G33-Z020 Control Room 0.1-10* 1.0 0.05 +/-1.1***
Reactor Water Cleanup System
Inlet Sample Line Panel G33-Z020 Control Room 0.1-10* 1.0 0.05 +/-1.1***
Reactor Water Cleanup System Outlets Sample Line Panel G33-Z020 Control Room 0.01-1** 0.1 0.02 +/-1.1 Control Rod Drive System Sample Line Panel G33-Z020 Control Room 0.01-1** 0.1 0.05 +/-1.1
- The instrument is nonlinear with 1 µmho/cm near midscale to facilitate readings at the normally low levels (i.e., 1 µmho/cm). ** The instrument is nonlinear with 0.1 µmho/cm near midscale. *** The accuracy is expressed as percent of full scale. The instruments are sensitive to within or less than the accuracy, an d at least one of these instruments is periodically (1/week) verified against laboratory calibration instruments.
CPS/USAR CHAPTER 05 5.2-60 REV. 12, JANUARY 2007 Table 5.2-9a
SUMMARY
OF ISOLATION/ALARM OF SYSTEM MONITORED AND THE LEAK DETECTION METHODS USED (Summary of Variable Trip Alarms Leakage Source vs. Generated Variables)
Affected Variable Monitored Source of Leakage a b c d e f g h i j k l m n o p q r s t u v X A A A A A A A A A Main Steamline X A A A A RCIC Steamline X A A A A A A A 8" Nominal Size X A A A A A RCIC Steamline X 4" Nominal Size X A A A A A X A A A A A A A A A RWCU Water X A A A A A A X A A A HPCS Water X X A A A LPCS Water X X A A A Recirc Pump Seal X X A A A A A A Feedwater X A A A X A A A A A A A A RHR Water X A A A A Reactor Vessel X A Head Seal X Upper Containment X A A Pool X A A Miscellaneous X A Leaks X A A X A A Valve Stem Packing X RCIC Water X A X A = Alarm and indicate (or record) only. X = Location of leakage source.
CPS/USAR CHAPTER 05 5.2-61 REV. 11, JANUARY 2005 Legend of Table 5.2-9a a. Located Inside Drywell
- b. Located Outside Drywell
- c. Drywell Pressure, High d. Reactor Water Level, Low e. Floor Drain Sump Fillup Rate, High (Containment)
- f. Equipment Drain Sump Flow Rate, High (Containment)
- g. Fission Product Radiation, High
- h. Drywell Temperature, High
- i. Safety/Relief Valve Discharge Pipe Temperature, High j. MSL Guard Pipe Temperature, High k. Valve Stem Leakoff Temperature, High
- l. Recirculation Pump Seal Flow, High
- m. Seal Pressure, High
- n. Air Cooler Condensate Flow, High
- o. Steam Flow Rate, High p. Sump or Drain Flow, High (Equipment Area) q. MSL Tunnel Ambient, High r. Equipment Area Ambient, High s. RWCU Differential Flow, High
- t. Seal Drain Flow, High
- u. Intersystem Leakage (Radiation), High v. ECCS Injection Line Leakage (Internal to Reactor Vessel) Differential Pressure CPS/USAR CHAPTER 05 5.2-62 REV. 11, JANUARY 2005 TABLE 5.2-9b
SUMMARY
OF ISOLATION/ALARM OF SYSTEM MONITORED AND THE LEAK DETECTION METHODS USED (Summary of Isolation Signals and Alarms System Isolation vs. Variable Monitored) Variable Monitored System Isolated** a b c d e f g h i j k l m n o p Main Steam I I I I Recirc (Sample line) I RHR I I I RCIC I I* I I I I RWCU I I I I Containment Isolation I I
- Systems or selected valves within the system that isolate.
I - Isolate alarm, and indicate (or record).
- RCIC turbine exhaust vacuum breaker line valves only. _____________________ a. Reactor Vessel Water Level
- b. Turbine Building Leak Detection
- c. MS Tunnel Ambient Temperature, High
- d. Deleted e. MS Line Flow Rate, High f. Drywell Pressure, High g. RHR Equipment Area Ambient Temperature, High
- h. Deleted i. RCIC Equipment Area Ambient Temperature, High
- j. Deleted k. RCIC Exhaust Diaphragm Pressure, High l. RCIC Steam Supply Differential Pressure (High Flow) m. RCIC Steam Supply Differential Pressure (Instr. Line Break)
- n. RWCU Process Piping Differential Flow, High
- o. RWCU Equipment Area Ambient Temperature, High
- p. Deleted CPS/USAR CHAPTER 05 5.2-63 REV. 11, JANUARY 2005 TABLE 5.2-10 SEQUENCE OF EVENTS FOR Figure 5.2-1 (1) TIME-SEC EVENTS 0 Initiate closure of all main steam isolation valves (MSIV) 0.3 MSIVs reached 90% open and initiated reactor scram. However, hypothetical failure of this position scram was assumed in this analysis. 1.6 Neutron flux reached the APRM flux scram setpoint and initiated reactor scram. 2.3 Reactor dome pressure reached the pressure setpoint (power actuated mode).
Only one half of valves in this group was assumed functioning. 2.3 Steamline pressure reached the safety/relief valve pressure setpoint (spring action mode). Valves which were not opened in the power actuated mode were
opened. 3.0 MSIVs completely closed. 3.4 Safety/relief valves opened in either power actuated mode or spring action mode due to high pressure. 3.4 Vessel bottom pressure reached its peak value.
12.6 Safety/Relief valves opened in their spring action mode closed. 19.2 (est) Safety/relief valves opened in their power-actuated mode closed. 50 (est) Reactor reached a limited cycle.
___________________________
Note: 1. This sequence of events was assumed for the initial cycle analysis of safety/relief valve capacity. The results of the current cycle analysis for this transient are provided in Appendix 15D, Reload Analysis.
CPS/USAR CHAPTER 05 REV. 12, JAN 2007 FIGURE 5.2-6 HAS BEEN DELETED
CPS/USAR CHAPTER 05 REV. 12, JAN 2007 FIGURE 5.2-9 HAS BEEN DELETED
CPS/USAR REV. 10,October 2001 Figure 5.4-2 Deleted
CPS/USAR CHAPTER 05 REV. 12, JAN 2007 FIGURE 5.4-4 HAS BEEN DELETED
CPS/USAR REV. 10,October 2001 Figures 5.4-9 and 5.4-10 Deleted
CPS/USAR REV. 10,October 2001 Figures 5.4-13 and 5.4-14 Deleted
CPS/USAR REV. 10,October 2001 Figures 5.4-16 through 5.4-19 Deleted
CPS/USAR CHAPTER 05 REV. 12, JAN 2007 FIGURE 5.4-22 HAS BEEN DELETED