ML23193A896

6 to Updated Final Safety Analysis Report, Chapter 5, Reactor Coolant System and Connected Systems

ML23193A896
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Site:	Millstone
Issue date:	06/28/2023
From:	Dominion Energy Nuclear Connecticut
To:	Office of Nuclear Reactor Regulation
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Millstone Power Station Unit 3 Safety Analysis Report Chapter 5: Reactor Coolant System and Connected Systems

Table of Contents tion Title Page

SUMMARY

DESCRIPTION..................................................................... 5.1-1 1 Schematic Flow Diagram............................................................................ 5.1-6 2 Piping and Instrumentation Diagram .......................................................... 5.1-6 3 Elevation Drawing ...................................................................................... 5.1-6 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY.............................................................................................. 5.2-1 1 Compliance with Codes and Code Cases ................................................... 5.2-1 1.1 Compliance with 10 CFR 50.55a................................................................ 5.2-1 1.2 Applicable Code Cases ............................................................................... 5.2-1 2 Overpressure Protection.............................................................................. 5.2-2 2.1 Design Bases............................................................................................... 5.2-3 2.2 Design Evaluation....................................................................................... 5.2-3 2.3 Piping and Instrumentation Diagrams ........................................................ 5.2-4 2.4 Equipment and Component Description..................................................... 5.2-4 2.5 Mounting of Pressure-Relief Devices......................................................... 5.2-4 2.6 Applicable Codes and Classification .......................................................... 5.2-5 2.7 Material Specifications ............................................................................... 5.2-5 2.8 Process Instrumentation .............................................................................. 5.2-5 2.9 System Reliability....................................................................................... 5.2-6 2.10 Testing and Inspection ................................................................................ 5.2-6 2.11 RCS Pressure Control during Low Temperature Operation ....................... 5.2-6 2.11.1 System Operation........................................................................................ 5.2-6 2.11.2 Evaluation of Low Temperature Overpressure Transients ......................... 5.2-7 2.11.3 Operating Basis Earthquake Evaluation ..................................................... 5.2-7 2.11.4 Administrative Procedures.......................................................................... 5.2-7 3 Materials Selection, Fabrication, and Processing ..................................... 5.2-10 3.1 Material Specifications ............................................................................. 5.2-10 3.2 Compatibility With Reactor Coolant ........................................................ 5.2-11 3.2.1 Chemistry of Reactor Coolant .................................................................. 5.2-11

tion Title Page 3.2.2 Compatibility of Construction Materials with Reactor Coolant ............... 5.2-11 3.2.3 Compatibility with External Insulation and Environmental Atmosphere ............................................................................................... 5.2-12 3.3 Fabrication and Processing of Ferritic Materials ...................................... 5.2-12 3.3.1 Fracture Toughness................................................................................... 5.2-12 3.3.2 Control of Welding ................................................................................... 5.2-13 3.3.3 Pressurized Thermal Shock ...................................................................... 5.2-13 3.4 Fabrication and Processing of Austenitic Stainless Steel ......................... 5.2-14 3.4.1 Cleaning and Contamination Protection Procedures ................................ 5.2-14 3.4.2 Solution Heat Treatment Requirements.................................................... 5.2-14 3.4.3 Material Inspection Program .................................................................... 5.2-15 3.4.4 Prevention of Intergranular Attack of Unstabilized Austenitic Stainless Steels.......................................................................................... 5.2-15 3.4.5 Retesting Unstabilized Austenitic Stainless Steel Exposed to Sensitization Temperatures....................................................................... 5.2-17 3.4.6 Control of Welding ................................................................................... 5.2-18 4 Inservice Inspection and Testing of Reactor Coolant Pressure Boundary 5.2-19 4.1 System Boundary Subject to Inspection ................................................... 5.2-19 4.2 Accessibility.............................................................................................. 5.2-20 4.3 Examination Techniques and Procedures ................................................. 5.2-22 4.4 Inspection Intervals................................................................................... 5.2-23 4.5 Examination Categories and Requirements .............................................. 5.2-23 4.6 Evaluation of Examination Results........................................................... 5.2-23 4.7 System Leakage and Hydrostatic Pressure Tests...................................... 5.2-23 4.8 Relief Requests ......................................................................................... 5.2-23 5 Detection of Leakage Through Reactor Coolant Pressure Boundary....... 5.2-24 5.1 Controlled Leakage................................................................................... 5.2-24 5.2 Identified Leakage .................................................................................... 5.2-24 5.2.1 Definition of Identified Leakage............................................................... 5.2-24 5.2.2 Collection and Monitoring of Identified Leakage .................................... 5.2-24 5.2.3 Reactor coolant pump shaft seal leakage .................................................. 5.2-25

tion Title Page 5.3 Unidentified Leakage................................................................................ 5.2-26 5.3.1 Definition of Unidentified Leakage .......................................................... 5.2-26 5.3.2 Collection of Unidentified Leakage.......................................................... 5.2-26 5.3.3 Detection of Unidentified Leakage........................................................... 5.2-26 5.3.4 Leakage Detection Method Sensitivity and Response Times................... 5.2-26 5.3.5 Leakage Detection Method Indicators and Alarms .................................. 5.2-27 5.3.6 Seismic Capability of Leakage Detection Methods.................................. 5.2-28 5.3.7 Testing and Calibration............................................................................. 5.2-28 5.4 Intersystem Leakage ................................................................................. 5.2-28 5.5 Technical Specifications ........................................................................... 5.2-30 5.6 Primary Coolant Sources Outside Containment ....................................... 5.2-30 6 References for Section 5.2 ........................................................................ 5.2-32 REACTOR VESSEL .................................................................................. 5.3-1 1 Reactor Vessel Materials ............................................................................ 5.3-1 1.1 Material Specifications ............................................................................... 5.3-1 1.2 Special Process Used for Manufacturing and Fabrication.......................... 5.3-1 1.3 Special Methods for Nondestructive Examination ..................................... 5.3-2 1.3.1 Ultrasonic Examination .............................................................................. 5.3-2 1.3.2 Penetrant Examinations .............................................................................. 5.3-2 1.3.3 Magnetic Particle Examination................................................................... 5.3-3 1.4 Special Controls for Ferritic and Austenitic Stainless Steels ..................... 5.3-3 1.5 Fracture Toughness..................................................................................... 5.3-4 1.6 Material Surveillance .................................................................................. 5.3-4 1.6.1 Measurement of Integrated Fast Neutron (E 1.0 MeV)

Flux at the Irradiation Samples ................................................................... 5.3-7 1.6.2 Calculation of Integrated Fast Neutron (E. 1.0 MeV) Flux at the Irradiation Samples ......................................................................... 5.3-10 1.7 Reactor Vessel Fasteners .......................................................................... 5.3-12 2 Pressure-Temperature Limits.................................................................... 5.3-12 2.1 Limit Curves ............................................................................................. 5.3-12

tion Title Page 2.2 End-of-Life RTPTS Projections................................................................. 5.3-13 2.3 Operating Procedures................................................................................ 5.3-14 3 Reactor Vessel Integrity............................................................................ 5.3-14 3.1 Design ....................................................................................................... 5.3-14 3.2 Materials of Construction ......................................................................... 5.3-15 3.3 Fabrication Methods ................................................................................. 5.3-15 3.4 Inspection Requirements........................................................................... 5.3-15 3.5 Shipment and Installation ......................................................................... 5.3-15 3.6 Operating Conditions ................................................................................ 5.3-16 3.7 Inservice Surveillance............................................................................... 5.3-17 4 References for Section 5.3 ........................................................................ 5.3-19 COMPONENT AND SUBSYSTEM DESIGN.......................................... 5.4-1 1 Reactor Coolant Pumps .............................................................................. 5.4-1 1.1 Pump Flywheel Integrity ............................................................................ 5.4-1 1.1.1 Design Bases............................................................................................... 5.4-1 1.1.2 Fabrication and Inspection.......................................................................... 5.4-1 1.1.3 Material Acceptance Criteria ...................................................................... 5.4-1 1.2 Reactor Coolant Pump Assembly ............................................................... 5.4-2 1.2.1 Design Bases............................................................................................... 5.4-2 1.2.2 Pump Assembly Description ...................................................................... 5.4-2 1.3 Design Evaluation....................................................................................... 5.4-4 1.3.1 Pump Performance...................................................................................... 5.4-4 1.3.2 Coastdown Capability................................................................................. 5.4-6 1.3.3 Bearing Integrity ......................................................................................... 5.4-6 1.3.4 Locked Rotor .............................................................................................. 5.4-6 1.3.5 Critical Speed.............................................................................................. 5.4-7 1.3.6 Missile Generation ...................................................................................... 5.4-7 1.3.7 Pump Cavitation ......................................................................................... 5.4-7 1.3.8 Pump Overspeed Considerations ................................................................ 5.4-7 1.3.9 Anti-Reverse Rotation Device .................................................................... 5.4-8

tion Title Page 1.3.10 Shaft Seal Leakage...................................................................................... 5.4-8 1.3.11 Seal Discharge Piping ................................................................................. 5.4-8 1.4 Tests and Inspections .................................................................................. 5.4-9 2 Steam Generators ........................................................................................ 5.4-9 2.1 Steam Generator Materials ......................................................................... 5.4-9 2.1.1 Selection and Fabrication of Materials ....................................................... 5.4-9 2.1.2 Steam Generator Design Effects on Material ........................................... 5.4-10 2.1.3 Compatibility of Steam Generator Tubing with Primary and Secondary Coolants .................................................................................. 5.4-11 2.1.4 Cleanup of Secondary Side Materials....................................................... 5.4-12 2.2 Steam Generator Inservice Inspection ...................................................... 5.4-12 2.3 Design Basis ............................................................................................. 5.4-13 2.4 Design Description ................................................................................... 5.4-14 2.5 Design Evaluation..................................................................................... 5.4-14 2.6 Quality Assurance..................................................................................... 5.4-16 3 Reactor Coolant Piping ............................................................................. 5.4-17 3.1 Design Bases............................................................................................. 5.4-17 3.2 Design Description ................................................................................... 5.4-18 3.3 Design Evaluation..................................................................................... 5.4-20 3.3.1 Material Corrosion/Erosion Evaluation .................................................... 5.4-21 3.3.2 Sensitized Stainless Steel.......................................................................... 5.4-21 3.3.3 Contaminant Control................................................................................. 5.4-21 3.4 Tests and Inspections ................................................................................ 5.4-21 4 Main Steam Line Flow Restrictor............................................................. 5.4-22 4.1 Design Basis ............................................................................................. 5.4-22 4.2 Design Description ................................................................................... 5.4-22 4.3 Design Evaluation..................................................................................... 5.4-22 4.4 Tests and Inspections ................................................................................ 5.4-22 5 Main Steam Isolation System ................................................................... 5.4-22 6 Reactor Core Isolation Cooling System.................................................... 5.4-23 7 Residual Heat Removal System................................................................ 5.4-23

tion Title Page 7.1 Design Bases............................................................................................. 5.4-23 7.2 System Design .......................................................................................... 5.4-25 7.2.1 Schematic Piping and Instrumentation Diagrams..................................... 5.4-25 7.2.2 Equipment and Component Descriptions ................................................. 5.4-27 7.2.3 System Operation...................................................................................... 5.4-28 7.2.4 Control ...................................................................................................... 5.4-33 7.2.5 Applicable Codes and Classifications....................................................... 5.4-35 7.2.6 System Reliability Considerations............................................................ 5.4-35 7.2.7 Manual Actions......................................................................................... 5.4-37 7.3 Performance Evaluation............................................................................ 5.4-37 7.4 Preoperational Testing .............................................................................. 5.4-38 8 Reactor Water Cleanup System ................................................................ 5.4-38 9 Main Steamlines and Feedwater Piping.................................................... 5.4-38 10 Pressurizer................................................................................................. 5.4-38 10.1 Design Bases............................................................................................. 5.4-38 10.1.1 Pressurizer Surge Line .............................................................................. 5.4-38 10.1.2 Pressurizer................................................................................................. 5.4-39 10.2 Design Description ................................................................................... 5.4-39 10.2.1 Pressurizer Surge Line .............................................................................. 5.4-39 10.2.2 Pressurizer................................................................................................. 5.4-39 10.3 Design Evaluation..................................................................................... 5.4-40 10.3.1 System Pressure ........................................................................................ 5.4-40 10.3.2 Pressurizer Performance ........................................................................... 5.4-41 10.3.3 Pressure Setpoints ..................................................................................... 5.4-41 10.3.4 Pressurizer Spray ...................................................................................... 5.4-41 10.3.5 Pressurizer Design Analysis ..................................................................... 5.4-42 10.3.6 Natural Circulation Following Loss of Off Site Power ............................ 5.4-43 10.4 Inspection and Testing Requirements....................................................... 5.4-43 10.5 Instrumentation Requirements .................................................................. 5.4-43 11 Pressurizer Relief Discharge System ........................................................ 5.4-43 11.1 Design Basis ............................................................................................. 5.4-44

tion Title Page 11.2 System Description ................................................................................... 5.4-44 11.2.1 Pressurizer Relief Tank............................................................................. 5.4-45 11.3 Safety Evaluation ...................................................................................... 5.4-45 11.4 Instrumentation Requirements .................................................................. 5.4-46 11.5 Inspection and Testing Requirements....................................................... 5.4-46 12 Valves ....................................................................................................... 5.4-46 12.1 Design Bases............................................................................................. 5.4-46 12.2 Design Description ................................................................................... 5.4-46 12.3 Design Evaluation..................................................................................... 5.4-47 12.4 Tests and Inspections ................................................................................ 5.4-47 13 Safety and Relief Valves........................................................................... 5.4-48 13.1 Design Bases............................................................................................. 5.4-48 13.2 Design Description ................................................................................... 5.4-48 13.3 Design Evaluation..................................................................................... 5.4-49 13.4 Inspection and Testing Requirements....................................................... 5.4-49 14 Component Supports................................................................................. 5.4-49 14.1 Description................................................................................................ 5.4-50 14.1.1 Reactor Vessel Structural Support (RVSS) .............................................. 5.4-50 14.1.2 Steam Generator Supports ........................................................................ 5.4-50 14.1.3 Reactor Coolant Pump Supports............................................................... 5.4-51 14.1.4 Pressurizer Support ................................................................................... 5.4-51 14.1.5 Pressurizer Safety Valve Supports............................................................ 5.4-51 14.2 Design Basis ............................................................................................. 5.4-51 14.3 Evaluation ................................................................................................. 5.4-52 14.4 Tests and Inspections ................................................................................ 5.4-52 15 Reactor Vessel Head Vent System ........................................................... 5.4-52 15.1 Design Basis ............................................................................................. 5.4-53 15.2 System Description ................................................................................... 5.4-54 15.3 Safety Evaluation ...................................................................................... 5.4-54 15.4 Inspection and Testing Requirements....................................................... 5.4-55 15.5 Instrumentation Requirements .................................................................. 5.4-55

List of Tables mber Title 1 System Design and Operating Parameters 1 Applicable Code Addenda for Class 1 Reactor Coolant System Components 2 Primary and Auxiliary Components Material Specifications 3 Reactor Vessels Internal Material Specifications

-4 Reactor Coolant Water Chemistry Specification 5 Safety Valve Support Bracket Loads 6 Relief Valves Referenced to Code Case N-242 7 Millstone Unit No. 3 rtpts Values (F)

-1 Reactor Vessel Non-Destructive Examination 2 Reactor Vessel Fracture Toughness Properties 3 Reactor Vessel Beltline Region Material Chemical Composition (wt Percent) 4 Adjusted Referenced Temperature (ART) Values (F) 5 Reactor Vessel Design Parameters 1 Reactor Coolant Pump Design Parameters 2 Reactor Coolant Pump Non-Destructive Examination Program

-3 Steam Generator Design Data 4 Steam Generator Nondestructive Examination Program 5 Reactor Coolant Piping Design Parameters 6 Reactor Coolant Piping Quality Assurance Program 7 Design Bases for Residual Heat Removal System Operation 8 Residual Heat Removal System Component Data 9 Residual Heat Removal System - Cold Shutdown Operations-Failure Modes and Effects Analysis 10 Pressurizer Design Data 11 Reactor Coolant System Design Pressure Settings 12 Pressurizer Quality Assurance Program 13 Pressure Relief Tank Design Data

mber Title 14 Relief Valve Discharge to the Pressurizer Relief Tank 15 Reactor Coolant System Design Parameters 16 Non-Destructive Examination Program Reactor Coolant System Valves 17 Pressurizer Valves Design Parameters 18 Equipment Supports, Loading Combinations, and Design Allowable Stresses 19 Reactor Vessel Head Vent System Equipment Design Parameters

List of Figures mber Title 1 (Sheets 1-6) P&IDs Reactor Coolant System

-2 Reactor Coolant System Process Flow Design 1 Reactor Vessel Inspection Area 2 Model F Steam Generator Inspection Area 3 Pressurizer Inspection Areas 1 Identification and Location of Beltline Region Material for the Reactor Vessel 2 Reactor Vessel 1 Reactor Coolant Pump

-2 Reactor Coolant Pump Estimated Performance Characteristics 3 Model F Steam Generator 4 Quatrefoil Tube Support Plates 5 (Sheets 1-3) P&IDs Low Pressure Safety Injection / Containment Recirculation 6 Residual Heat Removal System Process Flow Diagram (Mode A) 7 Pressurizer Relief Tank 8 Pressurizer

-9 RPV Support System 10 Leveling Device (Typical) RPV Support System 11 Vertical Supports (Typical) Reactor Coolant Pumps and Steam Generator

-12 Lateral Support (Typical) Steam Generator

-13 Lateral Support (Typical) Reactor Coolant Pump 14 Pressurizer Support (Sheet 1 of 2) 15 Pressurizer Safety Valve Support System (Sheet 1 of 2)

SUMMARY

DESCRIPTION reactor coolant system (RCS) (Figure 5.1-1) consists of four similar heat transfer loops nected in parallel to the reactor pressure vessel. Each loop contains a reactor coolant pump and m generator. In addition, the system includes a pressurizer, a pressurizer relief tank, rconnecting piping, valves, and instrumentation necessary for operational control. All these ponents are located in the containment building.

ing operation, the RCS transfers the heat generated in the core to the steam generators where m is produced to drive the turbine generator. Borated demineralized water is circulated in the S at a flow rate and temperature consistent with achieving the reactor core thermal-hydraulic ormance. The water also acts as a neutron moderator and reflector, and as a solvent for the tron absorber used in chemical shim control.

RCS pressure boundary provides a barrier against the release of radioactivity generated hin the reactor and is designed to ensure a high degree of integrity throughout the life of the t.

S pressure is controlled by the use of the pressurizer where water and steam are maintained in ilibrium by electrical heaters and water sprays. Steam can be formed (by the heaters) or densed (by the pressurizer spray) to minimize pressure variations due to contraction and ansion of the reactor coolant. Spring-loaded safety valves and power-operated relief valves are unted on the pressurizer and discharge to the pressurizer relief tank, where the steam is densed and cooled by mixing with water.

extent of the RCS is defined as:

1. The reactor vessel including control rod drive mechanism housings

2. The reactor coolant side of the steam generator

3. The reactor coolant pumps

4. A pressurizer attached by a surge line to one of the reactor coolant loops

5. The pressurizer relief tank

6. The safety and relief valves

7. The loop isolation valves

8. The interconnecting piping, valves, and fittings between the principal components listed above

ctor Coolant System Components

1. Reactor Vessel (Section 5.3)

The reactor vessel is cylindrical, with a welded hemispherical bottom head and a removable, flanged and gasketed, hemispherical upper head. The vessel contains the core, core support structures, control rods, and other components directly associated with the core.

The vessel has inlet and outlet nozzles located in a horizontal plane below the reactor vessel flange but above the top of the core. Coolant enters the vessel through the inlet nozzles, flows down the core barrel-vessel wall annulus, and is then redirected at the bottom to flow up through the core and out the outlet nozzles.

2. Steam Generators (Section 5.4.2)

The steam generators are vertical shell and U-tube evaporators with integral moisture separating equipment. The reactor coolant flows through the inverted U-tubes, entering and leaving through the nozzles located in the hemispherical bottom head of the steam generator. Steam is generated on the shell side and flows upward through the moisture separators to the outlet nozzle at the top of the vessel.

3. Reactor Coolant Pumps (Section 5.4.1)

The reactor coolant pumps are single speed centrifugal units driven by air-cooled, three phase induction motors. The shaft is vertical with the motor mounted above the pumps. A flywheel on the shaft above the motor provides additional inertia to extend pump coastdown. The inlet is at the bottom of the pump; discharge is on the side.

4. Piping (Section 5.4.3)

The reactor coolant loop piping is specified in sizes consistent with system requirements.

The hot leg inside diameter is 29 inches and the inside diameter of the cold leg return line to the reactor vessel is 27.5 inches. The piping between the steam generator and the pump suction is increased to 31 inch inside diameter in order to reduce pressure drop and improve flow conditions facilitating pump suction.

5. Pressurizer (Section 5.4.10)

The pressurizer is a vertical, cylindrical vessel with hemispherical top and bottom heads. Electrical heaters are installed through the bottom head of the vessel, while

6. Loop Isolation Valves (Section 5.4.3)

The reactor coolant loop isolation valves are remote controlled motor operated double disk gate valves. The hot and cold leg valves are identical except for the valve nozzles which are sized to match the corresponding piping. The steam generator and RCP in each loop may be isolated from the reactor vessel by closing the isolation valves.

7. Safety and Relief Valves (Section 5.4.13)

The pressurizer safety valves are of the totally enclosed pop-type. The valves are spring-loaded, self-actuated with back-pressure compensation. The power operated relief valves are solenoid operated valves, which are operated automatically or by remote manual control. Remotely operated valves are provided to isolate the inlet to the power operated relief valves if excessive leakage occurs.

Position indicating lights for these valves are provided in the control room.

8. Reactor Head Vent Piping (Section 5.4.15) ctor Coolant System Performance Characteristics ulations of important design and performance characteristics of the RCS are provided in le 5.1-1.

1. Reactor Coolant Flow The reactor coolant flow, a major parameter in the design of the system and its components, is established with a detailed design procedure supported by operating plant performance data, by pump model tests and analysis, and by pressure drop tests and analyses of the reactor vessel and fuel assemblies. Data from all operating plants have indicated that the actual flow has been well above the flow specified for the thermal design of the plant. By applying the design procedure described below, it is possible to specify the expected operating flow with reasonable accuracy.

Three reactor coolant flow rates are identified for the various plant design considerations. The definitions of these flows are presented in the following paragraphs.

2. Best Estimate Flow The best estimate flow is considered to be the most likely value for the actual plant operating condition. This flow is based on the best estimate of the reactor vessel,

system flow resistance or the pump head. System pressure drops, based on best estimate flow, are presented in Table 5.1-1. Although the best estimate flow is the most likely value to be expected in operation, more conservative flow rates are applied in the thermal and mechanical designs.

3. Thermal Design Flow Thermal design flow is the basis for the reactor core thermal performance, the steam generator thermal performance, and the nominal plant parameters used throughout the design. To provide the required margin, the thermal design flow accounts for the uncertainties in reactor vessel, steam generator and piping flow resistances, reactor coolant pump head, and the methods used to measure flow rate.

The thermal design flow is approximately 6.7 percent less than the best estimate flow and includes10 percent equivalent steam generator tube plugging. The thermal design flow is confirmed when the plant is placed in operation.

Tabulations of important design and performance characteristics of the RCS, based on thermal design flow, are provided in Table 5.1-1.

4. Mechanical Design Flow Mechanical design flow assumes 0 percent equivalent steam generator tube plugging, and is the conservatively high flow used in the mechanical design of the reactor vessel internals and fuel assemblies. To assure that a conservatively high flow is specified, the mechanical design flow is based on a reduced system resistance and on increased pump head capability. The mechanical design flow is approximately 3.9 percent greater than the best estimate flow.

Pump overspeed, due to a turbine generator overspeed of 20 percent, results in a peak reactor coolant flow of 120 percent of the normal operating flow. The overspeed condition is applicable only to operating conditions when the reactor and turbine generator are at power.

rrelated Performance and Safety Functions interrelated performance and safety functions of the RCS and its major components are listed w:

1. The RCS provides sufficient heat transfer capability to transfer the heat produced during power operation and when the reactor is subcritical, including the initial phase of plant cooldown, to the steam and power conversion system.

2. The system provides sufficient heat transfer capability to transfer the heat produced during the subsequent phase of plant cooldown and cold shutdown to the residual heat removal system.

fuel damage within the operating bounds permitted by the reactor control and protection systems.

4. The RCS provides the water used as the core neutron moderator and reflector and as a solvent for chemical shim control.

5. The system maintains the homogeneity of soluble neutron poison concentration and rate of change of coolant temperature such that uncontrolled reactivity changes do not occur. Interlocks are provided on the loop stop isolation valves to prevent the addition of cold or diluted water at excessive rates.

6. The reactor vessel is an integral part of the RCS pressure boundary and is capable of accommodating the temperatures and pressures associated with the operational transients. The reactor vessel functions to support the reactor-core and control rod drive mechanisms.

7. The pressurizer maintains the system pressure during operation and limits pressure transients. During reduction or increase of plant load, reactor coolant volume changes are accommodated in the pressurizer via the surge line.

8. The reactor pumps supply the coolant flow necessary to remove heat from the reactor core and transfer it to the steam generators.

9. The steam generator tube and tubesheet boundary are designed to prevent or control to acceptable levels the transfer of activity generated within the core to the secondary system.

10. The RCS piping serves as a boundary for containing the coolant under operating temperature and pressure conditions and for limiting leakage (and activity release) to the containment atmosphere. The RCS piping contains demineralized borated water which is circulated at the flow rate and temperature consistent with achieving the reactor core thermal and hydraulic performance.

11. The components of the RCS are surrounded by concrete structures which provide support, radiation shielding and missile protection. RCS shielding permits limited access to the containment during power operation. The reactor vessel is installed in a thick concrete cavity formed by the primary shield. The entire RCS is enclosed by the secondary shield.

12. Portions of the RCS are relied upon to function in conjunction with other systems of the cold shutdown design during a safety grade cold shutdown (Section 5.4.7).

It is expected that the systems normally used for cold shutdown would be available anytime the operator chooses to perform a reactor cooldown. Should only safety grade equipment be available, the RCS provides safety grade letdown capability

pressurizer power-operated relief valves. Refer to Section 5.4.7.2.3.5 for a detailed description of safety grade cold shutdown.

reactor vessel head letdown line and associated piping and valves also provide the capability itigate a possible condition of inadequate core cooling or inadequate natural circulation.

1 SCHEMATIC FLOW DIAGRAM RCS, shown schematically on Figure 5.1-2, includes typical values for principal parameters he system under normal steady state full power operating conditions. These values are based he best estimate flow. RCS volume under these conditions is presented in Table 5.1-1.

2 PIPING AND INSTRUMENTATION DIAGRAM iping and instrumentation diagram of the RCS (Figure 5.1-1) shows the extent of the systems ted within the containment, and the points of separation between the RCS and the secondary t utilization) system.

3 ELEVATION DRAWING ctor coolant system components are shown on Figures 3.8-59 and 3.8-60. These figures detail component relationships with the surrounding concrete structures.

concrete structures provide support, radiation shielding, and missile protection for the reactor lant system components. The concrete shielding permits limited access to the containment ng power operation.

mary shielding for the reactor vessel is provided by the neutron shield tank and a thick concrete l which surrounds the vessel. All reactor coolant system components are enclosed by the crane l, which serves as a secondary shield within the containment structure.

TABLE 5.1-1 SYSTEM DESIGN AND OPERATING PARAMETERS nt Design Life (years) 60 minal Operating Pressure (psig) 2,235 al System Volume Including ssurizer and Surge Line (ft3) 11,750 ssurizer Spray Rate (maximum gpm) 1,800 Note: Total Heater Capacity may be due to heater unavailability) ssurizer Relief Tank Volume (ft3) 1,800 4 Pumps Running System Thermal and Hydraulic Data (a) (b) sign NSSS Power (MWt)(e) 3739 3739 actor Power including measurement uncertainty (MWt)(e) 3723 3723 ermal Design Flows (gpm)

Active Loop (c) 90,800 90,800 Reactor 363,200 363,200 tal Reactor Flow (106 lb/hr) 135.5 137.1 mperatures (F)

Reactor Vessel Outlet 623.2 615.7 Reactor Vessel Inlet 555.8 547.3 Steam Generator Outlet 555.4 546.9 Steam Generator Steam 536.4 530.2 Feedwater 447.9 447.9 eam Pressure (psia) 934 886 tal Steam Flow (106 lb/hr) 16.66 16.63 st Estimate Flows (gpm)

Active Loop 97,300 99,700

System Thermal and Hydraulic Data (a) (b)

Reactor 389,200 398,800 stem Pressure Drops (d):

Reactor Vessel P (psi) 44.4 45.9 Steam Generator P (psi) 44.0 39.1 Hot Leg Piping P (psi) 2.1 2.2 Pump Suction Piping P (psi) 3.0 3.2 Cold Leg Piping P (psi) 4.0 4.3 Pump Head (ft) 303 291 Parameter based on full power operation with 10% equivalent steam generator tube plugging and reactor vessel average temperature of 589.5F.

Parameters based on full power operation with 0% equivalent steam generator tube plugging and reactor vessel average temperature of 581.5F.

The 4% reduction in thermal design flow was addressed by a 10 CFR 50.59 safety evaluation in 1993.

System pressure drops are based on a best estimate flow at full power.

The thermal and hydraulic data shown in the tables was conservatively established at 3723 MWt and 3739 MWt. The 3723 MWt is the bounding reactor thermal power used in the safety analysis, which includes the measurement uncertainty. NSSS Power of 3739 MWt is the sum of 3723 MWt and the net heat input of 16 MWt. The actual rated thermal power and NSSS power are 3709 MWt and 3725 MWt respectively at MUR power uprate conditions.

FIGURE 5.1-1 (SHEETS 1-6) P&IDS REACTOR COOLANT SYSTEM figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.

Mode A Steady State Full Power Operation Flow(1) ation Fluid Pressure psig Temperature °F GPM(2) lb/hr(3) Volume 1 R.C. 2246.7 617.2 111,211 37.1052 -

2 R.C. 2244.1 617.2 111,211 37.1052 -

3 R.C. 2206.0 556.8 99,692 37.1052 -

4 R.C. 2202.8 556.8 99,692 37.1052 -

5 R.C. 2297.0 557.0 99,600 37.1052 -

6 R.C. 2294.6 557.0 99,599 37.1048 -

-18 R.C. See Loop No. 1 Specifications

-27 R.C. See Loop No. 1 Specifications

-36 R.C. See Loop No. 1 Specifications 37 R.C. 2297.0 556.8 1.0 0.0004 -

38 R.C. 2297.0 556.8 1.0 0.0004 -

39 R.C. 2235.3 652.7 2.0 0.0008 -

40 Steam 2235.3 652.7 - - 720 41 R.C. 2244.0 652.7 - - 1080 42 R.C. 2244.0 652.7 2.5 0.0008 -

43 R.C. 2246.2 617.2 2.5 0.0008 -

44 Steam 2235.3 652.7 0 0 -

45 R.C. 2235.3 < 652.7 0 0 Minimize 46 N2 3.0 120.0 0 0 47 R.C. 2235.3 < 652.7 0 0 Minimize 48 N2 3.0 120.0 0 0 49 N2 3.0 120.0 0 0 50 N2 3.0 120.0 - -

51 PRT Water 3.0 120.0 - - 1350 Flows measured at 130°F and 2300 psia.

At the conditions specified x 106

Regulatory Guide 1.70, Revision 3, this section discusses the measures employed to provide maintain the integrity of the reactor coolant pressure boundary (RCPB) for the plant design ime. The RCPB, as defined in 10 CFR 50.2, extends to the outermost containment isolation e in system piping which penetrates the containment and is connected to the reactor coolant em (RCS) (Section 5.1). Since other sections of this FSAR already describe the components hese auxiliary fluid systems in detail, the discussions in this section are limited to the ponents of the RCS as defined in Section 5.1, unless otherwise noted.

itional information on the RCS and the components which are part of the RCPB (as defined in CFR 50) is given in the following sections:

Section 6.3 - The RCPB components which are part of emergency core cooling system Section 9.3.4 - The RCPB components which are part of the chemical and volume control system Section 3.9N.1 - The design loadings, stress limits, and analyses applied to the RCS and American Society of Mechanical Engineers (ASME) Code Class 1 components Section 3.9N.3 - The design loadings, stress limits, and analyses applied to ASME Code Class 2 and 3 components phrase, RCS, as used in this section is as defined in Section 5.1. When the term RCPB is used his section, its definition is that of Section 50.2 of 10 CFR 50.

1 COMPLIANCE WITH CODES AND CODE CASES 1.1 Compliance with 10 CFR 50.55a S components are designed and fabricated in accordance with 10 CFR 50.55a. The actual enda of the ASME Code applied in the original design of each component are listed in le 5.2-1.

1.2 Applicable Code Cases ulatory Guides 1.84 and 1.85 are discussed in Section 1.8. The following discussion addresses y unapproved or conditionally approved code cases (per Regulatory Guides 1.84 and 1.85) d on Class 1 primary components and component supports.

e Case 1528 (SA 508 Class 2a) material was used in the manufacture of the Millstone 3 steam erators and pressurizers.

chase orders for this equipment were placed prior to the original issue of Regulatory Guide (June 1974). Regulatory Guide 1.85 Revision 6 (May 1976) reflected conditional NRC roval of Code Case 1528. The Westinghouse test program demonstrates the adequacy of Code

C Eicheldinger's letter (3/17/78).

e Cases N-242 (Paragraphs 5.4, 5.5 and 5.6) and N-242-1 (Paragraphs 5.3, 5.4, 5.5 and 5.6) erial was used in the manufacture of the Millstone 3 mechanical shock arrestors. Code Case 42-1 (Paragraphs 1.0 through 4.0) material was used in welding operations on Millstone 3 tor plant component cooling check valve 3CCP*V3, S/N C61870. Code Case N-242 was also d on J. E. Lonergan Relief Valves which are listed in Table 5.2-6. Regulatory Guide 1.85,

. 18, allows the use of these code cases.

e Case N-71 (1644-6) material, A-500-74a Grade B, was used in the fabrication of cable tray ports attached to the CRDM Seismic Support Platform. Regulatory Guide 1.85, Rev. 20, ws the use of the code case.

e Case N-275, Repair of Welds, was used to waive LP examination requirements in the repair elds where the back side of the weld joint assembly is not accessible for removal of the mination material.

e Case N-407 was invoked for limited repair welds of A-487 Class 10Q steel castings without t weld heat treatment. The castings are for parts of the steam generator and reactor coolant p supports (FSAR Section 5.4.14). Material listed in Code Case N- 249-4, specifically A-668 ss M, was used for pins in the steam generator and reactor coolant pump pressurizer supports.

se Code Cases have not been endorsed by the NRC in Regulatory Guides 1.84 or 1.85. A uest for approval of Code Cases N-407 and N-249-4 was submitted to the NRC in Counsils r (6/8/84) with an attached report, 12179-J(B)-131. Code Case N-407 was approved by the C in Youngbloods letter (2/12/85) based on the test program results attached in Counsils r (6/8/84). Code Case N-249-4 was approved by the NRC in Youngbloods letter (9/24/85).

ME Code Case N-640 in conjunction with ASME Code Section XI, Appendix G has been used evelop the reactor vessel beltline P/T limits. This Code Case permits the use of an alternate ture toughness curve (KIc) in lieu of the lower bound KIa curve. Use of this Code Case was vided by the NRC as documented in letter dated January 9, 2002.

2 OVERPRESSURE PROTECTION S overpressure protection is provided by the pressurizer and steam generator safety valves g with the reactor protection system and associated equipment. Combinations of these ems assure compliance with the overpressure requirements of the ASME Code,Section III, graphs NB-7300 and NC-7300, for pressurized water reactor systems.

only portion of an auxiliary system used for overpressure protection of the RCS is the liquid ef valves of the heat removal (RHR) system. These valves protect the RCS at low temperatures n the RHR system is on operation. They are located inside containment and discharge to the surizer relief tank.

rpressure protection is provided for the RCS by the pressurizer safety valves. This protection fforded for the following events which envelop those credible events which could lead to rpressure of the RCS if adequate overpressure protection were not provided:

1. Loss of electrical load and/or turbine trip

2. Uncontrolled rod withdrawal at power

3. Loss of reactor coolant flow

4. Loss of normal feedwater

5. Loss of offsite power to the station auxiliaries sizing of the pressurizer safety valves is based on analysis of a complete loss of steam flow to turbine with the reactor operating at 100.4 percent of engineered safeguards design power. In analysis, feedwater flow is also assumed to be lost, and no credit is taken for operation of surizer power operated relief valves, pressurizer level control system, pressurizer spray em, rod control system, steam dump system, or steam line power operated relief valves. The tor is maintained at full power (no credit for direct reactor trip on turbine trip), and steam ef through the steam generator safety valves is considered. The total pressurizer safety valve acity is required to be at least as large as the maximum surge rate into the pressurizer during transient.

s sizing procedure results in a safety valve capacity well in excess of the capacity required to vent exceeding 110 percent of system design pressure for the events listed in this section.

rpressure protection for the steam system is provided by steam generator safety valves. The m system safety valve capacity is based on providing enough relief capacity to remove the ineered safeguards design steam flow. This must be done while limiting the maximum steam em pressure to less than 110 percent of the steam generator shell side design pressure.

wdown and heat dissipation systems of the nuclear steam supply system (NSSS) connected to discharge of these pressure relieving devices are discussed in Section 5.4.11.

m generator blowdown systems for the balance of plant are discussed in Section 10.4.8.

2.2 Design Evaluation escription of the pressurizer safety valves performance characteristics along with the design cription of the incidents, assumptions made, method of analysis, and conclusions are discussed hapter 15.

ection system. WCAP-7769 (Cooper et al., 1972), and Eicheldingers letter (1975) evaluate functional design of the overpressure protection system and analyze the capability of the em to perform its function for a typical plant. WCAP-7769 describes in detail the types and ber of pressure relief devices employed, relief device description, locations in the systems, ability history, and the details of the methods used for relief device sizing based on typical st condition. An overpressure protection report specifically for Millstone 3 is prepared in ordance with Article NB-7300 of Section III of the ASME Code. WCAP-7907 (Burnett, et al.,

2) describes the analytical model used in the analysis of the overpressure protection system the basis for its validity.

2.3 Piping and Instrumentation Diagrams rpressure protection for the RCS is provided by the pressurizer safety valves shown on ure 5.1-1. These valves discharge to the pressurizer relief tank through a common header.

steam generator safety valves are discussed in Section 10.3 and are shown on Figure 10.3-1.

2.4 Equipment and Component Description operation, significant design parameters, number and types of operating cycles, and ironmental conditions of the pressurizer safety valves are discussed in Sections 5.4.13, 3.9N.1, 3.11N.

iscussion of the equipment and components of the steam system overpressure protection ures is included in Section 10.3.

2.5 Mounting of Pressure-Relief Devices pressurizer safety valve support is designed to withstand seismic, thermal, pipe rupture, and dweight forces in addition to the valve discharge reactions. The supports consist of:

1. A circumferential box girder supported off four vertical columns

2. Radial support arms from each valve to the box girder

3. Pinned column connections at the pressurizer safety valve support brackets supports are welded in place.

ee safety valves are supported. The three valves are assumed operating simultaneously. The harge load from each valve, in combination with the seismic, thermal, pipe rupture, piping, deadweight load, is applied to the valve supports at the valve inlet flange. These loads are n by the radial support arms which then transmit thrust, bending, and torsional loads into the girder ring. These are distributed to each of the four columns and down to pin connections at

tion 3.9B.3.3 gives the particular loading combinations analyzed:

1. The normal condition includes: deadweight + 1/2 SSE + occasional (valve operation) loads

2. The upset condition includes: deadweight + 1/2 SSE + thermal + occasional (valve operation) loads

3. The faulted condition includes: deadweight + SSE + pipe rupture + occasional (valve operation) loads le 5.2-5 lists the loads at the pressurizer safety valve support brackets for each combination of gn loads. Included within the parentheses are Westinghouse allowable loads for the same gn load combinations.

iew of this table shows that faulted loads exceed other load conditions by a factor greater than cept for those loads that have insignificant effect on stresses such as Fx and My. The ratio of wable faulted stress to the allowable for normal, upset, or emergency is less than 2. Therefore, faulted load condition is the limiting condition.

2.6 Applicable Codes and Classification requirements of the ASME Boiler and Pressure Vessel Code,Section III, NB-7300 erpressure Protection Report) and NC-7300 (Overpressure Protection Analysis), are met.

ng, valves, and associated equipment used for overpressure protection are classified in ordance with ANSI-N18.2, Nuclear Safety Criteria for the Design of Stationary Pressurized er Reactor Plants. These safety class designations are delineated in Table 3.2-2 and shown Figure 5.1-1.

2.7 Material Specifications tion 5.2.3 describes material specifications.

2.8 Process Instrumentation h pressurizer safety valve discharge line incorporates a control board mounted temperature cator and an alarm to notify the operator of steam discharge due to either leakage or actual e operation. Chapter 7 discusses process instrumentation associated with the system.

reliability of the pressure relieving devices is discussed in Section 4 of WCAP-7769 (Cooper l., 1972) and Eicheldingers letter (1975).

2.10 Testing and Inspection ting and inspection of the overpressure protection components are discussed in tion 5.4.13.4 and Chapter 14.

2.11 RCS Pressure Control during Low Temperature Operation ministrative procedures are available to aid the operator in controlling RCS pressure during temperature operation. However, to provide a backup to the operator and to minimize the uency of RCS overpressurization, an automatic system is provided to mitigate any inadvertent ursion.

tection against an overpressurization event is provided through the use of two PORVs, two R suction relief valves, or one PORV and one RHR suction relief valve to mitigate any ntial pressure transients. Analyses have shown that one relief valve is sufficient to prevent ation of these limits due to anticipated mass and heat input transients. The mitigation system quired only during low temperature operation; it is manually placed in service and matically actuated.

2.11.1 System Operation o pressurizer power-operated relief valves are each supplied with actuation logic to ensure that utomatic and independent RCS pressure control backup feature is available for the operator ng low temperature operations. This system has the capability for RCS inventory letdown, eby maintaining RCS pressure within allowable limits. Sections 5.4.7, 5.4.10, 5.4.13, 7.7 and 4 give additional information on RCS pressure and inventory control during other modes of ration.

basic function of the system logic is to continuously monitor RCS temperature and pressure ditions whenever plant operation is at low temperatures. An auctioneered system temperature ontinuously converted to an allowable pressure and then compared to the actual RCS pressure.

system logic first annunciates a main control board alarm whenever the measured pressure roaches within a predetermined amount of the allowable pressure, thereby indicating that a sure transient is occurring and on a further increase in measured pressure, an actuation signal ansmitted to the PORVs when required to mitigate the pressure transient.

isolation valves between the RCS and the RHR suction relief valves must be open to make RHR suction relief valves operable for RCS overpressure mitigation. When the RHR system perated for decay heat removal or low pressure letdown control, the isolation valves between RCS and the RHR suction relief valves are open, and the RHR suction relief valves are osed to the RCS and are able to relieve pressure transients in the RCS.

ssure Transient Analyses ME Section III, Appendix G, establishes guidelines and upper limits for RCS pressure arily for low temperature conditions ( 350F). The mitigation system (Section 5.2.2.11) sfies these conditions at temperatures 226F, which is the enabling temperature required to ect the RCS against non-ductile failure.

nsient analyses determined the maximum pressure for the postulated mass input and heat input nts.

limiting mass input transient which would occur during RCS low temperature operation is the ction of a charging pump at a run-out flow of 570 gpm with letdown isolated.

heat input transient analysis is performed over the entire RCS shutdown temperature range.

s analysis assumes a reactor coolant pump startup with a 50F mismatch between the RCS and temperature of the hotter secondary side of the steam generators. Inadvertent RCP starts are considered credible during low temperature operation since two separate operator actions are uired to start an RCP. In addition, restrictions on the allowable mismatch are required to limit ef flow to values within the capacity of the RHR relief valves.

h heat input and mass input analyses take into account the single failure criteria and, therefore, y one relief valve is assumed to be available for pressure relief. These events have been luated considering the allowable isothermal beltline pressure/temperature limits. The luation of the transient results concludes that the vessel integrity and plant safety will not be aired.

2.11.3 Operating Basis Earthquake Evaluation uid systems evaluation has been performed considering the potential for overpressure sients following an operating basis earthquake (OBE).

Millstone 3 power-operated relief valves have been designed in accordance with the ASME e to provide the integrity required for the reactor coolant pressure boundary and qualified in ordance with the valve operability program which is described in detail in Section 3.9N.3.2.2.

ed on this evaluation, hypothesized overpressure transients following an OBE are not a cern.

2.11.4 Administrative Procedures hough the system described in Section 5.2.2.11.1 is designed to maintain RCS pressure within allowable pressure limits, administrative procedures have been provided for minimizing the ntial for any transient that could actuate the overpressure relief system. The following

primary importance is the basic method of operation of the plant. Normal plant operating cedures maximizes the use of a pressurizer cushion (steam bubble) during periods of low sure, low temperature operation. This cushion dampens the plants response to potential sient generating inputs, providing easier pressure control with the slower response rates.

adequate cushion substantially reduces the severity of some potential pressure transients such eactor coolant pump induced heat input and slows the rate of pressure rise for others. In junction with the previously discussed alarms, this provides reasonable assurance that most ntial transients can be terminated by operator action before the overpressure relief system ates.

wever, for those modes of operation when water solid operation may still be possible, the owing procedures further highlight precautions that minimize the potential for developing an rpressurization transient. The following specific recommendations are made:

1. Prior to removing the RHR letdown from service, alternate provisions for maintaining an RCS mass inventory balance shall be established to ensure that the cold overpressure protection system (COPPS) is not challenged.

2. Whenever the plant is water solid and the reactor coolant pressure is being maintained by the low pressure letdown control valve, letdown flow must bypass the normal letdown orifices, and the valve in the bypass line must be in the full open position. During this mode of operation, all three letdown orifices must also remain open.

3. If all reactor coolant pumps have been stopped for more than 5 minutes, and the reactor coolant temperature is greater than the charging and seal injection water temperature, no attempt shall be made to start the first reactor coolant pump when the RCS is water-solid until administrative, procedural guidelines which limit the temperature difference between the RCS and the charging and seal injection water are met. This will minimize the pressure transient when the pump is started and the cold water previously injected by the charging pumps is circulated through the warmer reactor coolant components.

4. If all reactor coolant pumps are stopped and the RCS is further cooled down by the residual heat exchangers, a nonuniform temperature distribution may occur in the reactor coolant loops. For this case, the Technical Specifications provide restrictions for starting the first reactor coolant pump that bound the most limiting heat injection transients, thereby ensuring that the RCS pressure is maintained within the allowable pressure limits. No attempt shall be made to start the first reactor coolant pump when the RCS is water-solid until administrative, procedural guidelines which limit the temperature difference between the RCS and the steam generator secondary side fluid are satisfied. These administrative limits provide

5. During plant cooldown using the main condenser, all steam generators shall be connected to the steam header to assure a uniform cooldown of the reactor coolant loops.

6. During normal cooldown, at least one reactor coolant pump shall be maintained in service until the reactor coolant temperature is reduced to 160F.

se special precautions back up the normal operational mode of maximizing periods of steam ble operation so that cold overpressure transient prevention is continued during periods of sitional operations.

specific plant configurations of ECCS testing and alignment also highlight procedures uired to prevent developing cold overpressurization transients. During these limited periods of t operation, the following actions minimize the probability of system overpressurization:

1. To preclude inadvertent ECCS actuation during cooldown, blocking of the low pressurizer pressure and low steam line pressure safety injection signal actuation logic occurs between the P-11 setpoint pressure of 1985 psig and the SI signal actuation pressure of 1877.3 psig. During heatup, the low pressurizer pressure and low steam line pressure safety injection signal actuation logic remains blocked until the pressure exceeds the P-11 setpoint.

2. During further cooldown, closure and power lockout of the accumulator isolation valves is required at a pressure of less than or equal to 1,000 psig and no sooner than two and one-half hours following reactor shutdown, but before the RCS pressure reaches the accumulator pressure, providing additional backup to item 1.

above. Prior to placing the cold overpressurization protection system in service, all but one charging pump and all SI pumps are rendered incapable of injecting into the RCS.

3. Periodic ECCS pump performance testing requires the testing of the pumps during normal power operation or at hot shutdown conditions. This precludes any potential for developing a cold overpressurization transient.

If cold shutdown testing with the vessel closed is necessary, the procedures require ECCS valve closure and RHS alignment to both isolate potential ECCS pump input and to provide backup benefit of the RHS relief valves.

The safety injection pump can be run to fill the accumulators or for testing during cold shutdown with the vessel closed provided the safety injection pump is rendered incapable of injecting into the RCS by at least two independent means.

The following are examples of acceptable actions which meet this requirement: 1) closing the pump discharge valve(s) to the injection line and either removing the

valve operator(s) or locking manual valve(s) closed.

4. Safety Injection signal circuitry testing, if done during cold shutdown, also requires RHS plus SI pump alignments and non operating charging pump power lockout to preclude inadvertent SI discharge to the RCS.

se procedural recommendations covering normal operations with a steam bubble, and sitional operations where potentially water solid, when followed by specific testing rations, provide in-depth cold overpressure preventions or reductions, augmenting the alled overpressure relief system.

3 MATERIALS SELECTION, FABRICATION, AND PROCESSING 3.1 Material Specifications ical material specifications used for the principal pressure retaining applications in Class 1 ary components and for Class 1 and 2 auxiliary components in systems required for reactor tdown and for emergency core cooling are listed in Table 5.2-2. Typical material cifications used for the reactor internals required for emergency core cooling, for any mode of mal operation or under postulated accident conditions, and for core structural load bearing mbers are listed in Table 5.2-3.

ome cases, Tables 5.2-2 and 5.2-3 may not be totally inclusive of the material specifications d in the listed applications. However, the listed specifications are representative of those erials used. All of the materials used were procured in accordance with ASME Code uirements.

welding materials used for joining the ferritic base materials of the RCPB conform to or are ivalent to ASME Material Specifications SFA 5.1, 5.2, 5.5, 5.17, 5.18, and 5.20. They are ed and qualified to the requirements of ASME Code,Section III.

welding materials used for joining the austenitic stainless steel base materials of the RCPB form to ASME Material Specifications SFA 5.4 and 5.9. They are tested and qualified ording to the requirements of ASME Code,Section III.

welding materials used for joining nickel-chromium-iron alloy in similar base material bination and in dissimilar ferritic or austenitic base material combination conform to ASME erial specifications SFA 5.11 and 5.14. They are tested and qualified to the requirements of ME Code,Section III.

3.2.1 Chemistry of Reactor Coolant RCS chemistry specifications are given in Table 5.2-4.

RCS water chemistry was selected to minimize corrosion. A periodic analysis of the coolant mical composition is performed to verify that the reactor coolant quality meets the cifications.

e chemical and volume control system provides a means for adding chemicals to the RCS ng all power operations subsequent to startup. Table 5.2-4 gives the oxygen content and pH ts for power operations.

pH control chemical employed is lithium-7 hydroxide. This chemical was chosen for its patibility with the materials and water chemistry of borated water/stainless steel/zirconium/

onel systems. In addition, lithium is produced in solution from the neutron irradiation of the olved boron in the coolant.

ing reactor startup from the cold condition, hydrazine is employed as an oxygen scavenging nt. The hydrazine solution is introduced into the RCS from the chemical and volume control em.

solved hydrogen controls and scavenges oxygen produced due to radiolysis of water in the region. Sufficient partial pressure of hydrogen is maintained in the volume control tank such the specified equilibrium concentration of hydrogen is maintained in the reactor coolant.

3.2.2 Compatibility of Construction Materials with Reactor Coolant of the ferritic low alloy and carbon steels used in principal pressure retaining applications e corrosion resistance cladding on all surfaces that are exposed to the reactor coolant. This ding material has a chemical analysis which is at least equivalent to the corrosion resistance ypes 304 and 316 austenitic stainless steel alloys or nickel-chromium-iron alloy, martensitic nless steel, and precipitation hardened stainless steel. The cladding on ferritic type base erials receives a post weld heat treatment, as required by the ASME Code.

itic low alloy and carbon steel nozzles are safe ended with either stainless steel wrought erials, stainless steel weld metal analysis A-7 (designated A-8 in the 1974 Edition of the ME Code), or nickel-chromium-iron alloy weld metal F-Number 43. The latter buttering erial requires further safe ending with austenitic stainless steel base material or stainless steel d metal analysis A-8 after completion of the post weld heat treatment when the nozzle is larger a 4 inch nominal inside diameter and/or the wall thickness is greater than 0.531 inches.

of the austenitic stainless steel and nickel-chromium-iron alloy base materials with primary sure retaining applications are used in the solution anneal heat treat condition. These heat tments are as required by the material specifications.

ding followed by a resolution annealing heat treatment.

mponents with stainless steel sensitized in the manner expected during component fabrication installation operate satisfactorily under normal plant chemistry conditions in pressurized er reactor systems because chlorides, fluorides, and oxygen are controlled to very low levels.

3.2.3 Compatibility with External Insulation and Environmental Atmosphere eneral, all of the materials listed in Table 5.2-2 which are used in principal pressure retaining lications and which are subject to elevated temperature during system operation are in contact h thermal insulation that covers their outer surfaces.

thermal insulation used on the RCPB is either reflective stainless steel type or made of pounded materials which yield low leachable chloride and/or fluoride concentrations. The pounded materials in the form of blocks, boards, cloths, tapes, adhesives, cements, etc, are ated to provide protection of austenitic stainless steels against stress corrosion which may lt from accidental wetting of the insulation by spillage, minor leakage, or other contamination m the environmental atmosphere. Section 1.8 includes a discussion which indicates the degree onformance with Regulatory Guide 1.36, Nonmetallic Thermal Insulation for Austenitic nless Steel.

he event of coolant leakage, the ferritic materials will show increased general corrosion rates.

ere minor leakage is anticipated from service experience, such as valve packing, pump seals,

, only materials which are compatible with the coolant (Table 5.2-2) are used. Ferritic erials exposed to coolant leakage can be readily observed as part of the inservice visual and/or destructive inspection program to assure the integrity of the component for subsequent ice.

3.3 Fabrication and Processing of Ferritic Materials 3.3.1 Fracture Toughness fracture toughness properties of the RCPB components meet the requirements of ASME tion III, Paragraphs NB-2300, NC-2300, and ND-2300 as appropriate.

iting steam generator and pressurizer RT temperatures are guaranteed at 60F for the base erials and the weldments. These materials meet the 50 ft-lb absorbed energy and 35 mils ral expansion requirements of the ASME Code,Section III at 120F. The actual results of e tests are provided in the ASME material data reports which are supplied for each component are submitted to the licensee at the time of shipment of the component.

ibration of temperature instruments and of Charpy impact test machines is performed to meet requirements of the ASME Code,Section III, Paragraph NB-2360.

pliance with Appendix G of the ASME Code,Section III. In this program, fracture toughness perties were determined and shown to be adequate for base metal plates and forgings, weld al, and heat affected zone metal for higher strength ferritic materials used for components of reactor coolant pressure boundary. The results of the program are documented in WCAP-9292 78), which has been submitted to the NRC for review via Eicheldingers letter (1978).

3.3.2 Control of Welding welding is conducted using procedures qualified according to the rules of Sections III and IX he ASME Code. Control of welding variables, as well as examination and testing, during cedure qualification and production welding is performed in accordance with ASME Code uirements.

tion 1.8 includes discussions which indicate the degree of conformance of the ferritic erials components of the RCPB with Regulatory Guides 1.34, Control of Electroslag perties, 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components,

, Control of Preheat Temperature for Welding of Low-Alloy Steel, 1.66, Nondestructive mination of Tubular Products, and 1.71, Welder Qualification for Areas of Limited essibility.

tinghouse practices for storage and handling of welding electrodes and fluxes comply with ME Code,Section III, Paragraph NB-2400.

3.3.3 Pressurized Thermal Shock ccordance with 10 CFR 50.61, reactor pressure vessel materials have been reviewed to blish a reference temperature for pressurized thermal shock (RTPTS). This review evaluated loading patterns and the actual amount of copper and nickel in the vessel materials. It also pared the vessel material composition and properties to surveillance capsule materials from ch tests and measurements were taken. A summary of this review is as follows:

1. Copper/Nickel Content:

• Plates - full chemistry results available.

• Welds - full chemistry results available.

2. Core Configuration:

The maximum fluence level of 2.70 x 1019 n/cm2, as determined by Westinghouse, was conservatively applied to all vessel locations to determine the end-of-life RTPTS. This value is based on the results of the updated neutron fluence analysis for 54 EFPY considering 3,650 MWt rated thermal power conditions. The third

Reactor Vessel Radiation Surveillance Program, September 2006. This represents the most current information regarding neutron flux and associated material degradation. This analysis considered core loading patterns and past power levels to predict the peak surface fluence. WCAP-11878, Analysis of Capsule U from the Northeast Utilities Service Company Millstone 3 Reactor Vessel Radiation Surveillance Program, June 1988 provides the evaluation of the first surveillance capsule removed. WCAP-15405, Revision 0, Analysis of Capsule X from the Northeast Nuclear Energy Company Millstone Unit 3 Reactor Vessel Radiation Surveillance Program, May 2000 provides the evaluation of the second surveillance capsule removed.

culated RTPTS values have been obtained using the above assumptions. Table 5.2-7 provides results of the calculations. This table will be updated whenever changes in core loadings, eillance measurements, or other information indicate a significant change in the RTPTS ected values, as required by 10 CFR 50.61(b)(1). The values that were calculated do not eed the RTPTS screening criteria of 270F for plates, forgings, and axial weld materials, and F for circumferential weld materials.

3.4 Fabrication and Processing of Austenitic Stainless Steel tions 5.2.3.4.1 through 5.2.3.4.5 address Regulatory Guide 1.44, Control of the Use of sitized Stainless Steel, and present the methods and controls used by Westinghouse to avoid sitization and prevent intergranular attack of austenitic stainless steel components. Also, tion 1.8 discusses conformance with Regulatory Guide 1.44.

3.4.1 Cleaning and Contamination Protection Procedures required that all austenitic stainless steel materials used in the fabrication, installation, and ing of nuclear steam supply components and systems are to be handled, protected, stored, and ned according to recognized and accepted methods which are designed to minimize tamination which could lead to stress corrosion cracking. The rules covering these controls are ulated in the Westinghouse Electric Corporation process specifications. These process cifications are also given to the A/E and to the owner of the plant for recommended use within r scope of supply.

3.4.2 Solution Heat Treatment Requirements austenitic stainless steels listed in Tables 5.2-2 and 5.2-3 are used in the final heat treated dition required by the respective ASME Code,Section II materials specification for the icular type or grade of alloy.

tinghouse practice is that austenitic stainless steel materials of product forms with simple pes need not be corrosion tested provided that the solution heat treatment is followed by water nching. Simple shapes are defined as all plates, sheets, bars, pipe and tubes, as well as ings, fittings, and other shaped products which do not have inaccessible cavities or chambers would preclude rapid cooling when water quenched. When testing is required, the tests are ormed in accordance with ASTM-A-262, Practices A or E, as amended by Westinghouse cess Specification 84201 MW.

3.4.4 Prevention of Intergranular Attack of Unstabilized Austenitic Stainless Steels tabilized austenitic stainless steels are subject to intergranular attack provided that three ditions are present simultaneously. These are:

1. An aggressive environment, e.g., an acidic aqueous medium containing chlorides or oxygen

2. A sensitized steel

3. A high temperature ny one of the three conditions described above is not present, intergranular attack will not ur. Since high temperatures cannot be avoided in all components in the NSSS, Westinghouse es on the elimination of conditions 1 and 2 to prevent intergranular attack on wrought stainless l components.

water chemistry in the RCS of a Westinghouse pressurized water reactor is rigorously trolled to prevent the intrusion of aggressive species. In particular, the maximum permissible gen and chloride concentrations are limited to those in Table 5.2-4. WCAP-7735 (Hazelton

1) describes the precautions taken to prevent the intrusion of chlorides into the system during ication, shipping, and storage. The use of hydrogen overpressure precludes the presence of gen during operation. The effectiveness of these controls has been demonstrated by both ratory tests and operating experience. The long time exposure of severely sensitized stainless arly plants to pressurized water reactor coolant environments has not resulted in any sign of rgranular attack. WCAP-7735 describes the laboratory experimental findings and the tinghouse operating experience. The additional years of operations since the issuing of AP-7735 have provided further confirmation of the earlier conclusions. Severely sensitized nless steels do not undergo any intergranular attack in Westinghouse pressurized water reactor lant environments.

hough there never has been any evidence that pressurized water reactor coolant water attacks sitized stainless steels, Westinghouse considers it good metallurgical practice to avoid the use ensitized stainless steels in the NSSS components. Accordingly, measures are taken to hibit the purchase of sensitized stainless steels and to prevent sensitization during component ication. Wrought austenitic stainless steel stock used for components that are part of: the

nder postulated accident conditions is used in one of the following conditions:

1. Solution annealed and water quenched

2. Solution annealed and cooled through the sensitization temperature range within less than approximately 5 minutes generally accepted that these practices prevent sensitization. Westinghouse has verified this erforming corrosion tests (ASTM-393) on as-received wrought material.

tinghouse recognizes that the heat affected zones of welded component must, of necessity, be ted into the sensitization temperature range, 800F to 1500F. However, severe sensitization, continuous grain boundary precipitates of chromium carbide, with adjacent chromium letion, can still be avoided by control of welding parameters and welding processes. The heat ut (Equation 5.2-1) and associated cooling rate through the carbide precipitation range are of ary importance. Westinghouse has demonstrated this by corrosion testing a number of dments.

t input based on expression given in Arc Welding Handbook is calculated as follows:

H = (E)(I)(60) S (5.2-1) re:

H = joules/inch E = volts I = amperes S = travel speed (inches/minute) 25 production and qualification weldments tested, representing all major welding processes, a variety of components, and incorporating base metal thicknesses from 0.10 to 4.0 inches, y portions of two were severely sensitized. Of these, one involved a heat input of 120,000 es and the other involved a heavy socket weld in relatively thin walled material. In both cases, sitization was caused primarily by high heat inputs relative to the section thickness. However, nly the socket weld did the sensitized condition exist at the surface, where the material is osed to the environment. The component has been redesigned and a material change has been e to eliminate this condition.

tinghouse controls the heat input in all austenitic pressure boundary weldments by:

1. Prohibiting the use of block welding

2. Limiting the maximum interpass temperature to 350F

ummarize, Westinghouse has a four point program designed to prevent intergranular attack of enitic stainless steel components:

1. Control of primary water chemistry to ensure a benign environment

2. Utilization of materials in the final heat treated condition and the prohibition of subsequent heat treatments in the 800F to 1,500F temperature range

3. Control of welding processes and procedures to avoid heat affected zone sensitization

4. Confirmation that the welding procedures used for the manufacture of components in the primary pressure boundary and of reactor internals do not result in the sensitization of heat affected zones h operating experience and laboratory experiments in primary water have conclusively onstrated that this program is 100 percent effective in preventing intergranular attack in tinghouse NSSSs using unstabilized austenitic stainless steel.

3.4.5 Retesting Unstabilized Austenitic Stainless Steel Exposed to Sensitization Temperatures not normal Westinghouse practice to expose unstabilized austenitic stainless steels to the sitization range of 800F to 1,500F during fabrication into components. If, during the course abrication, the steel is inadvertently exposed to the sensitization temperature range, 800F to 0F, the material may be tested in accordance with ASME-A-393 or A-262 as amended by tinghouse Process Specification 84201 MW to verify that it is not susceptible to intergranular ck, except that testing is not required for:

1. Cast metal or weld metal with a ferrite content of 5 percent or more

2. Material with a carbon content of 0.03 percent or less that is subjected to temperatures in the range of 800F to 1,500F for less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />

3. Material exposed to special processing provided the processing is properly controlled to develop a uniform product and provided that adequate documentation exists of service experience and/or test data to demonstrate that the processing will not result in increased susceptibility to intergranular stress corrosion is not verified that such material is not susceptible to intergranular attack, the material is olution annealed and water quenched or rejected.

following paragraphs address Regulatory Guide 1.31, Control of Stainless Steel Welding, present the methods used, and the verification of these methods, for austenitic stainless steel ding.

welding of austenitic stainless steel is controlled to mitigate the occurrence of microfissuring ot cracking in the weld. Although published data and experience have not confirmed that uring is detrimental to the quality of the weld, it is recognized that such fissuring is esirable in a general sense. Also, it has been well documented in the technical literature that presence of delta ferrite is one of the mechanisms for reducing the susceptibility of stainless l welds to hot cracking. However, there is insufficient data to specify a minimum delta ferrite l below which the material is prone to hot cracking. It is assumed that such a minimum lies ewhere between 0 and 3 percent delta ferrite.

scope of these controls discussed herein encompasses welding processes used to join nless steel parts in components designed, fabricated, or stamped in accordance with ASME e,Section III, Class 1 and 2, and core support components. Delta ferrite control is appropriate the above welding requirements except where no filler metal is used for other reasons such trol is not applicable. These exceptions include electron beam welding, autogenous gas lded tungsten arc welding, explosive welding, and welding using fully austenitic welding erials.

fabrication and installation specifications require welding procedure and welder qualification ccordance with the ASME Code,Section III, and include welding materials that are used for ding qualification testing and for production processing. Specifically, the starting welding erials are required to contain a minimum of 5 percent delta ferrite as determined by magnetic hods on an undiluted weld deposit. As an alternative, delta ferrite determination for sumable inserts, bare weld rods, and wire filler metal used with the gas tungsten arc welding cess can be predicted from their chemical composition using the appropriate weld metal stitution diagrams in the ASME Code,Section III. (The equivalent ferrite number may be stituted for percent delta ferrite.) When new welding procedure qualification tests are luated for these applications, including repair welding of raw materials, they are performed in ordance with the requirements of Section III and Section IX of the ASME Code.

starting welding materials used for fabrication and installation welds of austenitic stainless l materials and components meet the requirements of the ASME Code,Section III. The enitic stainless steel welding material conforms to ASME weld metal analysis A-7, ignated A-8 in the 1974 Edition of the ASME Code). Bare weld filler metal, including sumable inserts, used in inert gas welding processes conform to ASME SFA-5.9, and are cured to contain not less that 5 percent delta ferrite according to the ASME Code,Section III.

d filler materials used in flux shielded processes conform to ASME SFA-5.4 or SFA-5.9 and procured in a wire-flux combination to be capable of providing not less than 5 percent delta ite in the deposit according to the ASME Code,Section III. Welding materials are tested using welding energy inputs to be employed in production welding.

erial by lots and heats as appropriate. All of the weld processing is monitored according to roved inspection programs which include review of starting materials, qualification records, welding parameters. Welding systems are also subject to quality assurance audit including bration of gages and instruments: identification of starting and completed materials; welder procedure qualifications; availability and use of approved welding and heat treating cedures; and documentary evidence of compliance with materials; welding parameters and ection requirements. Fabrication and installation welds are inspected using nondestructive mination methods according to the ASME Code,Section III rules.

assure the reliability of these controls, Westinghouse has completed a delta ferrite verification gram, described in WCAP-8324-A (Enrietto 1975) which has been approved as a valid roach to verify the Westinghouse hypothesis and is considered an acceptable alternative for formance with the NRC Interim Position on Regulatory Guide 1.31. The NRC acceptance er and topical report evaluation were received on December 30, 1974. The program results, ch support the hypothesis presented in WCAP-8324-A, are summarized in WCAP-8693 rietto 1976).

tion 1.8 includes discussions which indicate the degree of conformance of the austenitic nless steel components of the RCPB with Regulatory Guides 1.34, Control of Electroslag perties, 1.66, Nondestructive Examination of Tubular Products, and 1.71, Welder lification for Areas of Limited Accessibility.

4 INSERVICE INSPECTION AND TESTING OF REACTOR COOLANT PRESSURE BOUNDARY inservice inspection program for Safety Class 1 (reactor coolant pressure boundary) ponents has been developed to ensure the structural integrity of all applicable vessels, piping, es, pumps, and appurtenances throughout the plant service lifetime. The program was eloped to meet the requirements of ASME Code,Section XI, 1983 Edition, Summer 1983 enda, Subsections IWA, IWB, and IWF. All of the detailed examinations listed in the Code e performed as a preservice examination prior to plant startup to demonstrate access, ection equipment and techniques, and to establish a baseline for inservice examinations.

sequent inservice inspections will be performed as specified in the edition of the ASME Code, tion XI, which is in effect for the inspection period in which the inspection is being performed.

exceptions to the ASME Code will be documented and approved in accordance with 10 CFR 552.

4.1 System Boundary Subject to Inspection ddition to the reactor pressure vessel (RPV), components and supports within the ASME e,Section III, Class 1 boundaries are subject to the requirements of inservice inspection per ME Code,Section XI, Subsection IWB.

wn schematically on Figure 5.1-1, Reactor Coolant System Boundary Diagram Steam Generators (primary side)

Pressurizer Reactor Coolant Pump Reactor Coolant Piping Chemical and Volume Control - to isolation valves Residual Heat Removal - to isolation valves High Pressure Safety Injection - to isolation valves Low Pressure Safety Injection - to isolation valves 4.2 Accessibility meet the accessibility requirements necessary for inservice inspection to ASME XI, sufficient ce is provided around each inspection area to permit access by the inspector and his ipment. Space allowance for assembly and disassembly of tooling and equipment, such as folding, lighting, and insulation, has been provided.

stablishing the physical layouts of the piping systems within the inspection boundaries as ned by the Code, the following general accessibility criteria were followed:

1. The surfaces of pipe welds were held at a minimum of 6 inches from an adjacent flat surface such as a wall.

2. Where the adjacent surface is curved as in the case of pipes arranged parallel to each other, the minimum clearance may have been reduced to 4 inches. In providing these clearances, allowance was made for insulation which may be on the adjacent pipes.

3. Space is provided on both sides of any pipe weld such that an operator has complete access to the pipe inspection area.

4. The ultrasonic examination of welds requires that, in addition to the weld, a length of pipe on each side of the weld can be completely accessible to the operator.

Insulation has been designed to be removable over applicable pipe lengths.

d experience and development of new ultrasonic techniques have shown that pipe welds und smooth and flat rather than crowned produce satisfactory inspection results.

piping welds in Class 1 systems were evaluated, and abrupt or sharp edges eliminated to ge smoothly with the adjacent pipe or component surface. Any grinding was restricted to the

e welds prepared in the manner described above can be successfully examined ultrasonically pproaching the welds from both sides.

ere the weld can only be examined from one side with little or no access from the opposite as with pipe to valve welds or pipe to fitting welds, grinding the weld flush permits necessary sducer contact over the weld area to fully comply with the Code requirements.

ssist in the provision of adequate inspection access, the following information was considered stablishing the plant layout:

1. Reactor vessel - The reactor vessel closure head is examined at the head laydown area. The closure studs receive both a volumetric and a surface examination.

A special tool is available specifically for examining the reactor vessel from the inside when full of water. This vessel inspection tool performs remote examination of all the required inspection areas in the vessel apart from the bottom head disc to ring weld and incore instrumentation penetration nozzles. Lower head welds require manual examination from the outside of the vessel. The building design allows for free access to the bottom of the reactor cavity for easy passage of personnel and equipment. The inclusion of a bottom head disc to ring weld is a feature of all reactor vessels and the inherent inability to examine this internally is likely to be a limitation of all reactor vessel inspection tool designs. Reactor nozzle safe end welds are required to have volumetric, visual, and surface examinations.

Access to these locations has been provided. Figure 5.2-1 shows the reactor vessel inspection areas.

2. Steam generator - Requirements for this vessel, on the primary side, are volumetric examination of the channel head to tube sheet weld, visual examinations on pressure retaining bolting, and surface and volumetric examination of nozzle to safe end welds and volumetric examination of the nozzle inner radius sections.

Adequate clearance for personnel access was provided in these areas between any adjacent missile shielding or support structures.

Figure 5.2-2 shows the steam generator inspection areas.

3. Main coolant pump - The examination requirements for pumps include visual and volumetric inspections of integrally welded supports and pressure retaining bolting. Additionally, relief has been granted to allow the internal surface of a disassembled pump to be visually examined during maintenance activities. Access required for disassembly to permit these inspections is provided in maintenance considerations.

circumferential and longitudinal welds together with all the instrumentation, surge, spray, and relief nozzle welds were 100 percent volumetrically inspected during the preservice inspection. Subsequent inservice inspections require that 1 foot of each longitudinal shell weld that intersects the circumferential shell-to-head welds and 100 percent of each circumferential shell-to-head weld are inspected.

Additionally, the spray, surge, relief, and safety nozzle inner radius sections are volumetrically examined.

Figure 5.2-3 shows the pressurizer inspection areas.

5. Valves - Class 1 valves, unless exempted by the exclusion criteria of the Code, require volumetric examination of pressure retaining welds and pressure retaining bolting 2 inches and larger in diameter. Also included are visual examination of internal pressure boundary surfaces on selected valves exceeding 4 inches nominal pipe size, pressure retaining bolting smaller than 2 inches in diameter, and surface or volumetric examinations, as applicable, on integrally welded support attachments. Adequate space is provided for personnel and equipment access to perform required inspections.

6. Piping - Piping, safe end, and branch connection welds 4 inches and greater require both volumetric and surface examinations, while those welds less than 4 inches require surface examinations only. Pressure retaining bolting exceeding 2 inches in diameter requires a volumetric examination, whereas bolting 2 inches and less requires visual examinations. Integral attachment welds for vessels, piping, pumps, and valves require a surface or volumetric examination, as applicable. Support components outside the IWB boundary require visual examinations in accordance with subsection IWF. Sufficient space has been provided for personnel and equipment access.

4.3 Examination Techniques and Procedures ual examinations are conducted in accordance with the guidelines of Paragraph IWA-2210, tion XI, ASME Code.

face examinations are conducted in accordance with the guidelines of Paragraph IWA-2220, tion XI, ASME Code.

umetric examinations are conducted in accordance with the guidelines of Paragraph A-2230,Section XI, ASME Code.

ote ultrasonic scanning equipment is used at Millstone for the reactor vessel nozzle, flange, shell weld examinations for both the preoperational baseline and the later inservice ections. The remote scanning equipment is supported from a fixture which is positioned on reactor vessel internals support flange. Each time the fixture is placed on the support flange, it

fixture acts as the main support and positioning mechanism for the various inspection chments (i.e., nozzle scanner, flange scanner, and vessel-shell scanner). The various scanners e multiple transducers to accommodate varying vessel geometrics and weld configurations.

ropriate drives provide the required movements of the transducers. The scanners can be xed to assure accurate reproducibility for later inspections.

nual inspection techniques are used on the steam generators, pressurizer, and piping.

4.4 Inspection Intervals defined in subarticle IWA-2400 and IWA-2420 (Inspection Program B) of ASME Code, tion XI, the inspection interval is 10 years. The interval may be extended by as much as 1 year ermit inspections to be concurrent with plant outages.

inspection schedule is in accordance with IWB-2420. It is intended that inservice minations be performed during normal plant outages, such as refueling shutdowns or ntenance shutdowns occurring during the inspection interval.

4.5 Examination Categories and Requirements extent of examinations performed is in accordance with ASME Code,Section XI, Table B-2500-1.

ddition, preservice inspections complied with IWB-2200.

4.6 Evaluation of Examination Results luation of examination results is conducted in accordance with IWB-3000, with flaw luation in accordance with Table IWB-3410-1. Criteria for determining the need for repair is ccordance with IWB-3000; necessary repairs comply with IWB-4000.

4.7 System Leakage and Hydrostatic Pressure Tests tem leakage and hydrostatic tests are conducted in accordance with IWA-5000 and IWB-5000.

4.8 Relief Requests Class 1 portion of the PSI program was developed using the criteria of the ASME Code, tion XI, 1980 Edition, Winter 1980 Addenda along with existing construction drawings as were issued. An ISI program was finalized using the criteria of the ASME Code,Section XI, 3 Edition, Summer 1983 Addenda known to be applicable and submitted to the NRC pursuant 0 CFR Part 50. At that time relief requests were identified.

hods are provided for detection of leakage through the reactor coolant pressure boundary PB). These methods meet the requirements of General Design Criterion 30 (Section 3.1.2) the guidelines of Regulatory Guide 1.45 (Section 1.8).

5.1 Controlled Leakage trolled leakage shall be that seal water flow supplied to the Reactor Coolant Pump seals.

5.2 Identified Leakage 5.2.1 Definition of Identified Leakage ntified Leakage is comprised of:

1. Leakage (except Controlled Leakage) into closed systems, such as pump seal or valve packing leaks, that is collected and diverted to a collecting tank

2. Leakage into the containment atmosphere from sources that are specifically located and are known not to interfere with the operation of the leakage detection systems or are known not to be reactor coolant pressure boundary leakage

3. Reactor coolant system leakage through a steam generator to the secondary coolant system 5.2.2 Collection and Monitoring of Identified Leakage

1. Valve stem leakage Valve stem leakoffs for the following valves are piped to the valve stem leakoff header in the reactor plant gaseous drains system (Section 9.3.3): reactor coolant system loop isolation valves and loop bypass valves, and the pressurizer spray line isolation valves. The leakoff header drains to the containment drains transfer tank.

Excessive stem leakage results in an increase in the rate of drainage collection in this tank. Tank level is monitored and alarmed in the control room. Inspection of flow glasses, located at several points in the common drain header, permits the source of leakage to be narrowed to a smaller group of valves. Determination of the leaking valve(s) is made by sequentially changing individual valve positions and observing changes in leakage rate.

2. Leakage from pressurizer safety valves or power operated relief valves Leakage is indicated by high temperature or mass flow in a safety valve discharge line or by high temperature in the combined discharge line from the power

indication and high level alarm are provided in the control room.

3. Reactor vessel flange leakage Temperature in the leakoff line from the reactor vessel flange O-ring seal leakage monitor connection is indicated and annunciated in the control room.

An increase in temperature of the leakoff line above ambient is an indication of O-ring seal leakage. High temperature actuates an alarm in the Control Room. This leakage is collected in the containment drains transfer tank.

4. Post Accident Sampling System Flow Flow from the Post Accident Sampling System may be directed to the containment drains sump during system line purging, sample acquisition, and flushing.

5. All leakage (liquid or vapor) into the containment atmosphere, which is not collected in the containment drains sump, is collected in the unidentified leakage sump. Some of this leakage is identified leakage from sources that are specifically located and are known not to interfere with the operation of the leakage detection systems or are known not to be reactor coolant pressure boundary leakage. This identified leakage, from either the reactor coolant or auxiliary systems, is normally monitored as unidentified leakage, along with the rest of the leakage to the unidentified leakage sump. However, to improve the effectiveness of the unidentified leakage sump level monitoring system alarm (the alarm alerts operators to the possibility of RCPB leakage), the alarm set point may be adjusted to account for identified leakage.

5.2.3 Reactor coolant pump shaft seal leakage Leakage may be identified by one, or a combination, of the following indications and/or alarms:

a. High flow rate of CVC seal return (CBO (controlled bleed off)): indication and alarm in control room.

b. High temperature of CVC seal return (CBO): indication and alarm provided by the computer in control room.

c. High CVC seal return (CBO) temperature upstream seal water filter: local indicator.

5.3.1 Definition of Unidentified Leakage dentified leakage is all leakage which is not identified leakage.

5.3.2 Collection of Unidentified Leakage reactor coolant leakage in the containment structure, which is not collected in the containment ns transfer tank, in the pressurizer relief tank, or in the containment drains sump is collected in unidentified leakage sump (Section 9.3.3). A drain trench in the containment floor is provided this purpose.

5.3.3 Detection of Unidentified Leakage following methods are used to detect unidentified leakage:

1. Containment (unidentified or drains) sump level or sump pump run time monitoring

2. Containment airborne particulate radioactivity monitoring

3. Containment airborne gaseous radioactivity monitoring

4. Containment pressure, temperature, and humidity monitoring (backup method)

5. Operator actions:

a. Check makeup rate to the reactor coolant system for abnormal increase.

Instrumentation is provided to measure the amount of reactor coolant diverted to the boron recovery system. Taking diverted letdown flow into consideration, net level changes in the pressurizer and volume control tank are all means for identifying system leakage.

b. Review logs for maintenance actions which may have resulted in discharge of water into the containment structure.

5.3.4 Leakage Detection Method Sensitivity and Response Times sitivity and response times for leakage detection methods 1 through 4, Section 5.2.5.3.3, are as ows:

1. Unidentified leakage sump level and sump pump instrumentation

detecting a 1 gpm change in the leakage rate into the sump within one hour.

2. Containment airborne particulate and gaseous radioactivity monitors These monitors respond to the increase in airborne radioactivity resulting from RCPB leakage, provided there is limited ambient airborne concentration from previous leakage into the containment. The actual time required to detect reactor coolant leakage depends upon the rate and location of leakage, reactor coolant gaseous activity level, and the containment ambient background activity. A 1 gpm RCPB leak can be detected in less than one hour with the particulate monitoring system and the gaseous monitoring system provided that the reactor coolant activity is sufficiently high and the containment activity is below a level that would mask the change in activity corresponding to this leak rate. To ensure adequate response to a coolant leak with lower coolant and higher containment activity, the monitor setpoints are set as low as possible without causing an excessive number of spurious alarms.

3. Containment pressure, temperature, and humidity RCPB leakage causes an increase in containment pressure, temperature, and humidity. Humidity, temperature or pressure monitoring of the containment atmosphere are considered as alarms or indirect indication of leakage to the containment.

5.3.5 Leakage Detection Method Indicators and Alarms following indicators and/or alarms are provided in the Control Room as a means for alerting operator to RCPB leakage:

1. Unidentified leakage sump and sump pump Unidentified leakage sump pump operation for greater than a preset time period results in an alarm in the control room. The plant computer monitors unidentified leakage sump level and sump pump running time (this information is also available at the liquid waste panel in the waste disposal building). The plant computer normally provides an alarm to alert operators if leakage to the unidentified leakage sump exceeds 1 gpm in any given hour. The alarm set point may be adjusted (not to exceed 2 gpm) to account for identified leakage from reactor coolant or auxiliary systems which goes to the unidentified leakage sump.

Additionally, the level instrumentation in the Containment Drains Sump (Sump

1. 3) can be monitored if the unidentified leakage sump system is determined to be inoperable. Procedures are provided to the operator for the determination of this leakage rate should the plant computer be unavailable.

Indicators and alarms are provided in the control room.

3. Containment pressure, temperature, and humidity Indication and alarm are provided for pressure. Indication is provided for temperature and humidity.

5.3.6 Seismic Capability of Leakage Detection Methods containment airborne particulate and gaseous radioactivity monitors are qualified to remain ctional when subjected to the Safe Shutdown Earthquake (SSE).

5.3.7 Testing and Calibration equipment and instrumentation used for RCPB leak detection are in continuous operation. The visions for testing and calibration of each method are described in the specific section for that em, as follows:

Method Section Unidentified Leakage Sump 9.3.3 Containment Radiation Monitoring 12.3.4 Containment Pressure, Temperature and Humidity 7.5 5.4 Intersystem Leakage ential intersystem leakage paths with associated instrumentation and monitoring methods used etect such leakage are as follows:

1. Secondary side of steam generators One or a combination of the following methods are used to identify steam generator tube and tube sheet leaks:

a. High activity as monitored and alarmed in the condenser air ejector vent line.

b. Steam generator secondary side radioactivity, as determined by sampling (Section 9.3.2)

c. Radioactivity, boric acid, or conductivity in condensate, or blowdown e.g.,

from main steam line drain traps, as indicated by laboratory analysis.

Rupture of the thermal barrier results in an increase in flow in the reactor plant component cooling water system return line from the thermal barrier (Section 9.2.2.1). At a predetermined setpoint of increasing flow, an air-operated valve in the return line closes; this, in conjunction with a check valve in the supply line, isolates the thermal barrier. The position of the air-operated valve is monitored in the control room. Additionally, the two main headers in the reactor plant component cooling water system are continuously monitored for radioactivity.

3. Low Pressure System Accumulators Leakage of reactor coolant past the check valves in the accumulator discharge line results in an increased level in the accumulator. High level is alarmed in the control room.

4. Secondary side of letdown heat exchanger, excess letdown heat exchanger, RHR heat exchanger, and reactor coolant pump seal water heat exchanger These heat exchangers are cooled by the reactor plant component cooling water system. Leakage into this system would be detected by the radiation monitors in the reactor plant component cooling water system.

5. Safety injection systems (high and low pressure)

Potential leakage paths that exist in the ECCS are the accumulator check valve bypass leakage to the RCS and piping and mechanical equipment leakage outside the containment.

Accumulator leakage is detected by level and pressure instrumentation provided for each accumulator. This instrumentation is continuously monitored during plant operation. Flow from each accumulator can be directed at any time through a test line to determine check valve leakage.

With respect to piping and mechanical equipment outside the containment, considering the provisions for visual inspection (if access is available) and leak detection, leaks are detected before they propagate to major proportions. A review of the equipment in these systems indicates that the largest sudden leak potential would be the sudden failure of a pump shaft seal. Evaluation of leakage rate, showed that flows of less than 50 gpm would result. Piping leaks, valve packing leaks, or flange gasket leaks are considered less severe than the pump seal failure.

Based on this review, the auxiliary and engineered safety features buildings and related equipment are designed to be capable of handling leaks up to a maximum of 50 gpm. Means are also provided to detect and isolate such leaks in the

(Sections 6.3, 7.3).

Larger leaks in the ECCS are prevented by the following:

a. The piping is classified ANS Safety Class 2 and, therefore, must comply with the corresponding quality assurance program associated with this safety class.

b. The piping, equipment, and supports are designed to ANS Safety Class 2 seismic classification permitting no loss of function resulting from the design basis earthquake.

c. The system piping is located within a controlled area on the plant site.

d. The piping system receives periodic pressure tests and is accessible for periodic visual inspection.

e. The piping is austenitic stainless steel which is not susceptible to brittle fracture during operating conditions.

6. Residual heat removal system (inlet and discharge)

Each suction and discharge line in the RHRS is equipped with a pressure relief valve. Each suction side relief valve is sized to relieve the flow of one charging pump at the relief valve set pressure. The discharge side relief valves relieve the maximum possible back leakage through the valves separating the RHRS from the RCS. Their relief flow capacity is 20 gpm at a set pressure of 600 psig (Section 5.4.7).

The fluid discharged by the suction side relief valves is collected in the pressurizer relief tank. The fluid discharged by the discharge side relief valve is collected in the recycle holdup tank of the boron recovery system (Section 9.3.5).

5.5 Technical Specifications er to Millstone Unit 3 for Technical Specifications for applicable RCPB leakage detection hods.

5.6 Primary Coolant Sources Outside Containment section 50.55a of 10 CFR 50 describes the codes and standards which must be implemented in design, construction, testing and inservice inspection of fluid systems subject to the ASME ler and Pressure Vessel Code. Preservice and inservice inspection program and leakage eptance criteria is based in part on the applicable section of the ASME Code,Section XI.

n to containment subsequent to an accident 10 CFR 50, Appendix J. III A.I(d). Appendix J uires these leak tests be performed periodically throughout the life of the plant and that the lts be reported to the NRC.

lstone 3 has a program to reduce leakage from systems outside containment that would or ld contain highly radioactive fluids in a post-accident situation. The program includes the owing:

1. System design and construction were reviewed to ensure that the potential for inadvertent releases of radioactive fluids is eliminated.

2. The implementation of all practical leak reduction measures for all systems that could carry radioactive fluid outside containment

3. The measurement of actual leak rates

4. A leak reduction program of preventive maintenance to reduce leakage to as-low-as-practical levels. Pressure testing at system operating pressure and integrated leak tests at intervals not to exceed each refueling cycle are typical demonstrations of system integrity.

ce the letdown and charging system are used in the determination of reactor coolant system age (inventory balance) the integrity of these systems is maintained.

veillance of the leak tightness of other systems which routinely contain radioactive fluids or es is assured by routine surveillance of the auxiliary and waste disposal buildings and airborne ation monitors in these buildings. The leak tightness of these systems is determined by the ctives of keeping occupational and routine releases as low as reasonably achievable.

e plant systems are excluded because the containment isolation systems prevent significant ases to these systems and the design of the plant does not require operation of these systems to gate an accident.

ce the containment building always has the largest inventory of radioactive materials, eased surveillance on a component containing a small fraction of the containment building entory cannot reduce the risk of a release significantly. Therefore, upgrading the leak testing of components described above, beyond the requirements of Appendix J and the inservice ection required by Section XI of the ASME Code is not contemplated.

tems outside containment which are maintained under this program include the recirculation y, safety injection, charging portion of chemical and volume control, and hydrogen mbiners, in accordance with Millstone 3 Technical Specification 6.8.4a.

1 Eicheldinger C., Fracture Toughness Properties of SA533 Class 2 and SA508 Class 2a Steels. Letter NS-CE-1228 (10/4/76) to J. F. Stolz of NRC, Office of Nuclear Reactor Regulation, Westinghouse Nuclear Safety Dept., Westinghouse Corp., Pittsburgh, Penn.

2 Eicheldinger C., Transmittal Letter for Westinghouse Topical Report WCAP-9292, Letter NS-CE-1730 (3/17/78) to J. F. Stolz of NRC Office of Nuclear Reactor Regulation, Westinghouse Nuclear Safety Dept., Westinghouse Corp., Pittsburgh, Penn.

3 WCAP-7477-L (Proprietary), March 1970, Golik, M.A. and WCAP-7735 (Non-proprietary), August, 1971, Hazelton, W.S. Sensitized Stainless Steel in Westinghouse PWR Nuclear Steam Supply Systems, Westinghouse Corp., Pittsburgh, Penn.

4 WCAP-7769, Rev. 1, June 1972, Cooper, K., et al., Overpressure Protection for Westinghouse Pressurized Water Reactors, Westinghouse Corp., Pittsburgh, Penn.

5 Eichelding, C., Transmittal of additional data requested by NRC for review of WCAP-7769, Rev. 1, Letter NS-CE-622 (4/16/75) to D. B. Vassallo of NRC, Directorate of Licensing, Westinghouse Nuclear Safety Dept., Westinghouse Corp., Pittsburgh, Penn.

6 WCAP-7907, October 1972, Burnett, T.W.T., et al., LOFTRAN Code Description, Westinghouse Corp., Pittsburgh, Penn.

7 WCAP-8324-A, June 1975, Enrietto, J. F., Control of Delta Ferrite in Austenitic Stainless Steel Weldments, Westinghouse Corp., Pittsburgh, Penn.

8 WCAP-8693, January 1976, Enrietto, J. F., Delta Ferrite in Production Austenitic Stainless Steel Weldments, Westinghouse Corp., Pittsburgh, Penn.

9 WCAP-9292, March 1978, Logsdon, W.A., et al., Dynamic Fracture Toughness of ASME3 SA508 Class 2a and ASME SA53 Grade A Class 2 Base and Heat Affected Zone Material and Applicable Weld Metals, Westinghouse Corp., Pittsburgh, Penn.

10 WCAP-11878, Analysis of Capsule U from the Northeast Utilities Service Company Millstone Unit 3 Reactor Vessel Radiation Surveillance Program.

11 Counsil, W.G., Millstone Nuclear Station, Unit No. 3 Request for Acceptance of a New Code Case and a Revised Code Case, Letter B11216 (6/8/84) to B. J. Youngblood of NRC Division of Licensing, Nuclear Regulatory Commission, Washington, D.C.,

Northeast Utilities Energy Company, (With attached Report 12179-J(B)-131, 1983, Banic, M., et al, The Effect of Carbon Content on the Need to Postweld Heat Treated ASTM A 487 Class 10Q Material, Stone and Webster Engineering Corporation, Boston, MA.)

Nuclear Energy Company, Nuclear Regulatory Commission, Washington, D.C.

13 Youngblood, B.J., Use of ASME Code Case N-249-4 for Millstone Nuclear Power Station, Unit 3, Letter dated 9/24/85 for Docket No. 50-423 to J.F. Opeka of Northeast Nuclear Energy Company, Nuclear Regulatory Commission, Washington, D.C.

14 The Procedure Handbook of Arc Welding, 12th Edition, Lincoln Electric Company, June 1973.

15 WCAP-15405, Revision 0, May 2002, Analysis of Capsule X from the Northeast Nuclear Energy Company Millstone Unit 3 Reactor Vessel Radiation Surveillance Program.

16 WCAP-16629-NP, Revision 0, September 2006. Analysis of Capsule W from the Dominion Nuclear Connecticut Millstone Unit 3 Reactor Vessel Radiation Surveillance Program.

SYSTEM COMPONENTS actor vessel ASME III, 1971 Edition through Summer 73 DM head adapter ASME III, 1971 Edition through Summer 73 TC Pressure Boundary ASME III, 1974 Edition through Summer 74 am generator ASME III, 1971 Edition through Summer 73 re Exit Thermocouple Nozzle Assembly ASME III, 1980 Edition through Winter 80 ssurizer ASME III, 1971 Edition through Summer 73 DM housing Full length ASME III, 1974 Edition through Summer 74 actor coolant pump ASME III, 1974 Edition through Summer 74 actor coolant pipe ASME III, 1971 Edition through Summer 73 rge line ASME III, 1971 Edition through Summer 73 SS valves Pressurizer safety ASME III, 1971 Edition through Winter 72 Power-operated relief ASME III, 1977 Edition through Summer 79 Pressurizer spray ASME III, 1971 Edition through Summer 73 Control ASME III, 1971 Edition through Winter 1972 addenda to 1977 Edition through Summer 1979 Addenda tor-operated Loop isolation ASME III, 1971 Edition through Winter 73 Loop bypass ASME III, 1971 Edition through Summer 72 Head vent isolation ASME III, 1977 Edition through Summer 79 P valves in interconnecting lines Dresser forged stainless steel 2 inches ASME III, 1974 Edition Velan forged stainless steel 2 inches ASME III, 1977 Edition through Summer 79 Cast stainless steel 2 1/2 inches ASME III, 1971 Edition through Summer 73 Forged stainless steel 2 1/2 inches ASME III, 1971 Edition through Summer 73 Control valves ASME III, 1971 Edition through Summer 73 erconnecting piping ASME III, 1971 Edition through Summer 73

SPECIFICATIONS actor Vessel Components Shell and head plates (other than core SA-533, Gr. A, B, or C, Class 1 (vacuum treated) region)

Shell plates (core region) SA-533, Gr. A or B, Class 1 (vacuum treated)

Shell, flange, and nozzle forgings SA-508, Class 2 or 3 Nozzle safe ends SA-182, Type F304 or F316 CRDM head adaptor and upper head SB-166 or 167 and SA-182, Grade F304 F304L, or F316 Heated Junction Thermocouple SA-479, 213, 479, Type 304; SA 182, F3 System Instrumentation tube appurtenances, SB-166 or 167 and SA-182, Type F304, F304L, or lower head F316 Closure studs, nuts, washers, inserts, SA-540, Class 3 Gr. B24 and adaptors Core support pads SB-166 with carbon less than 0.10%

Monitor tubes and vent pipe SA-312 or 376, Type 304, 316, SB-166 or SB-167 or SA-182 Type 316 Vessel supports, seal ledge and head SA-516, Gr. 70, quenched and tempered or SA-533, lifting lugs Gr. A, B, C, Class 1 or 2 (vessel supports may be of weld metal buildup of equivalent strength)

Cladding and buttering Stainless steel weld metal analysis A-7 and Ni-Cr-Fe weld metal F-Number 43 am Generator Components Pressure plates SA-533, Gr. A, B, or C, Class 1 or 2 Pressure forgings (including nozzles SA-508, Class 1,2,2a, or 3 and tubesheet)

Nozzle safe ends Stainless steel weld metal analysis A7 Channel heads SA-533, Gr. A,B, or C, Class 1 or 2 or SA-216, Gr.

WCC Tubes SB-163, Ni-Cr-Fe annealed Cladding and buttering Stainless steel weld metal analysis A-7 and Ni-Cr-Fe weld metal F-Number 43 Closure bolting SA-193, Gr. B7

ssurizer Components Pressure plates SA-533, Gr. A,B, or C, Class 1 or 2 Pressure forgings SA-508, Class 2 or 2a Nozzle safe ends SA-182, Type 316 or 316L and Ni-Cr-Fe weld metal F-Number 43 Cladding and buttering Stainless steel weld metal analysis A-7 or A-8 for Code dates later than 1974 and Ni-Cr-Fe weld metal F-Number 43 Closure bolting SA-193, Gr. B7 actor Coolant Pump Pressure forgings SA-182, Type F304, F316, F347, or F348 Pressure casting SA-351, Gr. CF8, CF8A, or CF8M Tube and pipe SA-213, 376, or 312, seamless Type 304 or 316 Pressure plates SA-240, Type 304 or 316 Bar material SA-479, Type 304 or 316 Closure bolting SA-193, 540, or 453, Gr. 660, SB-637 Gr. NO771B Flywheel SA-533, Gr. B, Class 1 ing Reactor coolant loop pipe SA-351, Gr. CF8A centrifugal casting Reactor coolant fittings, branch SA-351, Gr. CF8A static casting, and SA-182, Code nozzles Case 1423-2, Gr. 316N Surge line SA-376, Gr. TP304 Loop bypass SA-376, Gr. TP304 Auxiliary piping SA-312 and SA-376 Grades TP304 and TP316 to ANSI B36.10 or B36.19 Socket weld fittings ANSI B16.11 Butt weld fittings ANSI B16.9 Piping flanges ANSI B16.5 ll Length CRDM Latch housing SA-182 Grade 304, SA-336 Class F8, or SA-351, Gr. CF8

Rod travel housing SA-182, Gr. F304 or SA-336, Gr. F8 Cap SA-479, Type 304 Welding materials Analysis A-8, Type 308, or 308L lves Bodies SA-182, Type F316 or SA-351, Gr. CF8 or CF8M Bonnets SA-182, Type F316 or SA-351, Gr. CF8 or CF8M or SA-479 Type 316 Discs SA-182, Type F316 or SA-564, Gr. 630, or SA-351 Gr. CF8 or CF8M or SA-479 Type 316 Stems SA-182, Type F316 or SA-564, Gr. 630 Pressure retaining bolting SA-453, Gr. 660 Pressure retaining nuts SA-453, Gr. 660 or SA-194, Gr. 6 xiliary Heat Exchangers Heads SA-240, Type 304 Nozzle necks SA-182, Gr. F304; SA-240 and SA-312, Type 304 Tubes SA-213 and SA-249, Type 304 Tubesheets SA-182, Gr. F304; SA-240, Type 304 and 515, Gr.

70 with Type 304 SS weld overlay Shells SA-240 and 312, Type 304 xiliary Pressure Vessels, Tanks, Filters, etc.

Shells and heads SA-240, Type 304 and Type 316; SA-351 Gr. CF8M or SA-264 consisting of SA-537, Gr. C11 with stainless steel weld metal analysis A-8 cladding Flanges and nozzles SA-182, Gr. F304 and SA-105 or 350, Gr. LF2 and LF3 with stainless steel weld metal analysis A-8 cladding Piping SA-312 and 240, Type 304 or 316 seamless Pipe fittings SA-403, Type 304 seamless Closure bolting and nuts SA-193, Gr. B7 and SA-194, Gr. 2H xiliary Pumps Pump casing and heads SA-351, Gr. CF8 or CF8M and SA-182, Gr. F304 or F316

Flanges and nozzles SA-182, Gr. F304 or F316 and SA-403, Gr. WP316L seamless Piping SA-312, Type 304 or 316 seamless Stuffing or packing box cover SA-351, Gr. CF8 or CF8M and SA-240, Type 304 or 316 Pipe fittings SA-403, Gr. WP316L seamless Closure bolting and nuts SA-193, Gr. B6, B7, or B8M and SA-194, Gr. 2H or 8M, SA-193, Gr. B6, B7, or B8M, SA-453, Gr. 660, and nuts, SA-194, Gr. 2H, 8M, and 6

SA-182, Type F304 and F304H, or Type 403 per Westinghouse rgings Procedure 80280NL tes SA-240, Type 304 es ASTM A-358, Grade 304, Class 1, SA358 Grade 304 Class 1 SA-213, Type 304; SA249 Grade TP304; ASTM A-511, MT 304; and bes ASTM A-554, MT 304 rs SA-479, Type 304 and 316; ASTM A-276, 304 and SB-166 stings SA-351, Gr. CF8 SA-193, Gr. B8M Code Case 1618, Inconel 750 SA-637, Gr. 688 Type lting 2; SA-479, Type 316, Strain Hardened (Code Case 1618)

SA-194, Gr. 8 or 8A; SA-479, Type 304 and SA-637, Grade 688, Type ts 2

SA-479, Type 304, 304L or Type 316, SA-240, Type 304, ASTM A-cking devices 240, Type 304; and ASTM B-166 ld buttering ER 308, ER 308L, E308-15, E308L-15, E308T-3

TABLE 5.2-4 REACTOR COOLANT WATER CHEMISTRY SPECIFICATION Electrical conductivity Determined by the concentration of boric acid and alkali present, expected range is 5to 60S/cm at 25C.

Solution pH Determined by the concentration of boric acid and alkali present, expected values range between 4.5 (high boric acid concentration) and 11.0 (low boric acid concentration) at 25C; value will be 6.9 or greater at normal operating temperatures when the reactor is critical.

Oxygen, maximum (ppm) 0.1 Chloride, maximum (ppm) 0.15 Fluoride, maximum (ppm) 0.15 Hydrogen (cc (STP)/Kg H2O) 25 to 50 Total suspended solids, maximum (ppm) 0.05 pH control agent (Li7OH) (ppm) 0.3 to 6.0 as Li Boric acid (ppm B) Variable from 0 to approximately 4,000 TES:

Oxygen concentration must be controlled to less than 0.1 ppm in the reactor coolant at temperatures above 250F by scavenging with hydrazine. During power operation with the specified hydrogen concentration maintained in the coolant, the residual oxygen concentration control value becomes0.005 ppm.

Halogen concentrations must be maintained below the specified values at all times regardless of system temperature.

Hydrogen must be maintained 15 cc (STP)/kg H2O whenever the reactor is critical. The normal operating range should be 25 to 50 cc (STP)/kg H2O.

Solids concentration determined by filtration through filter having 0.45 micron pore size.

Suspended solids concentrations as high as 0.35 ppm may be observed during startups and shutdowns. However, sustained plant operation with suspended solids > 0.05 ppm should be investigated, and crud mitigation measures taken as necessary.

Limits for lithium hydroxide established for normal full power operation in conjunction with the fuel vendor. Prior to reactor criticality, sufficient lithium hydroxide is added to ensure a minimum at-temperature pH of a least 6.9. Lithium may be removed shortly before plant shutdown to aid in the clean up of RCS corrosion products.

LOADS (KIPS, INCH)

CONDITION Fx Fy Fz Mx My Mz 0 7 0 0 0 0 AD WEIGHT (5) a (20) (5) (100) (1) (32)

ERMAL 18 33 10 135 0 243 b (20) (75) (20) (523) (5) (135) 2 12 11 150 0 27 ISMIC 1/2 SSE (20) (30) (20) (390) (2) (134) 2 27 14 190 0 27 ISMIC SSE (35) (50) (35) (645) (2) (235) 1 14 5 70 0 14 LVE OPER. (OCCASIONAL)

(30) (100) (30) (560) (2) (204) 18 277 92 1246 0 244 ULTED CONDITION (140) (325) (140) (1715) (2) (963)

FETY LINE PIPE RUPTURE 15 229 73 986 0 203 Value within ( ) equals Westinghouse allowable loads.

When combined with other loads in norm/upset/test conditions, total value is less than Westinghouse allowable. Westinghouse has no allowable loads for pipe rupture.

Mark Number Service Location 3CCE*RV40A&B Charging Pump Cooler Relief Valves Auxiliary Building 3CCE*RV43A-C Cooler Relief Valves Auxiliary Building Safety Injection Pump Cooler Relief 3CCI*RV31A&B ESF Building Valves 3CCI*RV36A&B Cooler Relief Valves ESF Building Excess Letdown Heat Exchanger Relief 3CCP*RV39 Containment Valve Reactor Coolant Pump Thermal Barrier 3CCP*RV54A-D Containment Relief Valves 3CCP*RV59A&B Fuel Pool Cooler Relief Valves Auxiliary Building 3CCP*RV64A&B Residual Heat Exchanger Relief Valves Auxiliary Building 3CCP*RV82 Letdown Heat Exchanger Relief Valve Auxiliary Building 3CCP*RV85 Seal Water Heat Exchanger Relief Valve Auxiliary Building 3CCP*RV239A&B RHR Pump Cooler Relief Valves ESF Building Reactor Coolant Pump Upper Bearing 3CCP*RV258A-D Containment Relief Valves 3CCP*RV275A&B Containment Penetration Relief Valves Auxiliary Building 3CDS*RV105A&B Containment Penetration Relief Valves Auxiliary Building 3CDS*RV106A&B Containment Penetration Relief Valves Auxiliary Building Letdown Reheat Heat Exchanger Relief 3CHS*RV7006 Auxiliary Building Valve Letdown to Low Pressure 3CHS*RV8119 Auxiliary Building Demineralizer Relief Valve 3CHS*RV8120 Volume Control Tank Relief Valve Auxiliary Building 3CHS*RV8121 Seal Water Return Relief Valve Auxiliary Building 3CHS*RV8123 RCP Seal Water Return Header Auxiliary Building Charging Pump Suction Header Relief 3CHS*RV8124 ESF Building Valve 3DAS*RV87 Containment Penetration Relief Valve Auxiliary Building 3DGS*RV51 Containment Penetration Relief Valve Auxiliary Building 3FWA*RV45 Turbine Pump Relief Valve ESF Building

Mark Number Service Location 3FWS*CTV41A-D Bonnet Relief 3FWS*RV47A-D MS Valve Building Valves 3GWS-RV35 Degasifier Relief Valve Auxiliary Building 3GWS-RV77 GWS Relief Valve Auxiliary Building 3PGS*RV77 Containment Penetration Relief Valve Auxiliary Building 3RHS*RV8708A&B RHR Pump Suction Relief Valves Containment 3SFC*RV52A&B Fuel Pool Cooler Relief Valves Fuel Building 3SIH*RV8925A&B *P1A&B Suction Reliefs ESF Building 3SIH*RV8851 Cold Leg Injection Relief Valves ESF Building 3SIH*RV8853A&B SIS Pump Discharge Relief Valves ESF Building 3SIH*RV8858 SIS Pump Suction Header Relief Valve ESF Building 3SIL*RV8842 Hot Leg Injection Relief Valve ESF Building 3SIL*RV8855A-D Accumulator Tank 1 Relief Valves Containment RHR Pumps Safety Injection Line 3SIL*RV8856A&B ESF Building Relief Valves 3SIL*RV8857 Accumulator Nitrogen Supply Line Containment 3FWA*RV64A&B *P1A&B Suction Relief ESF Building 3FWA*RV65 *P2 Suction Relief ESF Building 3CHS*RV8501A-C *P1A-C Suction Relief ESF Building 3FPW*RV87 Containment Penetration Relief Valve Auxiliary Building 3SWP*RV95B 3CCP E1 Relief Valve Auxiliary Building

TABLE 5.2-7 MILLSTONE UNIT NO. 3 RTPTS VALUES (F)

Chemical Content I Initial M 1 Error RT Location Wt.% Cu Wt.% Ni NDT Term se Plate (CF/LF) 0.05 0.63 60 34 ld 0.05 0.05 -50 40.23 M is the margin term added to cover uncertainties in the values of initial RTNDT, copper and nickel content, fluence and calculational procedures.

Vessel Inside Surface Fluence (E 1 MeV)1019 n/cm2 RTPTS (F)

Location 54 EFPY 54 EFPY se Plate (CF/LF) 2.70 133 ld 2.70 30

1 REACTOR VESSEL MATERIALS 1.1 Material Specifications erial specifications are in accordance with the American Society of Mechanical Engineers ME) Code requirements and are given in Section 5.2.3.

ddition, the ferritic materials of the reactor vessel beltline were restricted to the following imum limits of copper, phosphorous, and vanadium to reduce sensitivity to irradiation rittlement in service.

Element Base Metal (%) As Deposited Weld Metal (%)

0.10 0.10 pper 0.12 (check) 0.012 (ladle) 0.015 osphorous 0.017 (check) nadium 0.05 (check) 0.05 (as residual) 1.2 Special Process Used for Manufacturing and Fabrication vessel is Safety Class 1. Design and fabrication of the reactor vessel was carried out in strict ordance with ASME Code,Section III, Class 1 requirements. The head flanges and nozzles e manufactured as forgings. The cylindrical portion of the vessel is made up of several shells, h consisting of formed plates joined by full penetration longitudinal weld seams. The ispherical heads were made with dished plates. The integral parts of the vessel and closure d subassemblies were joined by welding, primarily using the single or multiple wire merged arc.

use of severely sensitized stainless steel as a pressure boundary material has been prohibited has been eliminated by either a select choice of material or by programming the method of mbly.

control rod drive mechanism adaptor threads and surfaces of the guide studs are chrome ed to prevent possible galling of the mated parts.

ll locations in the reactor vessel where stainless steel and Inconel are joined, the final joining ds are Inconel weld metal in order to prevent cracking.

e region shells fabricated of plate material have longitudinal welds which are angularly ted away from the peak neutron exposure experienced in the vessel, where possible.

stainless steel clad surfaces were sampled to assure that composition and delta ferrite uirements are met.

procedure for cladding low alloy steel (SA-508, Class 2) is qualified in accordance with the mmendations of Regulatory Guide 1.43 (Section 1.8).

imum preheat requirements have been established for pressure boundary welds using low y material. The preheat is maintained either until (at least) an intermediate post weld heat tment is completed or until the completion of welding. In the latter case, upon completion of ding, a low temperature (400F minimum) post weld heat treatment is applied for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, owed by allowing the weldment to cool to ambient temperature. For primary nozzle to shell ds, preheat is maintained until an intermediate or full post weld heat treatment is completed.

1.3 Special Methods for Nondestructive Examination nondestructive examination of the reactor vessel and its appurtenances is conducted in ordance with the ASME Code,Section III requirements; also numerous examinations are ormed in addition to ASME Code,Section III requirements. Nondestructive examination of vessel is discussed in the following sections and shown in Table 5.3-1.

1.3.1 Ultrasonic Examination ddition to the ASME Code straight beam ultrasonic test, angle beam inspection of 100 percent late material was performed during fabrication to detect discontinuities that may be etected by longitudinal wave examination.

ddition to the ASME Code,Section III, nondestructive examination, all full penetration itic pressure boundary welds and heat affected zones in the reactor vessel were ultrasonically mined during fabrication. This test is performed upon completion of the welding and rmediate heat treatment but prior to the final post weld heat treatment. Section 5.3.3.7 usses this examination.

ddition to ASME Code,Section III, nondestructive examination, all full penetration ferritic sure boundary welds in the reactor vessel were ultrasonically inspected after hydrostatic ing to establish additional assurance that the vessel would pass the ASME Code,Section XI, ervice inspection requirements.

1.3.2 Penetrant Examinations partial penetration welds for the control rod drive mechanism head adaptors and the bottom rumentation tubes were inspected by dye penetrant after the root pass in addition to code uirements. Core support block attachment welds were inspected by dye penetrant after the first

1.3.3 Magnetic Particle Examination magnetic particle examination requirements below are in addition to the magnetic particle mination requirements of Section III of the ASME Code.

magnetic particle examinations of materials and welds were performed in accordance with the owing:

1. Prior to the final post weld heat treatment only by the Prod, Coil, or Direct Contact Method.

2. After the final post weld treatment only by the Yoke Method.

following surfaces and welds were examined by magnetic particle methods. The acceptance dards are in accordance with Section III of the ASME Code.

1.3.3.1 Surface Examinations re are three surface examinations:

1. All exterior vessel and head surfaces are magnetic particle examined after the hydrostatic test.

2. All exterior closure stud surfaces and all nut surfaces are magnetic particle examined after final machining or rolling. Continuous circular and longitudinal magnetization are used.

3. All inside diameter surfaces of carbon and low alloy steel products that have their properties enhanced by accelerated cooling are magnetic particle examined. This inspection is performed after forming and machining (if performed) and prior to cladding.

1.3.3.2 Weld Examination le 5.3-1 shows the non-destructive examinations for the Reactor Vessel.

1.4 Special Controls for Ferritic and Austenitic Stainless Steels ding of ferritic steels and austenitic stainless steels is discussed in Section 5.2.3. Section 5.2.3 udes discussions which indicate the degree of conformance with Regulatory Guides 1.31 and

. Section 1.8 discusses the degree of conformance with Regulatory Guides 1.34, 1.43, 1.50,

, and 1.99.

urance of adequate fracture toughness of ferritic materials in the reactor vessel (ASME Code, tion III, Class 1 component) is provided by compliance with the requirements for fracture ghness testing included in NB-2300 of Section III of the ASME Code and Appendix G of 10 R 50.

initial Charpy V-notch minimum upper shelf fracture energy levels for the reactor vessel line (including welds) are 75 foot-pounds as required per Appendix G of 10 CFR 50. The ture toughness data for the reactor vessel are given in Table 5.3-2. Reactor vessel beltline on material composition is given in Table 5.3-3. The predicted end-of-life beltline region erial information is given in Table 5.3-4. Plate locations are shown on Figure 5.3-1. The tor vessel closure head stud, nut, and washer material information is given in Table 5.3-5.

1.6 Material Surveillance he surveillance program, the evaluation of the radiation damage is based on pre-irradiation ing of Charpy V-notch and tensile specimens and post-irradiation testing of Charpy V-notch, ile and one-half T (thickness) compact tension (CT) fracture mechanics test specimens. The gram is directed toward evaluation of the effect of radiation on the fracture toughness of tor vessel steels based on the transition temperature approach and the fracture mechanics roach. The program conforms with ASTM-E-185-82, Conducting Surveillance Tests for ht Water Cooled Nuclear Power Reactor Vessels, and 10 CFR 50, Appendix H.

reactor vessel surveillance program uses six specimen capsules. The specimens are oriented equired by NB-2300 of Section III of the ASME Code. The capsules are located in guide kets welded to the outside of the neutron shield pads and are positioned directly opposite the ter portion of the core. The capsules can be removed when the vessel head and upper internals removed and can be replaced when the lower internals are removed. The six capsules contain tor vessel steel specimens, oriented both parallel and normal (longitudinal and transverse) to principal rolling direction of the limiting base material located in the core region of the reactor sel associated weld metal and weld heat affected zone metal. The six capsules contain 54 ile specimens, 360 Charpy V-notch specimens (which include weld metal and weld heat cted zone material), and 72 CT specimens. Archive material sufficient for two additional sules is retained.

imeters, including nickel (Ni), copper (Cu), iron (Fe), cobalt-aluminum (Co-Al), cadmium

) shielded Co-Al, Cd shielded neptunium-237 (Np-237), and Cd shielded uranium-238 238), are placed in filler blocks drilled to contain them. The dosimeters permit evaluation of flux seen by the specimens and the vessel wall. In addition, thermal monitors made of low ting point alloys are included to monitor the maximum temperature of the specimens. The cimens are enclosed in a tight fitting stainless steel sheath to prevent corrosion and ensure d thermal conductivity. The complete capsule was helium leak tested.

Number of Number of Number of Material Charpys Tensiles Compact Tensions miting base material

• 15 3 4 miting base material ** 15 3 4 ld metal *** 15 3 4 at affected zone 15 - -

TES:

Specimens oriented in the major rolling or working direction.

Specimens oriented normal to the major rolling working direction.

Weld metal to be selected per ASTM-E-185.

following dosimeters and thermal monitors are included in each of the six capsules.

Dosimeters Iron Copper Nickel Cobalt-aluminum (0.15 percent cobalt)

Cobalt-aluminum (cadmium shielded)

Uranium-238 (cadmium shielded)

Neptunium-237 (cadmium shielded Thermal monitors 97.5 percent lead (Pb), 2.5 percent silver (Ag) (579F melting point).

97.5 percent lead (Pb), 1.75 percent silver (Ag), 0.75 percent tin (Sn) (590F melting point).

fast neutron exposure of the specimens occurs at a faster rate than that experienced by the sel wall, with the specimens being located between the core and the vessel. Since these cimens experience accelerated exposure and are actual samples from the materials used in the sel, the transition temperature shift measurements are representative of the vessel at a later e in life. Data from CT fracture toughness specimens are expected to provide additional rmation for use in determining allowable stresses for irradiated material.

relations between the calculations and the measurements of the irradiated samples in the sules, assuming the same neutron spectrum at the samples and the vessel inner wall, are cribed in Section 5.3.1.6.1.

eillance specimen data. Verification and possible readjustment of the calculated wall osure will be made by use of data on all capsules withdrawn. The schedule for removal of the sules and the measured or expected neutron fluence is as follows:

Lead Removal Time Fluence psule Location Factor(a) (EFPY)(b) (n/cm2 E>1.0MeV)(a)

U 58.5° 4.06 1.3 4.00 x 1018 (c)

X 238.5° 4.35 8.0 1.98 x 1019 (c)

W 121.5° 4.22 13.8 3.16 x 1019 (c)(d)

Y(e) 241° 3.98 13.8 --

Y(f) 61° 3.98 -- Footnote (i)

V(e) 61° 3.98 Storage --

Z(g) 301.5° 4.22 23.4 5.37 x 1019 (h)

(a) Updated in Capsule W dosimetry analysis.

(b) Effective Full Power Years (EFPY) from plant startup.

(c) Plant specific evaluation.

(d) This fluence is not less than once or greater than twice the peak end of license fluence, and is approximately equal to the peak vessel fluence at 63 EFPY.

(e) Capsules Y and V were withdrawn after 13.80 EFPY (EOC 10) and placed into storage after accruing 2.98 x 1019 n/cm2 fluence.

(f) Capsule Y was reinserted into location 61 ° at EOC 17 (approximately 23.4 EFPY).

(g) Capsule Z was withdrawn at approximately 23.4 EFPY (EOC 17) after accruing approximately 5.37 x 1019 n/cm2 fluence. Dosimetry analysis was performed and the test specimens placed into vendor storage for future testing.

(h) This projected fluence is greater than once and less than twice the projected 72 EFPY and 90 EFPY peak vessel fluence.

(i) Capsule Y is installed for fluence monitoring during the operating license in accordance with ASTM E 185-82.

s schedule meets the requirements of ASTM E185-82. The Millstone 3 intermediate shell plate 05-1 is the most limiting surveillance material based upon predicted adjustments of reference perature, RTNDT in accordance with Regulatory Guide 1.99. All materials are predicted to ibit an EOL RTNDT of less than 100F, ASTM E185-82 requires that the program contain a

oved to date satisfy the ASTM E185-82 surveillance capsule withdrawal requirements for a gn life of 54 EFPY. Additional standby capsules remain in the reactor or in the spent fuel

l. The standby capsules are managed to provide surveillance data should subsequent nsions of the plants design life be desired.

1.6.1 Measurement of Integrated Fast Neutron (E 1.0 MeV) Flux at the Irradiation Samples effect a correlation between fast neutron (E 1.0 MeV) exposure and the radiation induced perties changes observed in the test specimens, a number of fast neutron flux monitors are uded as an integral part of the reactor vessel surveillance program. In particular, the eillance capsules contain detectors employing the following reaction.

54 (n,p) Mn-54 58 (n,p) Co-58 63 (n,) Co-60 237 (n,f) Cs-137 38 (n,f) Cs-137 ddition, thermal neutron flux monitors, in the form of bare and Cd shielded Co-Al wire, are uded within the capsules to enable an assessment of the effects of isotopic burnup on the onse of the fast neutron detectors.

use of passive neutron sensors such as included in the internal surveillance capsule dosimetry does not yield a direct measure of the energy dependent neutron flux level at the measurement tion. Rather, the activation or fission process is a measure of the integrated effect that the time energy dependent neutron flux has on the target material over the course of the irradiation od. An accurate assessment of the average flux level and, hence, time integrated exposure ence) experienced by the sensors may be developed from the measurements only if the sensor racteristics and the parameters of the irradiation are well known. In particular, the following ables are of interest:

1. The measured specific activity of each sensor

2. The physical characteristics of each sensor

3. The operating history of the reactor

4. The energy response of each sensor

5. The neutron energy spectrum at the sensor location

tor, and to derive key fast neutron exposure parameters from the measured reaction rates are cribed.

1.6.1.1 Determination of Sensor Reaction Rates specific activity of each of the radiometric sensors is determined using established ASTM cedures. Following sample preparation and weighing, the specific activity of each sensor is rmined by means of a lithium drifted germanium, Ge(Li), gamma spectrometer. In the case of surveillance capsule multiple foil sensor sets, these analyses are performed by direct counting ach of the individual wires; or, as in the case of U-238 and Np-237 fission monitors, by direct nting preceded by dissolution and chemical separation of cesium from the sensor.

irradiation history of the reactor over its operating lifetime is obtained from NUREG-0020, censed Operating Reactors Status Summary Report or from other plant records. In particular, rating data are extracted on a monthly basis from reactor start up to the end of the capsule diation period. For the sensor sets utilized in the surveillance capsule irradiations, the half-s of the product isotopes are long enough that a monthly histogram describing reactor ration has proven to be an adequate representation for use in radioactive decay corrections for reactions of interest in the exposure evaluations.

ing the measured specific activities, the operating history of the reactor, and the physical racteristics of the sensors, reaction rates referenced to full power operation are determined m the following equation:

A R = ----------------------------------------------------------------------

Pj - t - t N 0 FY --- --------- C j 1 - e j e d j P ref re:

measured specific activity (dps/gm) reaction rate averaged over the irradiation period and referenced to operation at a core power level of Pref (rps/nucleus)

= number of target element atoms per gram of sensor weight fractions of the target isotope in the sensor material number of product atoms produced per reaction average core power level during irradiation period j (MW)

= maximum or reference core power level of the reactor (MW)

average (E 1.0 MeV) over the entire irradiation period decay constant of the product isotope (sec-1) length of irradiation period j (sec) decay time following irradiation period j (sec) and the summation is carried out over the total number of monthly intervals comprising the total irradiation period.

he above equation, the ratio Pj/Pref accounts for month by month variation of power level hin a given fuel cycle. The ratio Cj is calculated for each fuel cycle and accounts for the change ensor reaction rates caused by variations in flux level due to changes in core power spatial ributions from fuel cycle to fuel cycle. For a single cycle irradiation Cj = 1.0. However, for tiple cycle irradiations, particularly those employing low leakage fuel management the itional Cj correction must be utilized.

1.6.1.2 Corrections to Reaction Rate Data r to using the measured reaction rates in the least squares adjustment procedure discussed in tion 5.3.1.6.1.3, additional corrections are made to the U-238 measurements to account for the ence of U-235 impurities in the sensors as well as to adjust for the build-in of plutonium opes over the course of the irradiation.

ddition to the corrections made for the presence of U-235 in the U-238 fission sensors, ections are also made to both the U-238 and Np-237 sensor reaction rates to account for ma ray induced fission reactions occurring over the course of the irradiation.

1.6.1.3 Least Squares Adjustment Procedure ues of key fast neutron exposure parameters are derived from the measured reaction rates g the FERRET least squares adjustment code (SCHMITTROTH, 1979). The FERRET roach uses the measured reaction rate data, sensor reaction cross-sections, and a trial spectrum nput and proceeds to adjust the group fluxes from the spectrum to produce a best fit (in a least ares sense) to the measured reaction rate data. The best estimate exposure parameters along h the associated uncertainties are then obtained from the best estimate spectrum.

he least squares adjustment, the continuous quantities (i.e., neutron spectra and cross-sections) approximated in a multi-group format consisting of 53 energy groups. The trial spectrum is verted to the FERRET 53 group structure using the SAND-II code (McELROY et. al., 1967).

s procedure is carried out by first expanding the trial spectrum into the SAND-II 620 group cture using a SPLINE interpolation procedure in regions where group boundaries do not cide. The 620 point spectrum is then re-collapsed into the group structure used in FERRET.

sensor set reaction cross-sections, contained within FERRET, are also collapsed into the 53 rgy group structure using the SAND-II code. In this instance, the trial spectrum, as expanded

tion are also constructed from the information contained on the ENDF/B-VI data files. These rices include energy group to energy group uncertainty correlations for each of the individual tions.

to the importance of providing a trial spectrum that exhibits a relative energy distribution e to the actual spectrum at the sensor set locations, the neutron spectrum input to the FERRET luation is obtained from calculations for each dosimetry location (Section 5.3.1.6.2.1).

1.6.2 Calculation of Integrated Fast Neutron (E. 1.0 MeV) Flux at the Irradiation Samples t neutron exposure calculations for the reactor geometry are carried out using both forward adjoint discrete ordinates transport techniques. A single forward calculation provides the tive energy distribution of neutrons for use as input to neutron dosimetry evaluations as well or use in relating measurement results to the actual exposure at key locations in the pressure sel wall. A series of adjoint calculations, on the other hand, establish the means to compute olute exposure rate values using fuel cycle specific core power distributions; thus, providing a ct comparison with all dosimetry results obtained over the operating history of the reactor.

ombination, the absolute cycle specific data from the adjoint evaluations together with relative tron energy spectra distributions from the forward calculation provided the means to:

1. Evaluate neutron dosimetry from surveillance capsule locations.

2. Enable a direct comparison of analytical prediction with measurement.

3. Determine plant specific bias factors to be used in the evaluation of the best estimate exposure of the reactor pressure vessel.

4. Establish a mechanism for projection of pressure vessel exposure as the design of each new fuel cycle evolves.

1.6.2.1 Reference Forward Calculation forward transport calculation for the reactor is carried out in r, geometry using the DORT dimensional discrete ordinates code (Version 3.1) and the BUGLE-96 cross-section library NL). The BUGLE-96 library is a 47 neutron group, ENDF/B-VI based, data set produced cifically for light water reactor applications. In these analyses, anisotropic scattering is treated h a P3 expansion of the scattering cross-sections and the angular discretization is modeled with 8 order of angular quadrature.

spatial core power distribution utilized in the reference forward calculation is derived from istical studies of long-term operation of Westinghouse four loop plants. Inherent in the elopment of this reference core power distribution is the use of an out-in fuel management tegy; i.e., fresh fuel on the core periphery. Furthermore, for the peripheral fuel assemblies, a

to the use of this bounding spatial power distribution, the results from the reference forward ulation establish conservative exposure projections for reactors of this design. Since it is kely that actual reactor operation would result in the implementation of a power distribution at nominal +2 level for a large number of fuel cycles and, further, because of the widespread lementation of low leakage fuel management strategies, the fuel cycle specific calculations for reactor will result in exposure rates well below these conservative predictions.

1.6.2.2 Cycle Specific Adjoint Calculations adjoint analyses are also carried out using an S8 order of angular quadrature and the P3 cross-ion approximation from the BUGLE-96 library. Adjoint source locations are chosen at several azimuths on the pressure vessel inner radius. In addition, adjoint calculations were carried out sources positioned at the geometric center of all surveillance capsules. Again, these ulations are run in r, geometry to provide neutron source distribution importance functions the exposure parameter of interest; in this case, (E 1.0 MeV).

importance functions generated from these individual adjoint analyses provide the basis for bsolute projections and comparison with measurement. These importance functions, when bined with cycle specific neutron source distributions, yield absolute predictions of neutron osure at the locations of interest for each of the operating fuel cycles; and, establish the means erform similar predictions and dosimetry evaluations for all subsequent fuel cycles.

ing the importance functions and appropriate core source distributions, the response of rest can be calculated as:

R 0 0 = r E r E S r E r dr d dE re:

0,0) = Neutron flux (E 1.0 MeV) at radius R0 and azimuthal angle 0

,E) = Adjoint importance function at radius r, azimuthal angle , and neutron source energy E.

,E) =Neutron source strength at core location r, and energy E.

important to note that the cycle specific neutron source distributions, S(r,,E), utilized with adjoint importance functions, I(r,,E), permit the use not only of fuel cycle specific spatial ations of fission rates within the reactor core; but, also allow for the inclusion of the effects of differing neutron yield per fission and the variation in fission spectrum introduced by the d-in of plutonium isotopes as the burnup of individual fuel assemblies increases.

design basis core power distribution used in the transport analysis was derived from istical studies of long-term operation of Westinghouse four-loop plants. Inherent in the elopment of the design basis core power distribution is the use of an out-in fuel management tegy; i.e., fresh fuel on the core periphery. Furthermore, for the peripheral fuel assemblies, a uncertainty derived from the statistical evaluation of plant-to-plant and cycle-to-cycle ations in peripheral power was used. Since it is unlikely that a single reactor would have a er distribution at the nominal + 2 level for a large number of fuel cycles, the use of this gn basis distribution is expected to yield somewhat conservative results. This is especially in cases where low leakage fuel management has been employed. Having the calculated tron flux distributions within the reactor geometry, the exposure of the capsule as well as the factor between the capsule and the vessel may be determined.

1.7 Reactor Vessel Fasteners reactor vessel closure studs, nuts, and washers are designed and fabricated in accordance with requirements of the ASME Code,Section III. The closure studs are fabricated of SA-540, ss 3, Grade B24. The closure stud material meets the fracture toughness requirements of the ME Code,Section III and 10 CFR 50, Appendix G. Compliance with Regulatory Guide 1.65 is ussed in Section 1.8. Nondestructive examinations are performed in accordance with the ME Code,Section III. Fracture toughness data for bolting materials are presented in Table 5.3-lstone Nuclear Power Station refueling procedures require the studs, nuts, and washers to be oved from the reactor vessel closure and be placed in storage racks during preparation for eling. The storage racks are then removed from the refueling cavity and stored in convenient tions on the containment operating deck prior to removal of the reactor vessel closure head refueling cavity flooding. Alternatively, the studs, nuts and washers may be lifted out of the eling cavity with the reactor vessel closure head. Therefore, the reactor vessel closure studs never exposed to the borated refueling cavity water. Additional protection against the sibility of incurring corrosion effects is assured by the use of an initial manganese base sphate surfacing treatment plus the use of an approved lubricant. An alternate surface tment to manganese base phosphate is a vapor phase plating process.

stud holes in the reactor vessel flange are sealed with special plugs before removing the tor vessel closure head thus preventing leakage of the borated refueling water into the stud s.

2 PRESSURE-TEMPERATURE LIMITS 2.1 Limit Curves tup and shutdown operating limitations are based on the properties of the core region erials of the reactor pressure vessel. Actual material property test data is used. The methods ined in Appendix G to Section XI of the ASME Code as modified by ASME Code Case N-

line material will be limiting. The heatup and cooldown curves are given in the Technical cifications. Beltline material properties degrade with radiation exposure, and this degradation easured in terms of the adjusted reference nil-ductility temperature which includes a reference ductility temperature shift (RTNDT).

limiting RTNDT used to establish the pressure/temperature limit curves, is periodically ated to incorporate the effects of irradiation exposure using the methodology described in ulatory Guide 1.99, Revision 2. This methodology calculates the increase in RTNDT based on h materials copper content and nickel content and also based on the neutron fluence to which material is expected to be exposed during the period of applicability of the pressure-perature limit curves. RTNDT values are calculated for the 1/4t and 3/4t locations (i.e., tips of ASME Code reference flaw when the flaw is assumed at the inside diameter and outside meter locations), respectively. For the selected period of operation, this shift is of sufficient nitude so that no unirradiated ferritic materials in other components of the reactor coolant em (RCS) will be limiting in the analysis.

operational curves (P/T limits) have been established for the ferritic materials of the RCS sidering ASME Boiler and Pressure Vessel Code Section XI, Appendix G as modified by ME Code Case N-640, and the additional requirements of 10 CFR 50 Appendix G.

lementation of the specific requirements provide adequate margin to brittle fracture of ferritic erials during normal operation, anticipated operational occurrences, and system leak and rostatic tests. Changes in fracture toughness of the core region plates, weldments, and ciated heat affected zones due to radiation damage will be monitored by the surveillance gram discussed in Section 5.3.1.6.

results of the radiation surveillance program will be used to verify that the RTNDT predicted m the effects of the fluence, copper content, and nickel content, using the methodology cribed in Regulatory Guide 1.99, Revision 2, is appropriate and to make any changes essary to correct the chemistry factors as described in paragraph 2.1 of the Regulatory Guide if NDT determined from the surveillance program is greater than the predicted RTNDT.

perature limits for inservice leak and hydrotests along with core criticality limits are included he Technical Specifications. Note that the core criticality limits provide margins associated h brittle fracture and do not consider core physics.

2.2 End-of-Life RTPTS Projections protect the reactor vessel against pressurized thermal shock events, the NRC promulgated the rule. This rule established end-of-life screening limits based on affects of neutron irradiation age at the reactor vessel surface which would provide acceptable level of risk due to PTS nts. This calculation is performed by predicting the shift in the reference transition perature (RTNDT). The shift in the reference transition temperature (RTNDT) is calculated g the methodology provided by 10 CFR 50.61. The value of RTPTS can be calculated by the owing expression:

s calculation provides an end-of-life value of RTPTS at the vessel clad/base metal interface ed upon the limiting projected surface fluence of 2.70 x 1019 n/cm2 (E 1MeV). Table 5.3-4 vides the results of the calculation for the limiting base and weld material.

2.3 Operating Procedures transient conditions that are considered in the design of the reactor vessel are presented in tion 3.9N.1.1. These transients are representative of the operating conditions that should dently be considered to occur during plant operation. The transients selected form a servative basis for evaluation of the RCS to ensure the integrity of the RCS equipment.

se transients listed as upset condition transients are listed in Table 3.9N-1. None of these sients will result in pressure-temperature changes which exceed the heatup and cooldown tations as described in Section 5.3.2.1 and in the Technical Specifications.

3 REACTOR VESSEL INTEGRITY 3.1 Design reactor vessel is cylindrical with a welded hemispherical bottom head and a removable, ed, flanged, and gasketed, hemispherical upper head (Figure 5.3-2). The rector vessel flange head are sealed by two hollow metallic O-rings. Seal leakage is detected by means of two off connections: one between the inner and outer ring and one outside the outer O-ring. The sel contains the core, core support structures, control rods, and other parts directly associated h the core. The reactor vessel closure head contains head adaptors. These head adaptors are ular members, attached by partial penetration welds to the underside of the closure head. The er end of these adaptors contains acme threads for the assembly of control rod drive hanisms, head adaptor plugs (spares), or instrumentation adaptors. The seal arrangement at upper end of these adaptors consists of a welded flexible canopy seal, except for some space d adaptors with plugs that have mechanical Canopy Seal Clamp Assemblies installed over the ting canopy seal welds to prevent possible leakages. Inlet and outlet nozzles are located metrically around the vessel. Outlet nozzles are arranged on the vessel to facilitate optimum ut of the RCS equipment. The inlet nozzles are tapered from the coolant loop vessel interfaces he vessel inside wall to reduce loop pressure drop.

bottom head of the vessel contains penetration nozzles for connection and entry of the lear incore instrumentation. Each nozzle consists of a tubular member made of Inconel. Each is attached to the inside of the bottom head by a partial penetration weld.

rnal surfaces of the vessel which are in contact with primary coolant are weld overlay with 5 inch minimum of stainless steel or Inconel. The exterior of the reactor vessel closure head is lated with canned stainless steel reflective insulation. The reactor vessel assembly is insulated h canned stainless steel panels of fibrous, powdered and reflective insulation. The insulating

cipal design parameters of the reactor vessel are given in Table 5.3-6.

re are no special design features which would prohibit the in situ annealing of the vessel.

ious modes of heating could be used depending on the desired temperature.

reactor vessel materials surveillance program is adequate to accommodate the annealing of reactor vessel. Sufficient specimens are available to evaluate the effects of the annealing tment.

lic loads are introduced by normal power changes, reactor trip, startup, and shutdown rations. These design base cycles are selected for fatigue evaluation and constitute a servative design envelope for the projected plant life. Vessel analyses result in a usage factor is less than one.

design specifications require analysis to prove that the vessel is in compliance with the gue and stress limits of the ASME Code,Section III. The loadings and transients specified for analysis are based on the most severe conditions expected during service. The maximum tup and cooldown rate consistent with plant operating limits is 100F per hour for normal rating conditions. These rates are reflected in the vessel design specifications.

3.2 Materials of Construction materials in the fabrication of the reactor vessel are discussed in Section 5.2.3.

3.3 Fabrication Methods Millstone Unit 3 reactor vessel manufacturer is Combustion Engineering Incorporated.

mbustion Engineering Incorporated is the largest reactor vessel fabricator in the United States their experience is demonstrated by the fact that they have fabricated over 40 reactor vessels Westinghouse designed NSSS's as well as additional vessels for other reactor vendors.

fabrication methods used in the construction of the reactor vessel are discussed in tion 5.3.1.2.

3.4 Inspection Requirements nondestructive examinations performed on the reactor vessel are described in Section 5.3.1.3.

3.5 Shipment and Installation reactor vessel is shipped in a horizontal position on a shipping sled with a vessel lifting truss mbly. All vessel opening are sealed to prevent the entrance of moisture and an adequate ntity of desiccant bags are placed inside the vessel. These are usually placed in a wire mesh

closure head is also shipped with a shipping cover and skid. An enclosure attached to the tilation shroud support ring protects the control rod mechanism housings. All head openings sealed to prevent the entrance of moisture and an adequate quantity of desiccant bags are ed inside the head. These are placed in a wire mesh basket attached to the head cover. All on steel surfaces are painted with heat resistant paint before shipping. A lifting frame is vided for handling the vessel head.

3.6 Operating Conditions rating limitations are presented in Section 5.3.2 and in the Technical Specifications. The cedures and methods used to ensure the integrity of the reactor vessel under the most severe tulated conditions are described in Section 3.9N.1.4.

ddition to the analysis of primary components discussed in Section 3.9N.1.4, the reactor sel is further qualified to ensure against unstable crack growth under faulted conditions.

uation of emergency core cooling system (ECCS) following a loss-of-coolant or steam line k accident procedures relatively high thermal stresses in regions of the reactor vessel which e into contact with ECCS water. Primary consideration is given to these areas, including the tor vessel beltline region and the reactor vessel primary coolant nozzle, to ensure the integrity he reactor vessel under these severe postulated transients.

principles and procedures of linear elastic fracture mechanics (LEFM) are used to evaluate mal effects in the regions of interest.

LEFM approach to the design against failure is basically a stress intensity consideration in ch criteria are established for fracture instability in the presence of a crack. Consequently, a c assumption employed in LEFM is that a crack or crack-like defect exists in the structure.

essence of the approach is to relate the stress field developed in the vicinity of the crack tip to applied stress on the structure, the material properties, and the size of defect necessary to se failure.

elastic stress field at the crack tip in any cracked body can be described by a single parameter gnated as the stress intensity factor, K. The magnitude of the stress intensity factor K is a ction of the geometry of the body containing the crack, the size and location of the crack, and magnitude and distribution of the stress.

criterion for failure in the presence of a crack is that failure will occur whenever the stress nsity factor exceeds some critical value. For the opening mode of loading (stresses pendicular to the major plane of the crack) the stress intensity factor is designated as KI and critical stress intensity factor is designated KIC. Commonly called the fracture toughness, KIC n inherent material property which is a function of temperature and strain rate. Any

ss intensity factor greater than or equal to KIC for the material will result in crack instability.

criterion of the applicability of LEFM is based on plasticity considerations at the postulated k tip. Strict applicability (as defined by ASTM) of LEFM to large structures where plane in conditions prevail requires that the plastic zone developed at the tip of the crack does not eed 2.25 percent of the crack depth. However, LEFM has been successfully used to provide servative brittle fracture prevention evaluations, even in cases where strict applicability of the ry is not permitted due to excessive plasticity. Recently, experimental results from Heavy tion Steel Technology Program intermediate pressure vessel tests have shown that LEFM can pplied conservatively as long as the pressure component of the stress does not exceed the d strength of the material. The addition of the thermal stresses, calculated elastically, which lts in total stresses in excess of the yield strength does not affect the conservatism of the lts, provided that these thermal stresses are included in the evaluation of the stress intensity ors. Therefore, for faulted condition analyses, LEFM is considered applicable for the luation of the vessel inlet nozzle and beltline region.

ddition, it has been well established that the crack propagation of existing flaws in a structure jected to cyclic loading can be defined in terms of fracture mechanics parameters. Thus, the ciples of LEFM are also applicable to fatigue growth of a postulated flaw at the vessel inlet zle and beltline region.

example of a faulted condition evaluation carried out according to the procedure discussed ve is given in WCAP-8099, 1973). This report discusses the evaluation procedure in detail as lied to a severe faulted condition (a postulated loss-of-coolant accident) and concludes that the grity of the reactor coolant pressure boundary would be maintained in the event of such an dent.

3.7 Inservice Surveillance internal surface of the reactor vessel is capable of inspection periodically using visual and/or destructive techniques over the accessible areas. During refueling, the vessel cladding is able of being inspected in certain areas between the closure flange and the primary coolant t nozzles, and, if deemed necessary, the core barrel is capable of being removed, making the re inside vessel surface accessible.

closure head is examined visually per the applicable ASME Edition and Addenda of Section Rules for Inservice Inspection of Nuclear Components. Optical devices permit a selective ection of the cladding, control rod drive mechanism nozzles, and the gasket seating surface.

knuckle transition piece, which is the area of highest stress of the closure head, is accessible he outer surface for visual inspection, dye penetrant or magnetic particle, and ultrasonic ing. The closure studs can be inspected periodically using visual, magnetic particle, and/or asonic techniques.

ondestructive inspection.

1. Vessel shell - from the inside surface

2. Primary coolant nozzles - from the inside surface

3. Closure head - from the inside and outside surfaces Bottom head - from the outside surface

4. Field welds between the reactor vessel nozzles and the main coolant piping design considerations which have been incorporated into the system design to permit the ve inspection are as follows:

1. All reactor internals are completely removable. The tools and storage space required to permit these inspections are provided.

2. The closure head is stored dry on the vessel head storage stand during refueling to facilitate direct visual inspection.

3. All reactor vessel studs, nuts and washers can be removed to dry storage during refueling.

4. Removable plugs are provided in the primary shield. Insulation around the nozzles may be removed for inspection requirements.

reactor vessel presents access problems because of the radiation levels and remote erwater accessibility to this component. Because of these limitations on access to the reactor sel, several steps have been incorporated into the design and manufacturing procedures in paration for the periodic nondestructive tests which are required by the ASME inservice ection code. These are:

1. Shop ultrasonic examinations are performed on all internally clad surfaces to an acceptance and repair standard to assure an adequate cladding bond to allow later ultrasonic testing of the base metal from the inside surface. The size of cladding bonding defect allowed is 0.25 inch by 0.75 inch with the greater direction parallel to the weld in the region bounded by 2 T (T = wall thickness) on both sides of each full penetration pressure boundary weld. Unbounded areas exceeding 0.442 square inch (0.75 inch diameter) in all other regions are rejected.

2. The design of the reactor vessel shell is a clean, uncluttered cylindrical surface to permit future positioning of the test equipment without obstruction.

4. During fabrication, all full penetration ferritic pressure boundary welds are ultrasonically examined in addition to ASME Code,Section III, requirements.

5. After the shop hydrostatic testing, all full penetration ferritic pressure boundary welds are ultrasonically examined in addition to ASME Code,Section III, requirements.

vessel design and construction enables inspection in accordance with the ASME Code, tion XI.

4 REFERENCES FOR SECTION 5.3 1 WCAP-8099 1973, Buchalet, C. and Mager, T. R., A Summary Analysis of the April 30 Incident at the San Onofre Nuclear Generating Station Unit 1, Westinghouse Corp.,

Pittsburgh, Penn.

2 Soltesz, R. G. et al., 1970, Nuclear Rocket Shielding Methods, Modification, Updating, and Input Data Preparation, Volume 5 - Two- Dimensional Discrete Ordinates Technique.

WANL-PR-(LL)-034.

3 Schmittroth, E.A., FERRETT Data Analysis Code, HEDL-TME-79-40, Hanford Engineering Development Laboratory, Richland, Washington, September 1979.

4 McElroy, W. N., et. al., A Computer-Automated Iterative Method of Neutron Flux Spectra Determined by Foil Activation, AFWL-TR-67-41, Volumes I-IV, Air Force Weapons Laboratory, Kirkland AFB, NM, July 1967.

5 ORNL RSCI Data Library Collection DLC-76, SAILOR Coupled Self-Shielded, 47 Neutron, 20 Gamma-Ray, P3, Cross Section Library for Light Water Reactors.

6 RSICC Compute Code Collection CCC-650, DOORS 3.1, One, Two, and Three-Dimensional Discrete Ordinates Neutron/Photon Transport Code System, August 1996.

7 RSIC Data Library Collection DLC-185, BUGLE-96, Coupled 47 Neutron, 20 Gamma-Ray Group Cross Section Library Derived from ENDF/B-VI for LWR Shielding and Pressure Vessel Dosimetry Applications, March 1996.

RT* UT** PT*** MT****

rgings Flanges yes yes Studs and nuts yes yes Head adapter flanges yes yes Head adapter tubes yes yes Instrumentation tubes yes yes Main nozzles yes yes Nozzle safe ends yes yes tes yes yes ldments Main seam yes yes yes Control rod drive head adapter connection yes Instrumentation tube connection yes Main nozzle yes yes yes Cladding yes yes Nozzle safe ends yes yes yes Head adapter forging to head adapter tube yes yes All ferritic welds accessible after hydrotest yes yes All non-ferritic welds accessible after yes yes hydrotest Seal ledge yes Head lift lugs yes Core pad welds yes Vessel Support Weld Buildup yes yes*****

TES:

RT = Radiographic UT = Ultrasonic PT = Dye penetrant

• MT = Magnetic particle

• • = Required inspection; progressive MT or Final UT

Avg. Upper Sh NMWD MM Component Code No. Grade Cu (%) N (%) T (F) RT (F) (ft-lb) (ft-Closure Head Dome B9812-1 A533B, CL. 1 0.08 -40 0 96.0 -

Closure Head Torus B9813-1 A533B, CL. 1 0.11 -40 10 107.5 -

Closure Head Flange B9803-1 A508, CL. 2 --- 30 30 121.0 -

Vessel Flange B9801-1 A508, CL. 2 0.11 -40 -40 116.5 -

Inlet Nozzle B9806-3 A508, CL.2 0.09 10 10 162.0 -

Inlet Nozzle B9806-4 A508, CL. 2 0.09 0 0 158.0 -

Inlet Nozzle R5-3 A508, CL. 2 0.07 -10 -10 130.0 -

Inlet Nozzle R5-4 A508, CL. 2 0.08 0 0 136.0 -

Outlet Nozzle R6-1 A508, CL. 2 --- -40 -40 128.0 -

Outlet Nozzle R6-2 A508, CL. 2 --- -30 -30 127.0 -

Outlet Nozzle B9807-1 A508, CL. 2 --- -30 -30 121.0 -

Outlet Nozzle B9807-2 A508, CL. 2 --- -30 -30 126.0 -

Nozzle Shell B9804-1 A533B, CL. 1 0.05 -40 40 85.5 -

Nozzle Shell B9804-2 A533B, CL. 1 0.08 -40 40 104.5 -

Nozzle Shell B9804-3 A533B, CL. 1 0.05 -50 0 103.5 -

Inter, Shell B9805-1 A533B, CL. 1 0.05 0.64 -40 60 113.3 8 Inter, Shell B9805-2 A533B, CL. 1 0.05 0.64 -60 6.2 90.0 7 Inter, Shell B9805-3 A533B, CL. 1 0.05 0.65 -40 -3.3 106.3 13

Avg. Upper Sh NMWD MM Component Code No. Grade Cu (%) N (%) T (F) RT (F) (ft-lb) (ft-Lower Shell B9820-1 A533B, CL. 1 0.08 0.63 -50 7.0 76.7 12 Lower Shell B9820-2 A533B, CL. 1 0.07 0.60 -30 38.8 75.7 11 Lower Shell B9820-3 A533B, CL. 1 0.06 0.61 -30 18.6 79.3 12 Bottom Head Torus B9816-1 A533B, CL. 1 0.13 -50 -40 91.5 -

Bottom Head Dome B9817-1 A533B, CL. 1 0.15 -30 -30 161.0 -

NOTES:

NMWD = normal to major working direction MWD = major working direction

COMPOSITION (WT PERCENT)

Weld Plate Plate Plate Plate Plate Plate Control Element B9805-1 B9805-2 B9805-3 B9820-1 B9820-2 B9820-3 4P6052 0.23 0.23 0.22 0.22 0.24 0.21 0.14 1.32 1.32 1.39 1.37 1.42 1.38 1.25 0.010 0.014 0.009 0.006 0.008 0.007 0.011 0.010 0.012 0.010 0.019 0.018 0.023 0.009 0.21 0.22 0.22 0.22 0.24 0.22 0.12 0.64 0.62 0.65 0.63 0.60 0.61 0.05 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.57 0.59 0.58 0.60 0.60 0.57 0.48 0.05 0.05 0.05 0.08 0.07 0.06 0.05

< 0.01 < 0.01 < 0.01 < 0.01 < 0.01 < 0.01 ---

ND ND ND ND ND ND ---

< 0.01 < 0.01 < 0.01 < 0.01 < 0.01 < 0.01 ---

0.005 0.006 0.007 0.006 0.005 0.004 ---

0.003 0.005 0.005 0.003 0.002 0.001 ---

0.012 0.013 0.012 0.011 0.011 0.011 ---

0.007 0.006 0.010 0.008 0.009 0.008 ---

0.024 0.024 0.025 0.020 0.032 0.033 ---

0.006 0.006 0.004 0.003 0.005 0.005 0.004

< 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 ---

< 0.01 < 0.01 < 0.01 < 0.01 < 0.01 < 0.01 ---

< 0.001 < 0.001 < 0.001 < 0.001 < 0.001 < 0.001 ---

= not detected TE:

licable for all beltline region weld seams.

Chemical Content Initial Margin at Location Wt. % Cu Wt. % Ni RTNDT 54 EFPY se Plate (B9805-1) 0.05 0.63 60 34 ld 0.05 0.05 -50 40.23 Surface ART 19 2 F = Fluence (E 1 MeV)10 n/cm at Expiration Date at Location 54 EFPY 54 EFPY se Plate (B9805-1) 2.70 133 ld 2.70 30

sign/operating pressure (psig) 2485/2317 sign temperature (F) 650 erall height of vessel and closure head, bottom head outside diameter to 43-10 of control rod mechanism adapter (foot-inch) ickness of canned stainless steel insulation 3 flective and fibrous insulation (inch) Powdered insulation (inch) 1 mber of reactor closure head studs 54 ameter of reactor closure head/studs, minimum shank (inch) 6-13/16 ide diameter of flange (inch) 167 tside diameter at flange (inch) 205 ide diameter at shell (inch) 173 et nozzle inside diameter (inch) 27.5 tlet nozzle inside diameter (inch) 29 ad thickness, minimum (inch) 1/8 wer head thickness, minimum (inch) 5-3/8 ssel beltline thickness, minimum (inch) 8.5 osure head thickness (inch) 7

MATERIAL FOR THE REACTOR VESSEL

1 REACTOR COOLANT PUMPS 1.1 Pump Flywheel Integrity integrity of the reactor coolant pump flywheel is assured on the basis of the following design quality assurance procedures.

1.1.1 Design Bases calculated stresses at operating speed are based on stresses due to centrifugal forces. The ss resulting from the interference fit of the flywheel on the shaft is less than 2,000 psi at zero ed, but this stress becomes zero at approximately 600 rpm because of radial expansion of the

. The reactor coolant pumps run at approximately 1,190 rpm and may operate briefly at rspeeds up to 109 percent (1,295 rpm) during loss of off site electrical power. For servatism, however, 125 percent of operating speed was selected as the design speed of the tor coolant pumps. The flywheels are given a preoperational test of 125 percent of the imum synchronous speed of the motor.

1.1.2 Fabrication and Inspection flywheel consists of two thick plates bolted together. The flywheel material is produced by a cess that minimizes flaws in the material and improves its fracture toughness properties (i.e.,

lectric furnace with vacuum degassing). Each plate is fabricated from SA-533, Grade B, Class eel. Supplier certification reports are available for all plates and demonstrate the acceptability he flywheel material on the basis of the requirements of NRC Regulatory Guide 1.14.

wheel blanks are flame-cut from the SA-533, Grade B, Class 1 plates, with at least 0.5 inch of k left on the outer surface and bore surface for machining to final dimensions. The finished hined bores, keyways, and drilled holes are subjected to magnetic particle or liquid penetrant minations in accordance with the requirements of Section III of the ASME Code. The finished heels, as well as the flywheel material (rolled plate), are subjected to 100 percent volumetric asonic inspection using procedures and acceptance standards specified in Section III of the ME Code.

reactor coolant pump motors are designed such that, by removing the cover to provide access y removing the flywheel from the pump motor shaft, the flywheel is available to allow an rvice inspection program. For a description of inservice inspection of the flywheels, refer to MP3 ISI Program.

1.1.3 Material Acceptance Criteria reactor coolant pump motor flywheel conforms to the following material acceptance criteria:

at 20°F in accordance with ASTM E-208. The above drop weight tests demonstrate that the NDTT of the flywheel material is no higher than 10F.

2. A minimum of three Charpy V-notch (C) impact specimens from each plate shall be tested at ambient (70F) temperature in accordance with the specification ASME SA-370. The Charpy V-notch (C) energy in both the parallel and normal orientation with respect to the final rolling direction of the flywheel plate material is at least 50 foot pounds and 35 mils lateral expansion at 70F and, therefore, the flywheel material has a reference nil-ductility temperature (RT) of 10F. An evaluation of flywheel overspeed has been performed which concludes that flywheel integrity will be maintained (WCAP-8163, 1973).

s, it is concluded that flywheel plate materials are suitable for use and can meet Regulatory de 1.14 acceptance criteria on the basis of suppliers certification data. The degree of pliance with Regulatory Guide 1.14 is further discussed in Section 1.8.

1.2 Reactor Coolant Pump Assembly 1.2.1 Design Bases reactor coolant pump assembly ensures an adequate core cooling flow rate for sufficient heat sfer to maintain a departure from nucleate boiling ratio (DNBR) greater than 1.30 within the meters of operation. The required net positive suction head is, by conservative pump design, ays less than that available by system design and operation.

ficient pump assembly rotational inertia is provided by a motor flywheel, motor rotor, and p rotating parts which provide adequate flow during coastdown conditions. This forced flow owing an assumed loss of off site electrical power and the subsequent natural circulation effect vides the core with adequate cooling. The reactor coolant pump motor is tested, without hanical damage, at overspeeds up to and including 125 percent of normal speed. The integrity he flywheel during a loss-of-coolant accident (LOCA) has been demonstrated and is ergoing generic review by the NRC (WCAP-8163, 1973).

reactor coolant pump is shown on Figure 5.4-1. The reactor coolant pump design parameters given in Table 5.4-1.

e and material requirements are provided in Section 5.2.

1.2.2 Pump Assembly Description ign Description reactor coolant pump is a vertical, single-stage, controlled leakage, centrifugal pump gned to pump large volumes of reactor coolant at high temperatures and pressures.

1. The hydraulic section consists of the casing, impeller, turning vane-diffuser, and diffuser adapter.

2. The seal section consists of three identical mechanical face-type sealing stages in series, assembled as a single piece cartridge. The seal system provides a pressure breakdown from the reactor coolant system (RCS) pressure to ambient conditions.

3. The motor section consists of a drip proof, squirrel cage, induction motor with a vertical solid shaft, an oil-lubricated double-acting Kingsbury type thrust bearing, upper and lower oil lubricated radial guide bearings, and a flywheel.

itional components of the pump are the shaft, pump radial bearing, thermal barrier heat hanger assembly, coupling, spool piece, and motor stand.

cription of Operation reactor coolant enters the suction nozzle, is pumped by the impeller through the diffuser, and s through the discharge nozzle. The diffuser adapter limits the leakage of reactor coolant back he suction.

l injection flow, under slightly higher pressure than the reactor coolant, enters the pump ugh a connection on the thermal barrier flange and is directed into the plenum between the mal barrier housing and the shaft. The flow splits with the major portion flowing down the t through the radial bearing and into the reactor coolant system. The remaining seal injection passes up the shaft through the seals.

mponent cooling water (Section 9.2.2.1) is provided to the thermal barrier heat exchanger.

ing normal operation, the thermal barrier limits the heat transfer from hot reactor coolant to radial bearing and to the seals. In addition, if a loss of seal injection flow should occur, the mal barrier heat exchanger cools the reactor coolant to an acceptable level before it enters the ring and seal area.

reactor coolant pump motor oil lubricated bearings are of conventional design. The radial rings are the segmented pad type, and the thrust bearing is a double-acting Kingsbury type.

mponent cooling water is supplied to the external upper bearing oil cooler and to the integral er bearing oil cooler. Each RCP motor is equipped with an oil collection system to mitigate the sequences of oil leaks. Section 9.5.11 describes this system in detail.

motor is a drip-proof, squirrel-cage, induction motor with Class B thermalastic epoxy lation, and fitted with external water/air coolers. The rotor and stator are of standard struction and are cooled by air. Six resistance temperature detectors are embedded in the stator dings to sense stator temperature. A flywheel and an anti-reverse rotation device are located at top of the motor.

hasis on the stator end turns. It is then routed to the external water/air heat exchangers, which supplied with chilled water (Section 9.2.2.2). Each motor has two such coolers, mounted metrically opposed to each other. Coolers are sized to maintain optimum motor operating perature. The air is finally exhausted to the containment environment.

h of the reactor coolant pump assemblies is equipped for continuous monitoring of reactor lant pump shaft and frame vibration levels. Shaft vibration is measured by two relative motion t probes mounted on top of the pump seal housing; the probes are located 90 degrees apart in same horizontal plane and mounted near the pump shaft. Frame vibration is measured by two city seismoprobes located 90 degrees apart in the same horizontal plane and mounted at the of the motor support stand. Proximeters and converters linearize the probe output which is layed on monitor meters in the control room. The monitor meters automatically indicate the hest output from the relative probes and seismoprobes; manual selection allows monitoring of vidual probes. Indicator lights display caution and danger limits of vibration.

spool piece, a removable shaft segment, is located between the motor coupling flange and the p coupling flange. The spool piece allows removal of the pump seals with the motor in place.

pump internals, motor, and motor stand can be removed from the casing without disturbing reactor coolant piping. The flywheel is available for inspection by removing the cover.

parts of the pump in contact with the reactor coolant are austenitic stainless steel except for s, bearings, and special parts.

1.3 Design Evaluation 1.3.1 Pump Performance reactor coolant pumps are sized to deliver flow at rates which equal or exceed the required rates. Initial RCS tests confirm the total delivery capability. Thus, assurance of adequate ed circulation coolant flow is provided prior to initial plant operation.

estimated performance characteristics are shown on Figure 5.4-2. The knee, at roximately 25 percent design flow, introduces no operational restrictions, since the pumps y operate at a speed which corresponds to full flow.

reactor trip system ensures that pump operation is within the assumptions used for

-of-coolant flow analyses, which also assures that adequate core cooling is provided to permit rderly reduction in power if flow from a reactor coolant pump is lost during operation.

or parameters influencing the seal environment which can effect seal life include axial and al shaft motions, radial shaft vibrations, temperature, pressure, oxidizing water chemistry, the ence of particulates, and pump start/stop cycles. The sealing system has demonstrated ugh design, testing, and field operation to be capable of withstanding all specified operating ditions.

s. A secondary seal O-ring is used to isolate stage pressures and provides a sliding secondary between the stationary ring and the balance sleeve. This arrangement eliminates the uirement for a flat surface to support the stationary ring. The stationary face subassembly is unted to the pressure breakdown device with springs. By flexibly mounting the stationary face assembly, the stationary face can accommodate axial and radial displacement of the rotating subassembly with minimum disruption to the lubricating film. In addition, the backing ngs provide the seal closure force when sealing pressure is low and aid the hydraulic force nce when sealing pressure is low. The optimized deflection control of the seal design results epeatable and predictable behavior with greater operating margin to tolerate transients.

ing normal operation, each seal stage will be subjected to a differential pressure of roximately one-third of reactor coolant system (RCS) pressure. Each of the three individual ing stages is designed to withstand full RCS pressure indefinitely with the RCP idle, and for a ted period of time with the pump running at a nominal speed of 1200 rpm, to allow for a trolled shutdown.

seal is designed to operate with a thin fluid film gap. As a result, design allowances must be e for short-term contact of the seal face ring materials, particularly during low pressure pump ts. Therefore, the stationary seal face ring material is resin-impregnated graphite. The rotating ring materials are silicon carbide or tungsten carbide and are used in the seal because of their d fracture resistance and thermal conductivity along with favorable tribologic properties.

gsten carbide has good conductive properties to resist self-induced-electro-corrosion in low ductivity service conditions. All of the elastomers performing static sealing functions in the cartridge are ethylene propylene.

normal operating mode of the sealing system, with one-third of RCS pressure across each e is created by tubular seal staging flow coils. The coil is part of a subassembly designated the sure breakdown device (PBD). There is a separate staging coil for each sealing stage, located he pressure retaining housing for that stage. Thus, each coil acts as an orifice to reduce the sure available at each seal stage, resulting in equal pressure distribution amongst the stages ess there is significant leakage through one or more of the seal stages). A second function of flow, aside from developing seal system pressure distribution, is to provide cooling flow ugh the sealing system to carry away frictional heat generated by the rotating seal parts.

ntaining stable seal temperatures is important to limit thermal gradients during transient ditions. The existing cooling systems - thermal barrier and injection - have been maintained hout change for the RCP.

effect of loss of off site power on the pump itself is to cause a temporary stoppage in the ply of injection flow to the pump seals and also of the component cooling water for seal and ring cooling. The emergency generators are started automatically due to loss of off site trical power so that component cooling flow and seal injection flow are automatically ored.

important to reactor protection that the reactor coolant continues to flow for a short time after tor trip. In order to provide this flow following loss of outside electrical power, each reactor lant pump is provided with a flywheel. Thus, the rotating inertia of the pump, motor, and heel is employed during the coastdown period to continue the reactor coolant flow. The stdown flow transients are provided on the figures in Section 15.3. The pump/motor system is gned for the Safe Shutdown Earthquake (SSE) at the site. Hence, it is concluded that the stdown capability of the pumps is maintained even under the most adverse case of loss of off electrical power coincident with the SSE. Core flow transients and figures are provided in tion 15.3.1.

1.3.3 Bearing Integrity design requirements for the reactor coolant pump bearings are primarily aimed at ensuring a g life with negligible wear, so as to give accurate alignment and smooth operation over long ods of time. The surface bearing stresses are held at very low values, and even under the most ere seismic transients do not begin to approach loads which cannot be adequately carried for rt periods of time.

ause there are no established criteria for short time, stress related failures in such bearings, it ot possible to make a meaningful quantification of such parameters as margins to failure, ty factors, etc. A qualitative analysis of the bearing design, embodying such considerations, s assurance of the adequacy of the bearing to operate without failure.

lube oil levels in the motor lube oil sumps signal an alarm in the control room. Each motor ring containing embedded temperature detectors, and so initiation of failure is monitored as a h bearing temperature on the control room computer. Upon control room receipt of a low level m, bearing temperature is monitored and once the manufacturers recommended maximum perature is reached, the reactor is tripped followed by RCP trip. If bearing temperature cations are ignored, and the bearing proceeded to failure, the low melting point of Babbitt al on the pad surfaces ensures that sudden seizure of the shaft will not occur. In this event, the or continues to operate, as it has sufficient reserve capacity to drive the pump under such ditions. However, the high torque required to drive the pump will require high current which lead to the motor being shutdown by the electrical protection systems.

1.3.4 Locked Rotor ay be hypothesized that the pump impeller might severely rub on a stationary member and seize. Analysis has shown that under such conditions, assuming instantaneous seizure of the eller, the pump shaft fails in torsion just below the coupling to the motor, disengaging the heel and motor from the shaft. This constitutes a loss of coolant flow in the loop. Following h a postulated seizure, the motor continues to run without any overspeed, and the flywheel ntains its integrity, as it is still supported on a shaft with two bearings. Flow transients are vided in Section 15.3.3 for the assumed locked rotor.

aring of the anti rotation pin in the seal ring. The motor has adequate power to continue pump ration even after the above occurrences.

cations of pump malfunction in these conditions are initially given by high temperature als from the bearing water temperature detector, and by excessive CVC seal return (CBO) cations, respectively.

1.3.5 Critical Speed reactor coolant pump shaft is designed so that its operating speed is below its first critical ed. This shaft design, even under the most severe postulated transient, gives low values of al stress.

1.3.6 Missile Generation cautionary measures taken to preclude missile formation from reactor coolant pump ponents assure that the pumps do not produce missiles under any anticipated accident dition. Appropriate components of the reactor coolant pump have been analyzed for missile eration. Any fragments of the motor rotor would be contained by the heavy stator frame. The e conclusion applies to the pump impeller because the small fragments that might be ejected ld be contained by the heavy casing. Further discussion and analysis of missile generation are tained in WCAP-8163.

1.3.7 Pump Cavitation minimum net positive suction head required by the reactor coolant pump at best estimate is approximately a 300 foot head (approximately 133 psi). In order for the controlled leakage to operate correctly, it is necessary to require a minimum differential pressure of roximately 200 psi across the seal. This corresponds to a primary loop pressure at which the imum net positive suction head is exceeded and no limitation on pump operation occurs from source.

1.3.8 Pump Overspeed Considerations turbine trips actuated by either the reactor trip system or the turbine protection system, the erator and reactor coolant pumps remain connected to the external network for 30 seconds to vent any pump overspeed condition.

electrical fault requiring immediate trip of the generator (with resulting turbine trip) could lt in an overspeed condition. However, the turbine control system and the turbine intercept es limit the overspeed to less than 120 percent. As additional backup, the turbine protection em has a mechanical overspeed protection trip, usually set at about 110 percent (of turbine ed). In case a generator trip deenergizes the pump buses, the reactor coolant pump motors will ransferred to off site power within 6 to 10 cycles. Overspeed of the pump, due to a discharge

harge side so that both the electrical leads and the connection box are protected by the motor m a jet impingement of the reactor coolant. This protection is required for 5 seconds so the or can prevent overspeed due to the described condition. Further discussion of pump rspeed considerations is contained in WCAP-8163.

1.3.9 Anti-Reverse Rotation Device h of the reactor coolant pumps is provided with an anti-reverse rotation device in the motor.

s anti-reverse mechanism consists of pawls mounted on the outside diameter of the flywheel, a ated ratchet plate mounted on the motor frame, a spring return for the ratchet plate, and two ck absorbers.

n approximate forward speed of 70 rpm, the pawls drop and bounce across the ratchet plate; he motor continues to slow, the pawls drag across the ratchet plate. After the motor has slowed come to a stop, the dropped pawls engage the ratchet plate and, as the motor tends to rotate in opposite direction, the ratchet plate also rotates until it is stopped by the shock absorbers. The r remains in this position until the motor is energized again. When the motor is started, the het plate is returned to its original position by the spring return.

he motor begins to rotate, the pawls drag over the ratchet plate. When the motor reaches icient speed, the pawls are bounced into an elevated position and are held in that position by tion resulting from centrifugal forces acting upon the pawls. While the motor is running at ed, there is no contact between the pawls and ratchet plate.

siderable plant experience with the design of the anti-reverse rotation device has shown high ability of operation.

1.3.10 Shaft Seal Leakage kage along the reactor coolant pump shaft is controlled by three identical mechanical face-sealing stages in series assembled as a single cartridge assembly, such that reactor coolant age to the containment is minimized.

ce leakage flow through a given seal stage is in parallel with the staging coil for that stage, ctively by-passing the coil, cavity pressures in the seal can change with variations in seal age. The pressure differential across the leaking seal stage will decrease while the two

-leaking seals equally share an increase in pressure differential (of equal magnitude to the loss ressure differential across the leaking seal stage).

1.3.11 Seal Discharge Piping seal reduces the leakoff pressure to that of the volume control tank. Seal return water from h pump seal is piped to a common manifold, through the seal water return filter, and through seal water heat exchanger where the temperature is reduced to that of the volume control tank.

1.4 Tests and Inspections reactor coolant pumps can be inspected in accordance with the ASME Code,Section XI, for rvice inspection of nuclear reactor coolant systems.

pump casing is cast in one piece, thus eliminating the inservice inspection of welds in the ng. Support feet are cast integral with the casing to eliminate a weld region.

design enables disassembly and removal of the pump internals for visual access to the rnal surface of the pump casing.

reactor coolant pump quality assurance program is given in Table 5.4-2.

2 STEAM GENERATORS nuclear steam supply system (NSSS) uses four Model F steam generators as shown on ure 5.4-3. Analysis of conditions that might compromise the reactor coolant boundary are ressed in this section.

2.1 Steam Generator Materials 2.1.1 Selection and Fabrication of Materials pressure boundary materials used in the steam generator are selected and fabricated in ordance with the requirements of Section III of the ASME Code. A general discussion of erials specifications is given in Section 5.2.3, with types of materials listed in Tables 5.2-2 5.2-3. Fabrication of reactor coolant pressure boundary materials is also discussed in tion 5.2.3, particularly in Sections 5.2.3.3 and 5.2.3.4.

ting has justified the selection of corrosion resistant Inconel 600, a nickel-chromium-iron alloy ME SB-163), for the steam generator tubes. The channel head divider plate is Inconel (ASME 168). The interior surfaces of the reactor coolant channel head, nozzles, and manways are clad h austenitic stainless steel.

primary side of the tube sheet is weld clad with Inconel (ASME SFA-5.14). The tubes are seal welded to the tube sheet cladding. These fusion welds, performed in compliance with tions III and IX of the ASME Code, are dye penetrant inspected and leak proof tested before h tube is hydraulically expanded the full depth of the tube sheet bore.

e cases used in material selection are discussed in Section 5.2.1. The extent of conformance h Regulatory Guides 1.84, Design and Fabrication Code Case Acceptability ASME Section Division 1, and 1.85 Materials Code Case Acceptability ASME Section III Division 1, is ussed in Section 1.8.

, Quality Assurance Requirements for Cleaning of Fluid Systems and Associated mponents of Water-Cooled Nuclear Power Plants, and ANSI Standard N45.2.1-1973, Cleaning luid Systems and Associated Components for Nuclear Power Plants. On site cleaning and nliness control standards are described in the Quality Assurance Program Description Topical ort. Cleaning process specifications are discussed in Section 5.2.3.4.

fracture toughness of the materials is discussed in Section 5.2.3.3. Adequate fracture ghness of ferritic materials in the reactor coolant pressure boundary is provided by compliance h 10 CFR Part 50, Appendix G, Fracture Toughness Requirements, and Paragraph NB-2300 of tion III of the ASME Code.

2.1.2 Steam Generator Design Effects on Material eral features have been introduced into the Model F steam generator to minimize the osition of contaminants from the secondary side flow. Such deposits could otherwise produce cal environment in which adverse conditions could develop and result in material attack. The port plates are made of corrosion resistant stainless steel 405 alloy and incorporate a four-lobe design (quatrefoil) that provides greater flow area adjacent to the tube outer surface and inates the need for interstitial flow holes. The resulting increase in flow provides higher eping velocities at the tube/tube support plate intersections. Figure 5.4-4 illustrates the trefoil broached holes. This modification in the support plate design is a major factor tributing to the increased circulation ratio. The increased circulation results in increased flow he interior of the bundle, as well as increased horizontal velocity across the tube sheet reducing tendency for sludge deposition. The effect of the increased circulation on the vibrational ility of the tube bundle has been analyzed with consideration given to flow induced excitation uencies. The unsupported span length of tubing in the U-bend region and the corresponding mum number of anti-vibration bars has been determined. The anti-vibration bars are icated from square Inconel barstock, which is then chrome plated to improve frictional racteristics. Also, due to the increased circulation ratio, the moisture separating equipment has n modified to maintain an adequate margin with respect to the moisture carryover. To provide ed strength as well as resistance to vibration, the quatrefoil tube support plate thickness has n increased. In addition, 12 peripheral supports also provide stability to the plates so that tube ting or wear due to flow induced plate vibrations at the tube support contact regions is imized.

urance against significant flow induced tube vibration has been obtained by a combination of lysis and testing.

mbining both vortex shedding and turbulence effects in a conservative manner, the maximum dicted local tube wear depth of a 60 year operating design objective is less than 0.008 inch.

s value is considerably below the plugging limit for a Model F steam generator tube.

mentioned in Section 5.4.2.1.1, corrosion tests which subjected the steam generator tubing erial, Inconel 600 (ASME SB-163), to simulated steam generator water chemistry have cated that the loss due to general corrosion over the 60 year operating design objective is gnificant compared to the tube wall thickness. Testing to investigate the susceptibility of this erial to stress corrosion in caustic and chloride aqueous solutions has indicated the Inconel has excellent resistance to general and pitting type corrosion in severe operating water ditions. Many reactor years of successful operation have shown the same low general osion rates as indicated by the laboratory tests.

rating experience has revealed areas on secondary surfaces and in crevice regions where lized corrosion rates were significantly greater than the low general corrosion rates.

rgranular attack intergranular stress corrosion cracking and tube wall thinning were erienced in localized areas, although not at the same location or under the same environmental ditions (water chemistry, temperature and sludge composition).

secondary side water chemistry program as described in Section 10.3.5 minimizes the sibility for developing localized corrosion and essentially eliminates the secondary side tube l thinning phenomenon. Successful all volatile treatment AVT operation requires ntenance of low concentrations of impurities in the steam generator bulk water, thus reducing potential for formation of highly concentrated solutions in localized areas, which is the ursor of corrosion. By restriction of the total alkalinity in the steam generator and prohibition xtended operation with free alkalinity, the AVT program should minimize the possibility for rrence of intergranular corrosion in localized areas due to excessive levels of free caustic.

oratory testing has shown that the Inconel 600 tubing is compatible with the AVT ironment. Isothermal corrosion testing in high purity water has shown that commercially duced Inconel 600 exhibiting normal microstructures tested at normal engineering stress levels s not suffer intergranular stress corrosion cracking in extended exposure to high temperature er. These tests also showed that no general type of corrosion occurred. A series of autoclave s in reference secondary water with planned excursions have produced no corrosion attached r 1,938 days of testing on any as produced, Inconel 600 tube samples.

cessful secondary side water chemistry controls combined with a comprehensive steam erator inservice inspection program as described in Section 5.4.2.2, assure that the steam erators will provide reliable service. The inspection program will also facilitate detection of unanticipated steam generator tube degradation.

eased margin against primary and secondary side stress corrosion cracking has been obtained he use of thermally treated Inconel 600 tubing. Thermal treatment of Inconel tubes has been wn to be particularly effective in resisting caustic cracking. Tubing used in the Model F is mally treated in accordance with a laboratory derived treatment process. In addition, the low s of tubes were thermally stress relieved prior to installation. This further reduces the potential stress corrosion cracking in the small radius U-bends.

nless steel was to occur, due to concentration of contaminants, the volume of the corrosion ducts is essentially equivalent to the volume of the parent material consumed. This would be ected to preclude denting. The support plates are also designed with quatrefoil tube holes er than cylindrical holes. The quatrefoil tube hole design promotes high velocity flow along tube and should sweep impurities away from the support plate location.

itional measures are incorporated in the Model F design to prevent areas of dryout in the m generator and accumulations of sludge in low velocity areas. Modifications to the wrapper e increased water velocities across the tube sheet. A flow distribution baffle is provided which es the low flow area to the center of the bundle. Increased capacity blowdown pipes have been ed to enable continuous blowdown of the steam generators at a high volume. The intakes of e blowdown pipes are located below the center cut out section of the flow distribution baffle he low velocity region where sludge may be expected to accumulate. Continuous blowdown uld provide protection against inleakage of impurities from the condenser.

2.1.4 Cleanup of Secondary Side Materials eral methods are employed to clean operating steam generators of corrosion causing ondary side deposits. Sludge lancing, a procedure in which a hydraulic jet inserted through an ess opening (handhole) loosens deposits which are removed by means of a suction pump, can erformed when the need is indicated by the results of steam generator tube inspection. Six ch access ports are provided for sludge lancing and inspection. Three of these are located ve the tube sheet and three above the flow distribution baffle. Continuous blowdown is ormed to regulate water chemistry. The location of the blowdown piping suction, adjacent to tube sheet and in a region of relatively low flow velocity, facilitates the removal of particulate urities to minimize the accumulation on the tube sheet.

2.2 Steam Generator Inservice Inspection steam generator is designed to permit inspection of ASME Code Class 1 and 2 parts, uding individual tubes. The design includes a number of openings to provide access to both primary and secondary sides of the steam generator. The specified inspection program plies with the edition of the ASME Code, Division 1,Section XI required by 10 CFR 50.55a, ctive January 5, 1977. The openings include four manways, two for access to both chambers he reactor coolant channel head inlet and outlet sides and two in the steam drum for inspection maintenance of the moisture separators; six, 6 inch handholes, three located just above the sheet secondary surface and three located just above the flow distribution baffle; and two, inch inspection ports located on the tube lane diameter between the upper tube support plate the Row 1 U-bend. Additional access to the tube U-bend is provided through each of the three k plates. For proper functioning of the steam generator, some of the deck plate openings are ered with welded, but removable, hatch plates. Inspection/access to the primary sides is vided by two, 16 inch manways located in the channel head.

cerning the inspection of tubes, which cover inspection equipment, baseline inspections, tube ction, sampling and frequency of inspection, methods of recording, and required actions based indings. Regulatory Guide 1.121, Basis for Plugging Degraded PWR Steam Generator Tubes, vides recommendations concerning the tube plugging. Agreement with Regulatory Guides 3 and 1.121 is discussed in Section 1.8. The minimum requirements for inservice inspection of m generators, including tube plugging criteria, are established as part of the Technical cifications. The inservice inspection program for the reactor coolant boundary is discussed in tion 5.2.4.

2.3 Design Basis am generator design data are given in Table 5.4-3. Code classifications for the steam generator ponents are given in Section 3.2. Although the ASME classification for the secondary side is cified to be Class 2, the current philosophy is to design all pressure retaining parts of the steam erator, and thus both the primary and secondary pressure boundaries, to satisfy the criteria cified in Section III of the ASME Code for Class 1 components. The design stress limits, sient conditions, and combined loading conditions applicable to the steam generator are ussed in Section 3.9N.1. Estimates of radioactivity levels anticipated in the secondary side of steam generators during normal operation and the bases for the estimates are given in pter 11. The accident analysis of a steam generator tube rupture is discussed in Chapter 15.

esign objective of the internal moisture separator equipment is that moisture carryover should exceed 0.25 percent by weight under the following conditions:

1. Steady state operating up to 100 percent of full load steam flow with water at the normal operation level

2. Loading or unloading at a rate of 5 percent of full power steam flow per minute in the range of 15 to 100 percent of full load steam flow

3. A step load change of 10 percent of full power in the range of 15 to 100 percent full load steam flow water chemistry on the reactor side, selected to provide the necessary boron content for tivity control, should minimize corrosion of RCS surfaces. The effectiveness of the water mistry of the steam side in affecting corrosion control is discussed in Chapter 10.

mpatibility of steam generator tubing with both primary and secondary coolants is discussed her in Section 5.4.2.1.3.

steam generator is designed to minimize unacceptable damage from mechanical or flow uced vibration. Tube support adequacy is discussed in the Design Evaluation Section. The es and tube sheet are analyzed and confirmed to withstand the maximum accident loading ditions as they are defined in Section 3.9N.1. Further consideration is given in the Design luation Section to the effect of tube wall thinning on accident condition stresses.

steam generator is a Model F, vertical shell and U-tube evaporator, with integral moisture arating equipment. Figure 5.4-3 shows the model, indicating several of its improved design ures described in the following paragraphs.

the primary side, the reactor coolant flows through the inverted U-tubes, entering and leaving ugh nozzles located in the hemispherical bottom head of the steam generator. The head is ded into inlet and outlet chambers by a vertical divider plate extending from the apex of the d to the tube sheet.

am is generated on the shell side, flows upward, and exits through the outlet nozzle at the top he vessel. Feedwater enters the steam generator at an elevation above the top of the U-tubes, ugh a feedwater nozzle. The water is distributed circumferentially around the steam generator means of a feedwater ring and then flows through an annulus between the tube wrapper and

l. The feedwater enters the ring via a welded thermal sleeve connection and leaves through erted J tubes located at the flow holes at the top of the ring. The J tubes are arranged to ribute the bulk of the colder feedwater to the hot leg side of the tube bundle. The feed ring is gned to minimize conditions which can result in water hammer occurrences in the feedwater ng. At the bottom of the wrapper, the water is directed toward the center of the tube bundle by ow distribution baffle. This baffle arrangement serves to minimize the tendency in the tively low velocity fluid for sludge deposition. Flow blocking devices discourage the water m flowing up the bypass lane as it enters the tube bundle, where it is converted to a steam-er mixture. Subsequently, the steam-water mixture from the tube bundle rises into the steam m section, where 16 individual centrifugal moisture separators remove most of the entrained er from the steam. The steam continues to the secondary separators for further moisture oval, increasing its quality to a designed minimum of 99.75 percent. The moisture separators troduce the separated water, which is combined with entering feedwater to flow back down annulus between the wrapper and shell for recirculation through the steam generator. The dry m exits from the steam generator through the outlet nozzle which is provided with a steam restrictor (Section 5.4.4).

2.5 Design Evaluation ced Convection effective heat transfer coefficient is determined by the physical characteristics of the Model F m generator and the fluid conditions in the primary and secondary systems for the nominal percent design case. It includes a conservative allowance for fouling and uncertainty. A gned heat transfer area is provided to permit the achievability of the full design heat removal ural Circulation Flow driving head created by the change in coolant density as it is heated in the core and rises to outlet nozzle initiates convection circulation. This circulation is enhanced by the fact that the

tdown in the unlikely event of loss of forced circulation.

chanical and Flow-Induced Vibration Under Normal Operation Conditions he design of the steam generators, the possibility of degradation of tubes due to either hanical or flow-induced excitation is thoroughly evaluated. This evaluation includes detailed lysis of the tube support systems, as well as an extensive research program with tube vibration del tests.

valuating degradation due to vibration, consideration is given to sources of excitation, such as e generated by primary fluid flowing within the tubes, mechanically induced vibration, and ondary fluid flow on the outside of the tubes. During normal operation, the effects of primary d flow within the tubes and mechanically induced vibration are considered to be negligible should cause little concern. Thus, the primary source of tube vibrations is the hydrodynamic itation by the secondary fluid on the outside of the tubes. In general, three vibration hanisms have been identified:

1. Vortex shedding

2. Fluidelastic excitation

3. Turbulence tex shedding does not provide detectable tube bundle vibration. There are several reasons why happens:

1. Flow turbulence in the downcomer and tube bundle inlet region inhibit the formation of Von Karmans vortex train.

2. The spatial variations of cross-flow velocities along the tube precludes vortex shedding at a single frequency.

3. Both axial and cross-flow velocity components exist on the tubes. The axial flow component disrupts the Von Karman vortices.

delastic excitation was observed during the testing. The amplitudes of the vibrations were ller than those of the turbulent flow induced vibrations. Therefore, fluidelastic excitation is luded from consideration as a factor in steam generator tube bundle vibrations.

w-induced vibrations due to flow turbulence cause stresses in the tubes that are more than two ers of magnitude below the endurance limit (30,000 psi) of the tube material. Therefore, the tribution to fatigue is negligible, and fatigue degradation from flow-induced vibration is not cipated.

rawn are that the primary source of tube vibration is fluid turbulence and the magnitude of the ation is so small that when combined with its total random nature, its contribution to tube gue is negligible. Therefore, fatigue degradation due to flow induced vibration is not cipated.

owable Tube Wall Thinning Under Accident Conditions evaluation has been performed to determine the extent of tube wall thinning that can be rated under accident conditions. The worst case loading conditions are assumed to be imposed n uniformly thinned tubes, at the most critical location in the steam generator. Under such a tulated design basis accident, vibration is of short enough duration that there is no endurance blem to be considered. The steam generator tubes, existing originally at their minimum wall kness and reduced by a conservative general corrosion and erosion loss, can be shown to vide an adequate safety margin (i.e., sufficient wall thickness, in addition to the minimum uired for a maximum stress less than the allowable stress limit, as it is defined by the ASME e).

results of a study made on D series (0.75 inch nominal diameter, 0.043 inch nominal wall kness) tubes under accident loadings are discussed in WCAP-7832 (1973). These results onstrate that a minimum wall thickness of 0.026 inch would have a maximum faulted dition stress (i.e., due to combined LOCA and safe shutdown earthquake loads) that is less the allowable limit. This thickness is 0.010 inch less than the minimum D series tube wall kness of 0.039 inch, which is reduced to 0.036 inch by the assumed general corrosion and ion rate. Thus, an adequate safety margin is exhibited. The corrosion rate is based on a servative weight loss rate for Inconel tubing in flowing 650F primary side reactor coolant

d. The weight loss, when equated to a thinning rate and projected over a 60 year design ective with appropriate reduction after initial hours, is equivalent to 0.083 mil thinning. The med corrosion rate of 3 mils leaves a conservative 2.917 mils for general corrosion thinning he secondary side.

Model F steam generator was analyzed using similar assumptions of general corrosion and ion rates. The overall similarity between previous tubes studied and the Model F tubes makes asonable to expect the same general results, that is, to conclude that the ability of the Model F m generator tubes to withstand accident loadings is not impaired by a lifetime of general osion losses. This is confirmed by specific analysis.

2.6 Quality Assurance steam generator nondestructive examination program is given in Table 5.4-4.

iographic inspection and acceptance standards are in accordance with the requirements of tion III of the ASME Code.

dments, and weld deposit cladding. Liquid penetrant inspection and acceptance standards are ccordance with the requirements of Section III of the ASME Code.

gnetic particle inspection is performed on the tube sheet forging, channel head casting, nozzle ings, and the following weldments:

1. Nozzle to shell

2. Support brackets

3. Instrument connection (secondary)

4. Temporary attachments for removal

5. All accessible pressure retaining welds after hydrostatic test gnetic particle inspection and acceptance standards are in accordance with the requirements of tion III of the ASME Code.

asonic tests are performed on the tube sheet forgings, tube sheet cladding, secondary shell and d plates, and nozzle forgings. Inspection and acceptance standards are in accordance with the uirements of Section III of the ASME Code.

heat transfer tubing is subjected to eddy current testing and ultrasonic examination.

ection and acceptance standards are in accordance with the requirements of Section III of the ME Code. Hydrostatic tests are performed in accordance with Section III of the ASME Code.

ddition, the heat transfer tubes are subjected to a hydrostatic test pressure not less than 1.25 es the primary side design pressure prior to installation into the vessel.

3 REACTOR COOLANT PIPING 3.1 Design Bases reactor coolant system (RCS) piping is designed and fabricated to accommodate the system sures and temperature attained under all expected modes of plant operation or anticipated em interactions. Stresses are maintained within the limits of Section III of the ASME Nuclear er Plant Components Code. Section 5.2 provides code and material requirements.

erials of construction are specified to minimize corrosion/erosion and ensure compatibility h the operating environment.

piping in the RCS is Safety Class 1 and is designed and fabricated in accordance with ASME tion III, Class 1 requirements.

nless steel pipe outside of the scope of ANSI B36.19 conforms to ANSI B36.10.

minimum wall thickness of the loop pipe and fittings are not less than that calculated using ASME III Class 1 formula of Paragraph NB-3641.1(3) with an allowable stress value of 50 psi. The pipe wall thickness for both bypass and pressurizer surge lines is Schedule 160.

minimum pipe bend radius is 5 nominal pipe diameters; ovality does not exceed 8 percent.

butt welds, branch connection nozzle welds, and boss welds are of a full penetration design.

tion 5.2.3 discusses processing and minimization of sensitization.

nges conform to ANSI B16.5.

ket weld fittings and socket joints conform to ASNI B16.11.

tion 5.2.4 discusses inservice inspection.

3.2 Design Description le 5.4-5 gives principal design data for the reactor cooling piping.

e and fittings are cast, forged, or seamless without longitudinal or electroslag welds, and ply with the requirements of the ASME Code,Section II, Parts A and C,Section III, and tion IX.

RCS piping is specified in the smallest sizes consistent with system requirements. This gn philosophy results in the reactor inlet and outlet piping diameters given in Table 5.4-5.

line between the steam generator and the pump suction is larger to reduce pressure drop and rove flow conditions to the pump suction.

reactor coolant piping and fittings which make up the loops are austenitic stainless steel.

re is no electroslag welding on these components. All smaller piping which comprise part of RCS such as the pressurizer surge line, spray and relief line, loop drains and connecting lines ther systems are also austenitic stainless steel. The nitrogen supply line for the pressurizer ef tank is carbon steel. All joints and connections are welded, except for the pressurizer relief the pressurizer code safety valves, where flanged joints are used. Thermal sleeves are alled in the crossover leg at the 2 inch chemical volume and control system (CHS) charging connection with each reactor coolant loop. The other thermal sleeves are on the pressurizer re the surge line connects and where the spray line connects to the pressurizer. Thermal ves are used where thermal stresses could develop due to rapid changes in fluid temperature ng normal operational transients.

1. Residual heat removal pump suction lines, which are 45 degrees down from the horizontal centerline. This enables the water level in the RCS to be lowered in the reactor coolant pipe while continuing to operate the residual heat removal system, should this be required for maintenance.

2. Loop drain lines and the connection for temporary level measurement of water in the RCS during refueling and maintenance operation.

3. The differential pressure taps for flow measurement, which are downstream of the steam generators on the first 90 degree elbow.

4. The hot leg sample connections and the cold leg high pressure safety injection, chemical and volume control charging, pressurizer spray, reactor plant gaseous drains and instrumentation connections, which are located on the horizontal centerline.

etrations into the coolant flow path are limited to the following:

1. The spray line inlet connections extend into the cold leg piping in the form of a scoop so that the velocity head of the reactor coolant loop flow adds to the spray driving force.

2. The reactor coolant sample system taps protrude into the main stream to obtain a representative sample of the reactor coolant.

3. The hot and cold narrow range, fast response resistance temperature detectors (RTDs) are located in thermowells that extend into the reactor coolant pipe.

4. The wide range hot and cold RTDs are located in thermowells that extend into hot and cold legs of the reactor coolant piping.

RCS piping includes those sections of piping interconnecting the reactor vessel, steam erator, and reactor coolant pump. It also includes the following:

1. Charging line and alternate charging line from the system isolation valve up to the branch connections on the reactor coolant loop.

2. Letdown line and excess letdown line from the branch connections on the reactor coolant loop to the system isolation valve.

3. Pressurizer spray lines from the reactor coolant cold legs to the spray nozzle on the pressurizer vessel.

5. Safety injection lines from the designated check valve to the reactor coolant loops.

6. Accumulator lines from the designated check valve to the reactor coolant loops.

7. Loop fill, loop drain, sample, and instrument lines to or from the designated isolation valve to or from the reactor coolant loops.

NOTE: Lines with a 3/8 inch flow restricting orifice qualify as Safety Class 2; in the event of a break in one of these Safety Class 2 lines, the normal makeup system is capable of providing makeup flow while maintaining pressurizer water level. In the case of the pressurizer steam space a 0.25 inch orifice was installed to provide a class break. ETE-MP-2021-1041 documents the acceptability (Use-As-Is disposition) of the small bore Class 2 piping, tubing, flex hoses, and valves associated with the pressurizer for which a restricting orifice was not provided.

These components are identified on P&ID 25212-26902, Sheet 3, (EM-102C).

8. Pressurizer surge line from one reactor coolant loop hot leg to the pressurizer vessel inlet nozzle.

9. Pressurizer spray, sample connection with scoop, reactor coolant temperature RTD thermowell installation boss, and the thermowell itself (see Note under Item 7).

10. All branch connection nozzles attached to reactor coolant loops.

11. Pressure relief lines from nozzles on top of the pressurizer vessel up to and through the power operated pressurizer relief valves and pressurizer safety valves.

12. Auxiliary spray line from the isolation valve to the pressurizer spray line header.

13. Sample lines from pressurizer to the isolation valve (see Note under Item 7).

14. Loop stop valve bypass lines.

15. Reactor vessel head vent piping from the reactor vessel head to the pressurizer relief tank (Section 5.4.15).

tion 5.2 discusses details of the materials of construction and codes used in the fabrication of tor coolant piping and fittings.

3.3 Design Evaluation tion 3.9 discusses piping load and stress evaluation for normal operating loads, blowdown s, and combined normal, blowdown and seismic loads.

water chemistry is selected to minimize corrosion.

odic analysis of the coolant chemical composition is performed to verify that the reactor lant quality meets the specifications.

design and construction are in compliance with ASME Section XI. Pursuant to this, all sure containing welds out to the second valve that delineates the RCS boundary are available examination with removal insulation.

mponents constructed with stainless steel operate satisfactorily under normal plant chemistry ditions in pressurized water reactor systems, because chlorides, fluorides, and particularly gen, are controlled to very low levels. (Section 5.2.3) odic analysis of the coolant chemical composition is performed to monitor the adherence of system to desired reactor coolant water quality listed in Table 5.2-4. Maintenance of the water lity to minimize corrosion is accomplished using the chemical and volume control system and pling system which are described in Chapter 9.

3.3.2 Sensitized Stainless Steel tion 5.2.3 discusses sensitized stainless steel.

3.3.3 Contaminant Control tamination of stainless steel and Inconel by copper, low melting temperature alloys, mercury lead is prohibited.

r to application of thermal insulation, the austenitic stainless steel surfaces are cleaned and lyzed in accordance with Regulatory Guide 1.37 as described in Section 1.8.

3.4 Tests and Inspections le 5.4-6 gives the RCS piping NDE program.

umetric examination is performed throughout 100 percent of the wall volume of each pipe and ng in accordance with the applicable requirements of Section III of the ASME Code for all 27.5 inches and larger. All unacceptable defects are eliminated in accordance with the uirements of the same section of the code.

quid penetrant examination is performed on both the entire outside and inside surfaces of each shed fitting in accordance with the criteria of ASME Section III. Acceptance standards are in ordance with the applicable requirements of ASME Section III.

. The S6 requirement applies to 100 percent of the piping wall volume. The material is mined in accordance with ASME Code,Section III and ASME Section II, SA 655, 1977 ion. The end of pipe sections, branch ends and fittings are machined back to provide a smooth d transition adjacent to the weld path.

4 MAIN STEAM LINE FLOW RESTRICTOR 4.1 Design Basis outlet nozzle of the steam generator contains a flow restrictor designed to limit steam flow in unlikely event of a break in the main steam line. With a restrictor, a large increase in steam creates a backpressure which limits further increase in flow. Several protective advantages thereby provided: rapid rise in containment pressure is prevented, the rate of heat removal m the reactor coolant is maintained within acceptable limits, thrust forces on the main steam piping are reduced, and stresses on internal steam generator components, particularly the tube et and tubes, are maintained within acceptable limits. Another design objective is to minimize erhammer type loads and unrecovered pressure loss across the restrictor during normal ration.

4.2 Design Description flow restrictor consists of seven Inconel (ASME SB-163) venturi inserts which are inserted the holes in an integral steam outlet low alloy steel forging. The inserts are arranged with one turi at the centerline of the outlet nozzle and the other six equally spaced around it. After rtion into the low allow steel forging holes, the Inconel venturi nozzles are welded to the onel cladding on the inner surface of the forging.

4.3 Design Evaluation flow restrictor design has been sufficiently analyzed to assure its structural adequacy. The ivalent throat diameter of the steam generator outlet is 16 inches, and the resultant pressure p through the restrictor at 100 percent steam flow is approximately 3.1 psi. This is based on a gn flow rate of 4.07 x 106 lb/hr. Materials of construction and manufacturing of the flow rictor are in accordance with Section III of the ASME Code.

4.4 Tests and Inspections ce the restrictor is not a part of the steam system pressure boundary, no tests and inspection ond those conducted during fabrication are performed.

5 MAIN STEAM ISOLATION SYSTEM main steam isolation system is described in Sections 6.2.4 and 10.3.

s section is not applicable to the Millstone 3 reactor core, as it applies to a boiling water tor core design and Millstone 3 has a pressurized water reactor.

7 RESIDUAL HEAT REMOVAL SYSTEM residual heat removal system (RHS) transfers heat from the reactor coolant system (RCS) to component cooling system (CCP) to reduce the temperature of the reactor coolant to the cold tdown temperature at a controlled rate during the second part of normal plant cooldown or a ty grade cold shutdown (SGCS) and maintains this temperature until the plant is started up in. The RHS may be aligned to the RCS for cooldown operation once RHS entry conditions achieved (RCS temperature and pressure reduced to at or below 350F and 375 psig, ectively).

s of the RHS also serve as parts of the emergency core cooling system (ECCS) during the ction phase of a loss-of-coolant accident (Section 6.3).

RHS may be used to transfer refueling water between the refueling cavity and the refueling er storage tank at the beginning and end of the refueling operations.

ief valves in the RHS pump suction lines from the RCS provide low temperature overpressure ection for the reactor vessel when the RHS is unisolated from the RCS (Section 5.2.2.11).

lear plants employing the same RHS design as the Millstone 3 Steam Electric Station are n in Section 1.3.

7.1 Design Bases S design parameters are listed in Table 5.4-7.

RHS is designed to operate in conjunction with other plant systems to reduce the temperature he RCS during the second phase of plant cooldown.

RHS is capable of being placed in operation approximately four hours after reactor shutdown n the temperature and pressure of the RCS are approximately 350F and 375 psig, ectively. Assuming that two heat exchangers and two pumps are in service and that each heat hanger is supplied with component cooling water at design flow and temperature, the RHS is gned to reduce the temperature of the reactor coolant from 350F to 200F within 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />.

wever, during normal cooldown only one RHS heat exchanger and pump are used for cooling l the reactor coolant temperature is reduced to 260F. This limitation is imposed based on the hnical Specifications requirement of 1 RHS train being operable in Mode 4 to mitigate a CA event and the issue raised by the Westinghouse Owners Group that flashing in the RHS ion line would occur due to the elevated temperature of the water trapped in the suction line in junction with the rapid depressurization upon RHS pump start. Consequently, one RHS train ains aligned to the RWST for use as an injection path to the RCS until the RCS temperature

ling the reactor coolant from 350F to 200F within 41.25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> with one reactor coolant p operating and within 72.25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> with 2 reactor coolant pumps operating. The heat load by RHS during the cooldown transient includes residual and decay heat from the core and reactor lant pump heat.

RHS is also designed to operate in conjunction with the other systems of the cold shutdown gn to achieve and maintain cold shutdown using only safety grade systems, as required by nch Technical Position RSB 5-1. See Safety Grade Cold Shutdown (one and/or two RHS ns(s) in service), Section 5.4.7.2.3.5.

RHS is designed to be isolated from the RCS whenever the RCS pressure exceeds the RHS gn pressure. The RHS is isolated from the RCS on the suction side by three normally closed, or-operated valves in series on each suction line. Two of the motor-operated valves are rlocked to prevent its opening if RCS pressure is greater than 412.5 psia and alarm in the trol room if RCS pressure exceeds 440 psig and the valve is open. If the plant is in Mode 1, 2,

, the operator is required to close all three suction valves. If the plant is in mode 4, 5, or 6 and RCS pressure increases to 750 psig, the operator is required to close the motor-operated valve est to the pump. (These interlocks are discussed in detail in Sections 5.4.7.2.4 and 7.6.2.) The d motor-operated valve is closed and deenergized at the motor control center (MCC). The or-operated valve closest to the pump suction is closed and deenergized at the MCC.

RHS is isolated from the RCS on the discharge side by three check valves in each return line.

o provided on the discharge side is a normally open motor-operated valve downstream of each S heat exchanger.

h inlet line to the RHS is equipped with a pressure relief valve sized to relieve the flow of one rging pump at the relief valve set pressure. These relief valves are provided to protect the RHS em (and the reactor pressure vessel when the RHS is unisolated from the RCS) from vertent overpressurization during plant cooldown or startup.

h discharge line from the RHS to the RCS is equipped with a pressure relief valve designed to eve the maximum possible back leakage through the valves isolating the RHS from the RCS.

RHS is designed for a single nuclear power unit and is not shared among nuclear power units.

RHS is designed to be fully operable from the control room for normal operation except for ning the outermost and inner most pump suction valve in each train. These valves are closed deenergized at the MCC. The MCCs for the innermost valves are located in the ESF building he 36 foot elevation. The MCCs for the outermost valves are located in the auxiliary building he vicinity of the rod drive control center. These MCCs are accessible should RHS operability equired after an accident (FSAR Table 12.3-3). Manual operations required of the operator closing the suction valves to the RWST, opening the suction isolation valves, positioning the control valves downstream of the RHS heat exchangers, and starting the RHS pumps.

nual actions, including those required for safety grade cold shutdown, are also discussed in

he required cooldown time. There are no motor-operated valves in the RHS that are subject to mon mode flooding. Provisions to protect the equipment from flooding are discussed in tion 3.4. For two low probability electrical system single failures, i.e., failure in the suction ation valve interlock circuitry, or emergency generator failure in conjunction with loss of off power, limited operator action outside the control room is required to open the suction ation valves. The spurious operation of a single RHS motor-operated valve can be accepted hout loss of cooling function as a result of the redundant two train design. Missile protection, ection against dynamic effects associated with the postulated rupture of piping, and seismic gn are discussed in Sections 3.5, 3.6, and 3.7, respectively.

7.2 System Design 7.2.1 Schematic Piping and Instrumentation Diagrams RHS, as shown on Figures 5.4-5 and 5.4-6, consists of two residual heat exchangers, two dual heat removal pumps, and the associated piping, valves, and instrumentation necessary for rational control. The suction lines to the RHS are connected to the hot legs of two reactor lant loops, while the return lines are connected to the cold legs of each of the reactor coolant ps.

se return lines are also the ECCS low head injection lines (Figure 6.3-1).

RHS suction lines are isolated from the RCS by three normally- closed motor-operated es in series. The two normally closed isolation valves inside containment in each RHS suction receive power from the same Class 1E source as the RHS pump in that line while the valve ide containment is powered by the opposite train. This arrangement ensures that single failure uirements for RHS accessibility and isolation are met. Each discharge line is isolated from the S by three check valves located inside the containment and by a normally open motor-operated e located outside the containment. (The check valves and the motor-operated valve on each harge line are not part of the RHS; these valves are shown as part of the ECCS; Figure 6.3-1.)

ing RHS operation, reactor coolant flows from the RCS to the residual heat removal pumps, ugh the tube side of the residual heat exchangers, and back to the RCS. The heat is transferred he component cooling water circulating through the shell side of the residual heat exchangers.

ncident with operation of the RHS, a portion of the reactor coolant flow may be diverted from nstream of the residual heat exchangers to the CHS low pressure letdown line for cleanup

/or pressure control. By regulating the diverted flow rate and the charging flow, the RCS sure may be controlled.

ssure regulation is necessary to maintain the pressure range dictated by the fracture prevention eria requirements of the reactor vessel and by the shaft seal differential pressure and net itive suction head requirements of the reactor coolant pumps.

dual heat exchanger and is used to maintain a constant return flow to the RCS. Instrumentation rovided to monitor system pressure, temperature, and total flow.

RHS may be used for filling the refueling cavity before refueling. After refueling operations, er is pumped back to the refueling water storage tank until the water level is brought down to flange of the reactor vessel. The remainder of the water is removed via a drain connection at bottom of the refueling canal.

en the RHS is in operation, the water chemistry is the same as that of the reactor coolant.

vision is made for the process sampling system (Section 9.3.2) to extract samples from the of reactor coolant downstream of the residual heat exchangers. A local sampling point is also vided on each residual heat removal train, between the pump and heat exchanger.

RHS functions in conjunction with the high head portion of the ECCS to provide injection of ated water from the refueling water storage tank into the RCS cold legs during the injection se following a loss-of-coolant accident.

g term recirculation is performed by the containment recirculation system discussed in tions 6.2.2 and 6.3.

use of the RHS as part of the ECCS is more completely described in Section 6.3.

cription of Component Interlocks:

The RHS pumps, in order to perform their ECCS function, are interlocked to start automatically on receipt of a safety injection signal (Section 6.3).

Two of the RHS suction isolation valves in each inlet line from the RCS are separately interlocked to prevent their being opened when RCS pressure is greater than 412.5 psia. In addition, an alarm will annunciate in the control room if RCS pressure exceeds 440 psig and the valve is open. If the plant is in Mode 1, 2, or 3, the operator is required to close all three suction valves. If the plant is in mode 4, 5, or 6 and the RCS pressure increases to 750 psig, the operator is required to close the motor-operated valve closest to the pump.

These interlocks are described in more detail in Sections 5.4.7.2.4 and 7.6.2. It should be noted that these valves can also be controlled from the Auxiliary Shutdown Panel (ASP).

Valve 8701A is not interlocked with RCS pressure low to open to provide one train of RHR cooling when the control room is inaccessible. The innermost and outermost RHS suction isolation valves in each inlet line are closed and deenergized at the MCCs.

The RHS suction isolation valves from the RCS are also interlocked to prevent their being opened unless the isolation valves in the following lines are closed:

1. Recirculation line from the residual heat exchanger outlet to the suction of the high head safety injection pumps

The motor-operated valves in the RHS mini-flow bypass lines are interlocked to open when the residual heat removal pump discharge flow is less than approximately 772 gpm and close when the flow exceeds approximately 1,633 gpm.

The motor-operated isolation valves in the recirculation lines from the residual heat exchanger outlet to the suctions of the high head safety injection pumps are interlocked such that they cannot be opened unless either of the series RHS suction isolation valves from the RCS in the corresponding subsystem is closed. A high CCP temperature interlock will signal the RHS heat exchanger bypass valve to open. This interlock is in effect when the Control Room main board (MB2) Normal-Cooldown switch is in the Cooldown position. See also, FSAR Section 9.2.2.1.5.

7.2.2 Equipment and Component Descriptions materials used to fabricate RHS components are in accordance with the applicable code uirements. All parts of components in contact with borated water are fabricated or clad with enitic stainless steel or equivalent corrosion resistant material. Component parameters are n in Table 5.4-8.

idual Heat Removal Pumps o pumps are installed in the RHS. The pumps are sized to deliver reactor coolant flow through residual heat exchangers to meet the plant cooldown requirements. The use of two separate R trains assures that cooling capacity is only partially lost should one pump become perative.

RHS pumps are protected from overheating and loss of suction flow by mini-flow bypass s that assure flow to the pump suction should the pump suction be isolated or the RCS sure be above the shutoff head of the pump. A valve located in each mini-flow line is ulated by a signal from the flow transmitters located in each pump discharge header. The trol valves open when the RHS pump discharge flow is less than 772 gpm and close when the exceeds approximately 1,633 gpm.

ressure sensor in each pump discharge header provides a signal for an indicator in the control

m. A high pressure alarm is also actuated by the pressure sensor.

two pumps are vertical, centrifugal units with mechanical seals on the shafts. All pump aces in contact with reactor coolant are austenitic stainless steel or equivalent corrosion stant material.

RHS pumps also function as the low head safety injection pumps in the ECCS. (See tion 6.3 for further information and for the RHS pump performance curves.)

o residual heat exchangers are installed in the system. The heat exchanger design is based on t load and temperature differences between reactor coolant and component cooling water ting 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after reactor shutdown when the temperature difference between the two ems is small.

installation of two heat exchangers in separate and independent residual heat removal trains res that the heat removal capacity of the system is only partially lost if one train becomes perative.

residual heat exchangers are of the shell and U-tube type. Reactor coolant circulates through tubes, while component cooling water circulates through the shell. The tubes are welded to the e sheet to prevent leakage of reactor coolant.

residual heat exchangers also function as part of the ECCS (Section 6.3).

idual Heat Removal System Valves ves that perform a modulating function are equipped with two sets of packings and an rmediate leakoff connection that discharges to the drain header.

nual and motor-operated valves have backseats to facilitate repacking and to limit stem age when the valves are open. Motor-operated valves are stopped in the open direction by t switches and therefore must be back seated manually. Leakage connections are provided re required by valve size and fluid conditions.

RHS heat exchanger outlet butterfly valves have been provided with actuator throttle limiters have been set to prevent full opening of the valves in the event of a loss of the (non safety) rument Air. The RHS heat exchanger bypass butterfly valves have been modified to fail open he event of a loss of Instrument Air. Upon loss of air, the outlet valves will fail open to the pre-open position and the bypass valves will fail full open to allow continued cooldown without ersely affecting CCP piping with an RCS temperature as high as 350F.

7.2.3 System Operation 7.2.3.1 Reactor Startup erally, while at cold shutdown condition, decay heat from the reactor core is being removed he RHS. The number of pumps and heat exchangers in service depends upon the heat load at time.

nitiation of the plant startup, the RCS is completely filled, and the pressurizer heaters are rgized. The RHS is operating and is connected to the CHS via the low pressure letdown line to trol reactor coolant pressure. During this time, the RHS acts as an alternate letdown path. The ual valves downstream of the residual heat exchangers leading to the letdown line of the CHS

am bubble formation in the pressurizer is accomplished by increasing the letdown flow above charging flow with the pressurizer heaters energized. The reactor coolant pumps are normally ted to heat up the system after the pressurizer bubble has been formed. When the pressurizer er level reaches the no-load programmed setpoint, pressurizer level control is shifted to the mal operational means. The RHS is then isolated from the RCS and the system pressure is trolled by normal letdown, pressurizer spray, and pressurizer heaters.

7.2.3.2 Power Generation and Hot Standby Operation ing power generation and hot standby operation, the RHS is not in service but is aligned for ration as part of the ECCS.

7.2.3.3 Plant Shutdown nt shutdown is defined as the operation which brings the plant from no-load temperature and sure to a cold shutdown condition (i.e., to a subcritical condition with the reactor coolant perature no greater than 200F).

7.2.3.4 Normal Cold Shutdown initial phase of a normal plant shutdown is accomplished by transferring heat from the RCS he steam and power conversion system. Circulation of the reactor coolant is provided by the tor coolant pumps and heat removal is accomplished by using the steam generators and ping steam to the condenser.

onjunction with this portion of the cooldown, the reactor coolant is borated to the centration required for cold shutdown and depressurized to a pressure permitting RHS ration. Boration and makeup for the contraction of the RCS due to cooling are performed g the charging, letdown, and makeup control portions of the CHS.

depressurization function is performed by initiating pressurizer spray from the discharge of operating reactor coolant pump.

en the reactor coolant temperature and pressure are reduced to at or below 350F and 375 psig, ess than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reactor shutdown, the second phase of cooldown starts with the RHS g placed in operation.

tup of the RHS includes a warmup period during which time reactor coolant flow through the t exchangers is limited to minimize thermal shock. The rate of heat removal from the reactor lant is manually controlled by regulating the coolant flow through the residual heat hangers. By adjusting the control valves downstream of the residual heat exchangers, the ed mean temperature of the return flow is controlled. Coincident with the manual adjustment, h heat exchanger bypass valve is automatically regulated to give the required total flow.

tor coolant temperature decreases, the reactor coolant flow through the residual heat hanger is increased by adjusting the control valve in each heat exchangers tube side outlet difications to the RHS system have been made to preclude overheating of the RHS heat hanger (shell side) cooling water piping (CCP system) in the event of a loss of Instrument Air ng a Normal or safety grade cold shutdown (SGCS) cooldown. The RHS heat exchanger et butterfly valves have been provided with actuator throttle limiters that have been set to vent full opening of the valves in the event of a loss of the (non safety) Instrument Air. The S heat exchanger bypass butterfly valves have been modified to fail open in the event of a loss nstrument Air. Upon loss of air, the outlet valves will fail open to the pre-set open position and bypass valves will fail full open to allow continued cooldown without adversely affecting P piping with an RCS temperature as high as 350F. The changes have no effect on the RHS ction flowpath when RHS is used during the SI phase following a LOCA. See also FSAR tion 6.3.2.2.5.

ing plant shutdown with the RHS in operation, operation with a steam bubble in the surizer is maximized to provide RCS pressure control. The RCS is augmented by regulating charging flow rate and the rate of letdown from the RHS to the CHS.

er the reactor coolant is reduced below a temperature of 160F and the reactor coolant pump is ped, cooling of the pressurizer is continued by providing auxiliary spray from the CHS.

er the reactor coolant pressure is reduced and the temperature is 140F or lower, the RCS may pened for refueling or maintenance.

7.2.3.5 Safety Grade Cold Shutdown ile the plant shutdown basis is hot standby for those events involving a primary or secondary em piping passive failure, it is cold shutdown for those events which are initiated from normal rating conditions. In accordance with the functional requirements of Branch Technical ition RSB 5-1, safety grade cold shutdown is defined as the ability to take the plant from mal operating conditions to cold shutdown, with or without off site power, with the most ting single failure, using only safety related equipment and limited action outside of the trol room, and within a reasonable period of time following shutdown.

uld portions of the normal shutdown systems be unavailable, the operator should maintain the t in a hot standby condition while making the normal systems functional. However, for cases hich the Demineralized Water Storage Tank (DWST) is the exclusive source of demineralized er, the operator should use any of the normal systems available in conjunction with safety de backups for those systems which cannot be made available in order to ensure cold tdown can be achieved without depleting the DWST. The safety grade provisions are to be d only upon the inability to make available the equipment normally used for the given ction.

tdown earthquake (SSE), coincident with a loss of off site power, and the loss of one RHS n due to the loss of one vital bus as the most limiting single failure. Under these circumstances:

1. Circulation of reactor coolant is accomplished by natural circulation until RHS cooling is initiated. (The reactor coolant pumps are assumed to be stopped.)

2. Heat removal is accomplished with the steam generators and water from the DWST via the auxiliary feedwater system, and steaming through the main steam safety or steam generator atmospheric relief bypass valves.

3. Makeup/boration is accomplished with the charging pumps.

4. Letdown is accomplished via the reactor vessel head vent system to the pressurizer relief tank.

5. RCS depressurization is accomplished using the pressurizer power-operated relief valves.

6. Cooldown continues until RHS entry conditions are achieved, at which time one RHS train is placed in service. Cooldown by steaming through the atmospheric relief bypass valves would continue in parallel with RHS cooling (concurrent steaming) only until such time that RHS could independently remove the required decay and sensible heat from the RCS.

afety grade cold shutdown would be implemented in three phases:

1. Boration: Borated water from the boric acid storage system is added to the RCS in order to maintain a constant shutdown margin at lower reactor coolant temperatures. Auxiliary feedwater drawn from the DWST is used to remove decay heat from the RCS and is released as steam through the main steam safety valves.

The plant is maintained at hot standby for a maximum of six hours in order to complete this boration phase. For details on safety grade boration, see Section 9.3.4.2.6.

2. Steam Generator Cooling: Boration is terminated. Auxiliary feedwater drawn from the DWST is used to reduce the RCS temperature to RHS entry conditions and is released as steam through at least two steam generator atmospheric relief bypass valves. The plant is cooled to RHS entry conditions within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> from termination of boration phase.

3. RHS System Cooling: Auxiliary feedwater cooling is terminated once the RHS can cool the plant independently. The RCS temperature is reduced to cold shutdown conditions via the RHS System.

essurized by the safety injection accumulators, the motor-operated accumulator isolation es are closed prior to RCS pressure dropping below the accumulator discharge pressure. Two he accumulator isolation valves are powered from the orange safety train while the other two es are powered from the purple safety train. Additional protection against inadvertent essurization of the RCS by the accumulators is provided by redundant Class 1E solenoid-rated accumulator vent valves which permit venting of the accumulators in the remote event the discharge line should fail to isolate.

RHS is designed to operate in conjunction with the other safety grade systems of the cold tdown design in order to address the functional requirements of SRP Section 5.4.7 and Branch hnical Position RSB 5-1. The SRP requires that plant safety systems have the capacity to bring reactor to conditions permitting the operation of the RHS within a reasonable period of time, ned as 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, assuming a single failure of an active component with only either on site or site power available. The BTP requires that the plant have the capacity to bring the reactor to a shutdown condition, within a reasonable period of time following shutdown, assuming the t limiting failure. Therefore, the SRP, in conjunction with the BTP, require that the plant be able of achieving RHS entry conditions within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> of reactor trip and achieving cold tdown within an unspecified additional reasonable period of time.

Millstone 3 safety grade cold shutdown design enables the nuclear steam supply to be taken m hot standby to cold shutdown conditions using only safety grade systems, with or without site power, and with the most limiting single failure. The safety grade cold shutdown design enables the RCS to be taken from hot standby to conditions that will permit initiation of RHS ration within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, and then to cold shutdown within an additional 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Therefore, Millstone 3 licensing basis is to achieve cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of reactor trip.

Section 14.2.7.9, the Millstone 3 instrument air system is non-safety related; therefore, the ty grade cold shutdown design must be capable of achieving cold shutdown without the use of rument air.

h instrument air available and a single failure, cold shutdown conditions can be achieved hin 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of reactor trip.

h instrument air unavailable and a single failure, limited operator action outside of the control m is required. A loss of instrument air causes the RHS heat exchanger bypass valves to fail n, thus reducing the flow to the RHS heat exchanger. This arrangement reduces the heat oval rate in order to protect the reactor plant component cooling water system from rheating. In order to increase the heat removal rate as the RCS temperature decreases, operator on is required to throttle the operating heat exchanger bypass valve. This limited operator on is justified since it is required only after a single failure and, if initiated 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> after tor trip, will result in cold shutdown conditions within 52 hours6.018519e-4 days <br />0.0144 hours <br />8.597884e-5 weeks <br />1.9786e-5 months <br /> of reactor trip.

ditions within 68.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.

refore, in all cases, a safety grade cold shutdown can be achieved without challenging the ble DWST inventory or overheating the reactor plant component cooling water system, and hin the licensing basis of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

7.2.3.6 Refueling h residual heat removal pumps may be utilized during refueling to pump borated water from refueling water storage tank to the refueling cavity. During this operation, the residual heat oval pumps are stopped, the isolation valves in the inlet lines of the RHS are closed, the ation valves to the refueling water storage tank are opened, and the residual heat removal ps are restarted.

reactor vessel head is lifted slightly. The refueling water is then pumped into the reactor sel through the normal RHS return lines and into the refueling cavity through the open reactor sel. The reactor vessel head is gradually raised as the water level in the refueling cavity eases. After the water level reaches the normal refueling level, the residual heat removal ps are stopped, the inlet isolation valves are opened, the refueling water storage tank supply es are closed, the residual heat removal pumps are restarted, and the residual heat removal is med.

ing refueling, the RHS is maintained in service with the number of pumps and heat hangers in operation as required by the heat load.

owing refueling, either the residual heat removal pumps or the spent fuel purification system ps can be used to drain the refueling cavity. If the residual heat removal pumps are used to n the refueling cavity, the refueling water level is lowered to the top of the reactor vessel ge by pumping water from the RCS to the refueling water storage tank. The vessel head is replaced and the normal RHS flow path reestablished. The remainder of the water is removed m the refueling canal via a drain connection in the bottom of the canal as described in tion 9.1.3.2.

7.2.4 Control h inlet line to the RHS is equipped with a pressure relief valve sized to relieve the flow of one rging pump at the relief valve set pressure. These relief valves also protect the RHS system d the reactor pressure vessel when the RHS is unisolated from the RCS) from inadvertent rpressurization during plant cooldown or startup. Each valve has a relief flow capacity of 560 at a set pressure of 440 psig. An analysis has been conducted to confirm the capability of the S relief valve to prevent overpressurization in the RHS. All credible events were examined for r potential to overpressurize the RHS. These events included normal operating conditions, equent transients, and abnormal occurrences. The analysis confirmed that one relief valve has capability to keep the RHS maximum pressure within code limits.

e has a relief flow capacity of 20 gpm at a set pressure of 600 psig. These relief valves are ted in the low pressure safety injection portion of the ECCS (Figure 5.4-5).

fluid discharged by the suction side relief valves is collected in the pressurizer relief tank.

fluid discharged by the discharge side relief valves is collected in the primary drains transfer (Section 9.3.3).

design of the RHS includes three motor-operated gate isolation valves in series on each inlet between the high pressure RCS and the lower pressure RHS. They are closed during normal ration and are opened only for residual heat removal during a plant cooldown after the RCS sure is reduced to 375 psig or lower and RCS temperature is reduced to approximately 350F.

ing a plant startup, the inlet isolation valves are shut after drawing a bubble in the pressurizer prior to increasing RCS pressure above 425 psig. Two of the three isolation valves in each t line are provided with prevent-open interlocks. It should be noted that when controlling e 8701A from the ASP, the RCS low pressure interlock is not available. This design feature ws one train of RHR cooling when the control room is inaccessible. Although spurious ning of these two isolation valves in series is considered unlikely, the third isolation valve in h inlet train is closed and deenergized at the MCC to prevent overpressure of RHS piping. The ation valves closest to the pump suctions are deenergized at the MCC to prevent a fire induced rious hot short from damaging the valve in the credited train rendering that train non-ctional. The two interlocked valves in each RHS subsystem are separately and independently rlocked with pressure signals to prevent their being opened whenever the RCS pressure is ter than approximately 412.5 psia.

two interlocked valves in each RHS subsystem are also separately and independently alarmed CS pressure signal is 440 psig and the valve is open. If the plant is in Mode 1, 2, or 3, the rator is required to close all three suction valves. If the plant is in mode 4, 5, or 6 and the RCS sure increases to 750 psig, the operator closes the motor-operated valve closest to the pump.

use of two independently powered motor-operated valves in each of the two inlet lines, along h two independent pressure interlock signals for each function, assures a design which meets licable single failure criteria. Not only more than one single failure, but also different failure hanisms must be postulated to defeat the function of preventing possible exposure of the RHS ormal RCS operating pressure. These productive interlock designs, in combination with plant rating procedures, provide diverse means of accomplishing the protective function. For further rmation on the instrumentation and control features refer to Section 7.6.2.

RHS inlet isolation valves are provided with red-green position indicator lights on the main trol board and the auxiliary shutdown panel. The indicator lights for the innermost RHS ion MOV are extinguished when deenergized at the MCC in MODES 1, 2 and 3.

ation of the low pressure RHS from the high pressure RCS is provided on the discharge side normally open motor-operated valve and three check valves in series. These check valves are ted in the ECCS and their testing is described in Section 6.3.4.2.

entire RHS is designed as Nuclear Safety Class 2, except the suction isolation valves inside tainment which are Class 1. Component codes and classifications for the RHS and the other ems relied upon for safety grade cold shutdown are given in Section 3.2.

7.2.6 System Reliability Considerations eral Design Criterion 34 requires that a system to remove residual heat be provided. The ty function of this system is to transfer fission product decay heat and other residual heat from core at a rate sufficient to prevent fuel or pressure boundary design limits from being eeded. Safety grade systems are provided in the plant design to perform this safety function.

safety grade systems which perform this function for all plant conditions, except LOCA, are:

1. The RCS and steam generators, which operate in conjunction with the auxiliary feedwater system;

2. The steam generator safety valves;

3. The steam generator atmospheric relief bypass valves;

4. The residual heat removal system (RHS) which operates in conjunction with the reactor plant component cooling water system;

5. The service water system.

LOCA conditions, the safety grade system which performs the function of removing residual t from the reactor core is the ECCS, which operates in conjunction with the charging pump ling water system, safety injection pump cooling water system and the service water system.

auxiliary feedwater system, along with the steam generator safety valves and steam generator ospheric relief bypass valves, provides a completely separate, independent, and diverse means erforming the safety function of removing residual heat, which is normally performed by the S system when RCS temperature is less than 350F. The auxiliary feedwater system is capable erforming this function for an extended period of time following plant shutdown.

rder to achieve conditions that permit initiation of RHS operation, two other functions ation and depressurization) must be performed. The boration function is normally provided he CHS. Certain initiating HELB events, postulated to occur in the operating CHS pump harge piping, when combined with a single active failure of the standby CHS pump to start, lead to a loss of all charging. In addition, all charging may be lost as a result of certain tulated fire conditions (see FSAR Section 9.5.1 and the FPER for SIH system performance uirements). For these conditions, the SIH pumps will provide the required RCS inventory and ation flow to achieve safe shutdown. When the reactor coolant pumps are not available, due to of off site power or following a manual pump trip, the depressurization function may be

RHS is provided with two residual heat removal pumps, and two residual heat removal heat hangers arranged in two separate, independent flowpaths. To assure reliability, each residual t removal pump is connected to a different emergency bus. Each residual heat removal train is ated from the RCS on the suction side by three motor-operated valves in series. Each motor-rated valve receives power via a separate motor control center, and one of the three valves in es in the same train receives power from a different emergency bus than do the other two es and the pump. Two of the suction isolation valves in each RHS subsystem are also rlocked and alarmed to prevent exposure of the RHS to the normal operating pressure of the S (Section 5.4.7.2.4).

S operation for normal conditions and for major failures is accomplished from the control m with limited operator action outside the control room. The redundancy in the RHS system gn provides the system with the capability to maintain its cooling function even with major le failures, such as failure of an RHS pump, valve, or heat exchanger, since the redundant n can be used for continued heat removal.

uld it be necessary to take the plant to cold shutdown conditions using only safety grade ems, portions of the RCS (Section 5.4.15) and the ECCS (Section 6.3) are also relied upon for ation, letdown, makeup and depressurization. These safety grade provisions would be used y upon failure of the equipment normally used for the given function.

ation is accomplished by using the centrifugal charging pumps to supply borated water from boric acid tanks to the RCS via the charging bypass line or the high head safety injection lines he ECCS. See Section 9.3.4.2 for further details.

down to accommodate boration and any other addition to the RCS inventory is provided by the tor vessel head vent system letdown path to the pressurizer relief tank. See Section 5.4.15.2 further details.

ressurization is accomplished by discharging RCS inventory via the safety grade pressurizer er-operated relief valves. Two parallel lines are provided with solenoid-actuated valves which be remotely operated to relieve to the pressurizer relief tank. The ECCS accumulators are also vided with safety grade isolation and venting capability in order to ensure that ressurization can be completed.

pressurizer relief tank, the vessel head letdown valves, and the pressurizer relief valves are cribed in Sections 5.4.11, 5.4.12, and 5.4.13, respectively, and are shown on Figure 5.1-1.

systems used for boration/inventory control and for depressurization are remotely operable h either on site or off site power available and assuming the most limiting single failure. A ure modes and effects analysis (FMEA) of the portions of the RCS, ECCS, and CHS that are d for safety grade cold shutdown is included in the RHS - Cold Shutdown Operations - FMEA

S operation for normal conditions, even with a major failure is accomplished from the control m with limited operator action outside the control room. The redundancy in the RHS design vides the system with the capability to maintain its cooling function even with a major single ure, such as failure of a residual heat removal pump, valve, or heat exchanger or of an rgency power source, without impact on the redundant trains continued heat removal. The y effect would be an extension of the time required for cooldown. The capability of the RHRS afety grade cooldown is demonstrated in the RHS - Cold Shutdown Operation - FMEA ble 5.4-9).

7.2.7 Manual Actions RHS is designed to be fully operable from the control room for normal operation except for ning the outermost and innermost pump suction valve in each train. The outermost and ermost valves are closed and deenergized at the MCC. The outermost MOVs MCCs are ted in the auxiliary building in the vicinity of the rod drive control center. The innermost Vs MCCs are located in the ESF building on the 36 foot level. The MCCs are accessible uld RHS operability be required after an accident (FSAR Table 12.3-3). Manual operations uired of the operator include: opening the suction and discharge isolation valves, positioning flow control valves downstream of the residual heat exchangers, and starting the residual heat oval pumps. If the plant is in mode 1, 2, or 3, all three of the RHR isolation valves in each path require manual closure upon alarm of valve open and RCS pressure greater than 440

. If the plant is in mode 4, 5, or 6 and the RCS pressure increases to 750 psig, the operator is uired to close the motor-operated valve closest to the pump.

uming the most limiting single failure, the RHS can still be operated with limited operator on required outside of the control room, with the only effect being an extension in the ldown time. Manual operation consists of opening one of the suction/isolation valves, and in event instrument air is not available, throttling the operating heat exchanger bypass valve to ease RHS heat exchanger flow; see Section 5.4.7.2.3.5.

7.3 Performance Evaluation performance of the RHS system in reducing reactor coolant temperature is evaluated through use of heat balance calculations on the RCS and CCP at stepwise intervals following the ation of RHS operation. Heat removal through the RHS and CCP heat exchangers is ulated at each interval by use of standard water-to-water heat exchanger performance elations; the resultant fluid temperatures for the RHS and CCP systems are calculated and d as input to the next intervals heat balance calculation.

umptions utilized in the series of heat balance calculations describing plant RHS cooldown as follows:

1. RHS operation is initiated no earlier than four hours after reactor shutdown.

3. Thermal equilibrium is maintained throughout the RCS during the cooldown.

4. Component cooling water outlet temperature from the RHS heat exchanger is limited to 145F for normal and 145F for a safety grade cold shutdown.

5. One reactor coolant pump is assumed running until the coolant temperature is at 160F for normal two-train cooldown. At this temperature, the reactor coolant pump is stopped. For safety grade cooldown with one or two trains, the reactor coolant pumps are assumed to be stopped.

7.4 Preoperational Testing operational testing of the RHS is addressed in Chapter 14.

8 REACTOR WATER CLEANUP SYSTEM s is a BWR requirement and, as such, does not apply to Millstone 3, which is a PWR plant.

9 MAIN STEAMLINES AND FEEDWATER PIPING n steamlines and feedwater piping are discussed in Sections 10.3 (Main Steam System),

.7 (Condensate and Feedwater Systems), and 10.4.9 (Auxiliary Feedwater System).

10 PRESSURIZER 10.1 Design Bases general configuration of the pressurizer is shown on Figure 5.4-8. The design data of the surizer are given in Table 5.4-10. Codes and material requirements are provided in tion 5.2.

pressurizer provides a point in the RCS where liquid and vapor can be maintained in ilibrium under saturated conditions for pressure and control purposes, for steady state rations and during transients.

10.1.1 Pressurizer Surge Line surge line is sized to minimize the pressure drop between the RCS and the safety valves in er to obtain maximum allowable discharge flow from the safety valves, as necessary.

surge line and the thermal sleeves at each end are designed to withstand the thermal stresses lting from volume surges of relatively hotter or colder water which may occur during ration.

10.1.2 Pressurizer volume of the pressurizer is equal to, or greater than, the minimum volume of steam, water, otal of the two which satisfies all of the following requirements:

1. The combined saturated water volume and steam expansion volume is sufficient to provide the desired response to system volume changes

2. The water volume is sufficient to prevent the heaters from being uncovered during a step load increase of ten percent at full power

3. The steam volume is large enough to accommodate the surge resulting from 50 percent reduction of full load with automatic reactor control and 40 percent steam dump without the water level reaching the high level reactor trip point

4. The steam volume is large enough to prevent water relief through the safety valves following a loss of load with the high water level initiating a reactor trip, without reactor control or steam dump

5. The pressurizer will not empty following reactor trip and turbine trip

6. The emergency core cooling signal is not activated during reactor trip and turbine trip 10.2 Design Description 10.2.1 Pressurizer Surge Line pressurizer surge line connects the pressurizer to one reactor hot leg providing for continuous lant volume pressure adjustments between the RCS and the pressurizer.

10.2.2 Pressurizer pressurizer as shown on Figure 5.4-8 is a vertical, cylindrical vessel with hemispherical top bottom heads constructed of carbon steel, with austenitic stainless steel cladding on all rnal surfaces exposed to the reactor coolant. A stainless steel liner or tube may be used in lieu ladding in some nozzles.

surge line nozzle and removable electric heaters are installed in the lower pressurizer head.

heaters are removable for maintenance or replacement. A thermal sleeve is provided to imize stresses in the surge line nozzle. A retaining screen is located above the nozzle to vent any foreign matter from entering the RCS. Baffles in the lower section of the pressurizer

ay line nozzles, relief and safety valve connections are located in the upper head of the vessel.

ay flow is modulated by automatically controlled air-operated valves. The spray valves also be operated manually by a switch in the control room.

mall continuous spray flow is provided through a manual bypass valve around the er-operated spray valves to assure that the pressurizer liquid is homogeneous with the coolant to prevent excessive cooling of the spray piping.

ing an outsurge from the pressurizer, flashing of water to steam and generating of steam by matic actuation of the heaters retain the pressure above the minimum allowable limit. During nsurge from the RCS, the spray system, which is fed from two cold legs, condenses steam in vessel to prevent the pressurizer pressure from reaching the setpoint of the power-operated ef valves for normal design transients. Heaters are energized on high water level during rge to heat the subcooled surge water that enters the pressurizer from the reactor coolant loop.

erial specifications are provided in Table 5.2-7 for the pressurizer, pressurizer relief tank, and surge line. Design transients for the components of the RCS are discussed in Section 3.9N.1.

itional details on the pressurizer design cycle analysis are given in Section 5.4.10.3.5.

ay Line Temperatures peratures in the spray lines from the cold legs of two loops are measured and indicated.

rms to warn the operator from these signals are actuated by low spray water temperature.

rm conditions indicate insufficient flow in the spray lines.

ety and Relief Valve Discharge Temperatures peratures in the pressurizer safety and relief valve discharge lines are measured and indicated.

increase in a discharge line temperature is an indication of leakage or relief through the ciated valve.

10.3 Design Evaluation 10.3.1 System Pressure enever a steam bubble is present within the pressurizer, RCS pressure is maintained by the surizer. Analyses indicate that proper control of pressure is maintained for the operating ditions.

afety limit has been set to ensure that the RCS pressure does not exceed the maximum sient value allowed under the ASME Code,Section III, and thereby assure continued integrity he RCS components.

ing startup and shutdown, the rate of temperature change in the RCS is controlled by the rator. Heatup rate is controlled by pump energy and by the pressurizer electrical heating acity. This heatup rate takes into account the continuous spray flow provided to the surizer. When the reactor core is shutdown, the heaters are deenergized.

en the pressurizer is filled with water, i.e., during initial system heatup, and near the end of the ond phase of plant cooldown, RCS pressure is maintained by the letdown flow rate via the idual Heat Removal System.

10.3.2 Pressurizer Performance normal operating water volume at full load conditions is a percentage of the free internal sel volume. Under part load conditions, the water volume in the vessel is reduced for portional reductions in plant load. The various plant operating transients are analyzed and the gn pressure is not exceeded with the pressurizer design parameters as given in Table 5.4-10.

10.3.3 Pressure Setpoints RCS design and operating pressure together with the safety, power relief and pressurizer y valves setpoints, and the protection system setpoint pressures are listed in Table 5.4-11. The gn pressure allows for operating transient pressure changes. The selected design margin siders core thermal lag, coolant transport times and pressure drops, instrumentation and trol response characteristics, and system relief valve characteristics.

10.3.4 Pressurizer Spray o separate, automatically controlled spray valves with remote manual overrides are used to ate pressurizer spray. In parallel with each spray valve is a manual throttle valve which mits a small continuous flow through both spray lines to reduce thermal stresses and thermal ck when the spray valves open, and to help maintain uniform water chemistry and temperature he pressurizer. Temperature sensors with low alarms are provided in each spray line to alert the rator to insufficient bypass flow. The layout of the common spray line piping to the pressurizer ms a water seal which prevents the steam buildup back to the control valves. The spray rate is cted to prevent the pressurizer pressure from reaching the operating setpoint of the power ef valves during a step reduction in power level of ten percent of full load.

pressurizer spray lines and valves are large enough to provide adequate spray using as the ing force the differential pressure between the surge line connection in the hot leg and the y line connection in the cold leg. The spray line inlet connections extend into the cold leg ng in the form of a scoop so that the velocity head of the reactor coolant loop flow adds to the y driving force. The spray valves and spray line connections are arranged so that the spray operate when one reactor coolant pump is not operating. The line may also be used to assist in alizing the boron concentration between the reactor coolant loops and the pressurizer.

ng cooldown when the reactor coolant pumps are not operating. The thermal sleeves on the surizer spray connection and the spray piping are designed to withstand the thermal stresses lting from the introduction of cold spray water.

10.3.5 Pressurizer Design Analysis occurrences for pressurizer design cycle analysis are defined as follows:

1. The temperature in the pressurizer vessel is always, for design purposes, assumed to equal saturation temperature for the existing RCS pressure, except in the pressurizer steam space subsequent to a pressure increase. In this case the temperature of the steam space will exceed the saturation temperature since an isentropic compression of the steam is assumed.

The only exceptions of the above occur when the pressurizer is filled water solid during plant startup and cooldown or potentially during transients, such as an Inadvertent ECCS Actuation, CVCS malfunction or a feedwater line break.

2. The temperature shock on the spray nozzle is assumed to equal the temperature of the nozzle minus the cold leg temperature and the temperature shock on the surge nozzle is assumed to equal the pressurizer water space temperature minus the hot leg temperature.

3. Pressurizer spray is assumed to be initiated instantaneously to its design flow rate as soon as the RCS pressurizer pressure increases above 2260 psig. Spray is assumed to be terminated as soon as the RCS pressure falls below 2260 unless otherwise noted.

4. Consistent with 3 above, unless otherwise noted, pressurizer spray is assumed to be initiated once per occurrence of each transient condition. The pressurizer surge nozzle is also assumed to be subject to one temperature transient per transient condition, unless otherwise noted.

5. At the end of each upset condition transient, the RCS is assumed to return to a no-load condition with pressure and temperature changes controlled within normal limits.

6. Temperature changes occurring as a result of pressurizer spray are assumed to be instantaneous. Temperature changes occurring on the surge nozzle are also assumed to be instantaneous.

7. Whenever spray is initiated in the pressurizer, the pressurizer water level is assumed to be at the no load level.

bank of pressurizer backup heaters (manually connected to an emergency power source hin 60 minutes) is sufficient to maintain natural circulation following a loss of off site power.

10.4 Inspection and Testing Requirements pressurizer is designed and constructed in accordance with ASME Code Section III.

mplement the requirements of ASME Code Section XI the following welds are designed and structed to present a smooth transition surface between the parent metal and the weld metal.

path is ground smooth for ultrasonic inspection.

1. Support skirt to the pressurizer lower head

2. Surge nozzle to the lower head

3. Safety, relief, and spray nozzles to the upper head

4. Nozzle to safe end attachment welds

5. All girth and longitudinal full penetration welds

6. Manway attachment welds liner within the safe end nozzle region extends beyond the weld region to maintain a uniform metry for ultrasonic inspection.

pheral support rings are furnished for the removable insulation modules.

pressurizer quality assurance program is given in Table 5.4-12.

10.5 Instrumentation Requirements er to Chapter 7 for details of the instrumentation associated with pressurizer pressure, level, temperature.

11 PRESSURIZER RELIEF DISCHARGE SYSTEM pressurizer relief discharge system collects, cools and directs for processing the steam and er discharged from the various safety and relief valves in the containment. The system consists he pressurizer relief tank, the safety and relief valve discharge piping, the relief tank spray der and associated piping, and the tank nitrogen supply, the vent to containment and the drain he reactor plant gaseous drains. Table 5.4-14 shows these valves with reference to their FSAR res.

es and materials of the pressurizer relief tank Figure 5.4-7 and associated piping are given in tion 5.2. Design data for the tank are given in Table 5.4-13.

system design is based on the requirement to absorb a discharge of steam equivalent to 110 ent of the full power pressurizer steam volume. The steam volume requirement is roximately that which would be experienced if the plant were to suffer a complete loss of load ompanied by a turbine trip but without the resulting reactor trip.

minimum volume of water in the pressurizer relief tank is determined by the energy content he steam to be condensed and cooled, by the assumed initial temperature of the water, and by desired final temperature of the water volume. The initial water temperature is assumed to be F, which corresponds to the design maximum expected containment temperature for normal ditions. Provision is made to permit cooling the tank should the water temperature rise above F during plant operation. The design final temperature is 200F, which allows the contents of tank to be drained directly to the reactor plant gaseous drains system without cooling.

vessel saddle supports and anchor bolt arrangement are designed to withstand the loadings lting from a combination of nozzle loadings acting simultaneously with the vessel dead ght loadings.

11.2 System Description piping and instrumentation diagram for the pressurizer relief discharge system is given on ure 5.1-1.

steam and water discharged from the various safety and relief valves inside containment is ed to the pressurizer relief tank if the discharged fluid is of reactor grade quality. Table 5.4-14 vides an itemized list of valves discharging to the tank together with references of the esponding piping and instrumentation diagrams.

tank normally contains water and a predominantly nitrogen atmosphere. In order to obtain ctive condensing and cooling of the discharged steam, the tank is installed horizontally and steam is discharged through a sparger pipe located near the bottom, under the water level. The ger holes are designed to insure a resultant steam velocity close to sonic.

tank is also equipped with an internal spray and a drain which are used to cool the water owing a discharge. Cold water is drawn from the primary grade water system, and the content he tank is drained to the reactor plant gaseous drains system.

nitrogen gas blanket is used to control the atmosphere in the tank and to allow room for the ansion of the original water plus the condensed steam discharge. The tank gas volume is ulated using a final pressure based on an arbitrary design pressure of 100 psig. The design harge raises the worst case initial conditions to 50 psig, a pressure low enough to prevent

contents of the vessel are drained to the reactor plant gaseous drains system.

11.2.1 Pressurizer Relief Tank general configuration of the pressurizer relief tank is shown on Figure 5.4-7. The tank is a zontal, cylindrical vessel with elliptical dished heads. The vessel is constructed of austenitic nless steel and is overpressure protected in accordance with ASME Code Section VIII, ision 1, by means of two safety heads with stainless steel rupture discs.

anged nozzle is provided on the tank for the pressurizer discharge line connection to the ger pipe. The tank is also equipped with an internal spray connected to a cold water inlet and h a bottom drain, which are used to cool the tank following a discharge.

11.3 Safety Evaluation pressurizer relief discharge system does not constitute part of the reactor coolant pressure ndary per 10 CFR 50, Section 50.2, since all of its components are downstream of the reactor lant system safety and relief valves. Thus, General Design Criteria 14 and 15 are not licable. Furthermore, complete failure of the auxiliary systems serving the pressurizer relief does not impair the capability for safe plant shutdown.

design of the system piping layout and piping restraints is consistent with Regulatory Guide

. Compliance to Regulatory Guide 1.46 by restraining the safety and relief valve discharge ng so that integrity and operability of the valves are maintained in the event of a rupture.

ulatory Guide 1.67 is not applicable since the system is not an open discharge system.

pressurizer relief discharge system is capable of handling the design discharge of steam hout exceeding the design pressure and temperature. The volume of water in the pressurizer ef tank is capable of absorbing the heat from the assumed discharge maintaining the water perature below 200F. If a discharge exceeding the design basis should occur, the relief device he tank would pass the discharge through the tank to the containment sumps.

rupture discs on the relief tank have a relief capacity equal to or greater than the combined acity of the pressurizer safety valves. The tank design pressure is twice the calculated pressure lting from the design basis safety valve discharge described in Section 5.4.11.1. The tank and ure discs holders are also designed for full vacuum to prevent tank collapse if the contents l following a discharge without nitrogen being added.

discharge piping from the safety and relief valves to the relief tank is sufficiently large to vent backpressure at the safety valves from exceeding 20 percent of the setpoint pressure at flow.

pressurizer relief tank pressure transmitter provides an indication of pressure relief tank sure. An alarm is provided to indicate high tank pressure.

pressurizer relief tank level transmitter supplies a signal for an indicator with high and low l alarms.

temperature of the water in the pressurizer relief tank is indicated, and an alarm actuated by h temperature informs the operator that cooling of the tank contents is required.

11.5 Inspection and Testing Requirements system components are subject to non destructive and hydrostatic testing during construction ccordance with Section VIII, Division 1 of the ASME Code (Table 5.4-12).

ing plant operation, periodic visual inspections and preventive maintenance are conducted on system components according to normal industrial practice.

12 VALVES 12.1 Design Bases noted in Section 5.2, all valves out to and including the second valve normally closed or able of automatic or remote closure, larger than three-quarter inch, are ANS Safety Class 1, ASME III, Code Class 1 valves. All three-quarter inch or smaller valves in lines connected to reactor coolant system (RCS) are Class 2 since the interface with the Class 1 piping is vided with suitable orificing for such valves. Exceptions to this are the pressurizer steam space ation valves and RHS PLTB lines which are ASME III Class 1 with the orifice located nstream of the isolation valve. Design data for the RCS are given in Table 5.4-15.

a check valve to qualify as part of the RCS it must be located inside the containment system.

en the second of two normally open check valves is considered part of the RCS (as defined in tion 5.1), and verification of proper valve closure is required, non-intrusive techniques (e.g.,

ography) are employed to perform this verification.

ensure that the valves meet the design objectives, the materials of construction minimize osion/erosion and ensure compatibility with the environment, leakage is minimized to the nt practicable by design, and stresses are maintained within the limits of the ASME Section Code.

12.2 Design Description valves in the RCS are constructed primarily of stainless steel.

PORV block valves were replaced with valves that do not require leakoff connections. All ttling control valves, regardless of size, are provided with double stuffing boxes and with stem off connections. All leakoff connections are piped to a closed collection system. Leakage to atmosphere is essentially zero for these valves.

e valves at the engineered safety features interface are wedge design and are essentially ight through. The wedges are flexwedge or solid. All gate valves have backseats. Check es are either swing type or tilting disc for size 2.5 inches and larger. All check valves which tain radioactive fluid are stainless steel and do not have body penetrations other than the inlet, et and bonnet. The check hinge is services through the bonnet. The accumulator check valve esigned such that at the required flow the resulting pressure drop is within the specified limits.

operating parts are contained within the body. The disc has limited rotation to provide a nge of seating surface and alignment after each valve opening.

reactor coolant loop stop valves are remotely controlled motor- operated gate valves which mit any loop to be isolated from the reactor vessel. One valve is installed on each hot leg and on each cold leg. The design of the valve is basically the same as noted above with the itional feature that each set of packing is capable of being tightened independently of the other of packing. Also, the valve is a paralleled disc design. RCS parameters are given in le 5.4-15.

12.3 Design Evaluation design/analysis requirements for Class 1 valves, as discussed in Section 5.2, limit stress to ls which ensure the structural integrity of the valves. In addition, the testing programs cribed in Section 3.9N.3.2.2 demonstrate the ability of the valves to operate as required during cipated and postulated coolant conditions.

ctor coolant chemistry parameters are specified in the design specifications to assure the patibility of valve construction materials with the reactor coolant. To ensure that the reactor lant continues to meet these parameters, the chemical composition of the coolant is analyzed odically as discussed in the technical specifications.

above requirements and procedures, coupled with the previously described design features minimizing leakage, ensure that the valves perform their intended functions as required during t operation.

12.4 Tests and Inspections ts and examinations of RCS valves are performed in accordance with the requirements of the ME Code,Section III. There are no full penetration welds within valve body walls. Valve destructive examinations are given in Table 5.4-16.

tion XI, as indicated in the Technical Specifications.

ves are accessible for disassembly and internal visual inspection to the extent practical.

rvice inspection is discussed in Section 5.2.4.

13 SAFETY AND RELIEF VALVES 13.1 Design Bases pressurizer safety valves are designed to accommodate the maximum surge resulting from plete loss of load. Sizing of the pressurizer safety valves is discussed in Section 5.2.2. The surizer power-operated relief valves are designed to limit pressurizer pressure to a value w the fixed high pressure reactor trip setpoint. They are designed to fail to the closed position ower loss.

13.2 Design Description pressurizer safety valves are of the pop type. The valves are spring loaded, open by direct d pressure action, and have back pressure compensation features.

piping connecting the pressurizer nozzles to their respective safety valves are shaped in the m of a loop seal. However, loop seal drains are maintained open to eliminate the formation of a er seal. EPRI testing showed water seals cause substantial safety valve discharge pipe loads.

densate resulting from normal heat losses drains back to the pressurizer via a drain tapped to low point of the loop seal.

pressurizer power operated relief valves are solenoid operated valves which are operated matically or by remote manual control. The pressurizer power operated relief valves are vided with a positive position indication in the control room (open/closed indication lights ch are activated by limit switches).

otely operated stop valves are provided to isolate the power operated relief valves if essive leakage develops. Positive position indication (open/closed) for the stop valves is ted in the control room.

power operated relief valves (PORVs), the PORV block valves, and pressurizer level rumentation are powered from the Class IE power system (Section 8.3.1).

peratures in the pressurizer safety and relief valve discharge lines are measured and indicated he control room. An increase in a discharge line temperature is an indication of leakage or ef through the associated valve.

ves identical to Millstone 3s power operated relief valves (PORVs) and safety valves were ed, in a program conducted by EPRI under full flow, expected saturated steam operating

luated by Westinghouse and a report was generated.

itionally, testing of valves similar to the PORV block valves, is documented in Duke ineering Services Inc. Report TR-161, Dynamic Test Program for BW/IP International, Inc. -

ve Division Inch Parallel Disk Gate Motor-Operated Valve, dated 9/8/97. This test fied valve operability under full flow conditions.

PORVs were analyzed by Westinghouse in 1998 and qualified for operation during subcooled er conditions. The block valves were similarly qualified to operate with subcooled water in ordance with GL89-10 requirements per the licensee's program.

ign parameters for the pressurizer safety and power operated relief valves are given in le 5.4-17.

13.3 Design Evaluation pressurizer safety valves prevent RCS pressure from exceeding 110 percent of system design sure, in compliance with the ASME Code.

pressurizer power operated relief valves prevent actuation of the fixed reactor high pressure for all design transients up to and including the design step load decreases with steam dump.

relief valves also limit the opening of the spring loaded safety valves. The pressurizer power-rated relief valves also provide a safety grade means to depressurize the RCS for safety grade shutdown. See Section 5.4.7.2.3.5.

13.4 Inspection and Testing Requirements ts and examination of pressurizer safety and relief valves are performed in accordance with the uirements of the ASME Code,Section III. There are no full penetration welds within valve y walls. Valve nondestructive examinations are given in Table 5.4-16.

tests and inspections discussed in Section 3.9 are performed to ensure the operability of ve valves. In place operational testing is performed on valves as required by the ASME OM e as indicated in the technical specifications.

ves are accessible for disassembly and internal visual inspection to the extent practical.

rvice inspection is discussed in Section 5.2.4.

14 COMPONENT SUPPORTS mponent supports are part of a safety system that permits movement to accommodate thermal ansion of the reactor coolant loops during plant operation while providing restraint to the tor coolant system (RCS) components during accident conditions.

ntain their necessary safety functions during normal operating conditions, postulated safe tdown earthquake (SSE) conditions, and accidents such as postulated extremes of pipe rupture ng concurrently with the SSE. Postulated pipe ruptures are assumed to be double-ended or gitudinal. These failures are assumed to occur in either the reactor coolant piping, pressurizer e piping, or main steam line piping (Section 3.6). Section 3.7B.1 discusses seismic design of ports for reactor coolant piping. Detailed design bases and results of qualification analyses are tained in Section 3.9B.3.

14.1 Description supports are comprised of forged, cast, and welded steel sections. Linear type supports are d in all cases except for the RPV support which is a plate and shell support. The attachments to supported equipment are non-integral and are bolted to or bear against the components.

chment to the interface to building structure is achieved by embedded anchor bolts and shear 14.1.1 Reactor Vessel Structural Support (RVSS) support for the reactor vessel (the neutron shield tank) is a cylindrical double-wall structure surrounds and supports the reactor pressure vessel, and accommodates all applicable loading ditions. The RVSS transfers all loading conditions from the reactor vessel to the primary ld wall through groutings, and to the concrete anchors at its base. The RVSS also provides port for the out-of-core neutron detector monitors. The annular portion of the tank is filled h water to provide neutron shielding and a thermal barrier for protection of the surrounding ctural concrete. The water is circulated through an external heat exchanger to maintain proper ling for the system. The reactor vessel is supported at four nozzles on leveling devices unted on top of the neutron shield tank. The functional requirement of the RPV leveling ices is to provide vertical adjustment at each RPV nozzle restraint pad during installation of reactor vessel. During all plant conditions, the leveling device is designed to transfer only nward vertical loads from the RPV to the RVSS. Upward and side loads from the RPV are sted by gib keys and gib gussets. The RVSS is shown on Figures 5.4-9 and 5.4-10.

14.1.2 Steam Generator Supports supports for each steam generator consist of vertical, upper and lower lateral supports.

r individual column assemblies provide the vertical support for each steam generator. Each mn assembly consists of a lower clevis, column lug, extension tube and upper column clevis.

upper clevises are bolted to the steam generator tube sheet and the lower clevises are hored to the concrete floor. The four vertical column assemblies transmit vertical forces from steam generator to the cubicle floor.

lateral (upper and lower) supports are provided by eight double acting hydraulic snubbers.

h lateral support has four hydraulic snubber assemblies which permit motion of the steam

hydraulic snubbers are designed to lock and resist dynamic forces which result from seismic

/or pipe rupture conditions.

lower lateral support assemblies are bolted to the steam generator tube sheet and the concrete

l. The upper lateral support assemblies are bolted to the steam generator restraint ring and the crete wall. The steam generator supports are shown on Figures 5.4-11 and 5.4-12.

14.1.3 Reactor Coolant Pump Supports reactor coolant pump is supported by three pin ended columns which provide vertical support le allowing free movement in the horizontal plane. Three independent hydraulic snubber mblies, connected to the pump support and the reactor shield wall, provide lateral support for pump during dynamic loading conditions while allowing thermal expansion of the RCS. The p supports are shown on Figures 5.4-11 and 5.4-13.

14.1.4 Pressurizer Support re is one pressurizer located in the pressurizer cubicle of the containment building. The surizer is an integral part of the RCS and is connected to the hot leg of Loop 2 by the surge (Section 5.4.10).

pressurizer is skirt mounted to a ring girder which is suspended from the operating floor by hanger columns. Four horizontal support restraints, which attach the ring girder to the ding structure, prevent all motions except vertical translation and horizontal rotation. Integral located on the pressurizer near the center of gravity fit into striker plate assemblies embedded he concrete floor at elevation 51 feet 4 inches These brackets allow thermal expansion of the surizer but resist horizontal and torsional displacements resulting from seismic and/or wdown forces. The pressurizer support is shown on Figure 5.4-14.

14.1.5 Pressurizer Safety Valve Supports pressurizer safety valves are mounted on a ring girder that is located on the upper portion of pressurizer. Support flanges are bolted to the valve body which in turn are connected to the girder. The ring girder is supported by four columns welded to the ring and pin-connected to is lugs attached to the pressurizer gussets. The supports are designed to withstand the loads osed by the safety relief piping which consist of dead weight, thermal, seismic, and ultaneous discharge of all safety valves. The pressurizer safety valve supports are shown on ure 5.4-15.

14.2 Design Basis final designs, established for these supports, are based on maximum load combinations.

se load combinations are derived from a system analysis using blowdown forcing functions

imum loads are used as the faulted conditions for support design.

m these final support designs, the inertia, stiffness, and damping quantities are evaluated and d as a basis for further refinement by elastic structural dynamic analysis, as described in tion 3.7B.3. The designs are revised according to the computer results for more uniform stress ribution. This cycle is repeated, as required, to achieve sufficient optimization of structural gn efficiency for the supports (Section 3.9B.3).

loading categories, load combinations, and stress limits for the supports are shown in le 5.4-18. The steam generator, reactor coolant pump and pressurizer supports are classified near type supports. For these linear type supports subject to design, normal, upset, and rgency operating loads, the stress limits are based on the elastic analysis of the ASME III e, Subsection NA, Appendix XVII-2000. The reactor vessel support, neutron shield tank, is a bination linear and plate and shell-type support. The stress limits for linear type supports are Appendix XVII-2000 and the stress limits for plate and shell type supports are per NF-3220 of ASME Code,Section III. Faulted operating conditions for all component supports have been lyzed in accordance with Appendix F of the ASME III Code.

14.3 Evaluation ailed evaluation ensures the design adequacy and structural integrity of the reactor coolant p and the primary equipment supports system. This detailed evaluation is made by comparing analytical results with established criteria for acceptability as described in Section 3.9B.3.

ctural analyses are performed to demonstrate design adequacy of the plant in case of an OBE SE and/or LOCA conditions. Loads which the system is expected to encounter during plant ration (thermal, weight, pressure) are applied and stresses are compared to allowable values as cribed in Section 3.9B.3.

safe shutdown earthquake (SSE) and design basis LOCA resulting in a rapid depressurization he system, are required design conditions for public health and safety. The methods used for analysis of the SSE and LOCA conditions are given in Section 3.9B.1.

14.4 Tests and Inspections d inspection and standards are specified in accordance with Section V of the ASME Code.

der qualifications and welding procedures are specified in accordance with Section IX of the ME Code.

15 REACTOR VESSEL HEAD VENT SYSTEM reactor vessel head vent system (RVHVS) (Figure 5.1-1) removes non condensable gases or m from the reactor vessel head. This system is designed to mitigate a possible condition of equate core cooling or impaired natural circulation resulting from the accumulation of consumable gases in the RCS. Additionally, the system provides the safety grade letdown path

15.1 Design Basis RVHVS is designed to remove non consumable gases or steam from the reactor coolant em via remote manual operations from the control room. The system discharges to the surizer relief tank. Additionally, a letdown flow path is provided from the reactor vessel head t to the excess letdown heat exchanger in the chemical and volume control system (CHS). The HVS is designed to vent a volume of hydrogen at system design pressure and temperature roximately equivalent to one half of the reactor coolant system volume in one hour.

system provides for venting the reactor vessel head by using only safety grade equipment.

down to accommodate boration during a safety grade cold shutdown is also provided by this

. To ensure reliability of this function, the letdown line is provided with parallel solenoid es. The valves are designed to fail closed such that both lines can always be isolated, and the valves in the same line are powered by the same power train such that at least one line can ays be made available. Downstream of these isolation valves, the safety grade path directs own to the pressurizer relief tank via parallel solenoid valves.

piping and equipment from the vessel head vent up to and including the second isolation valve ach flow path are designed and fabricated in accordance with ASME Section III, Class 1 uirements. The piping and equipment in the flow paths from the isolation valve to the dulating valves and from the isolation valves to the excess letdown heat exchanger are gned and fabricated in accordance with ASME Section III, Class 2 requirements. The ainder of the piping and equipment is non-nuclear safety.

isolation valves are included in the Westinghouse valve operability program which is an eptable alternative to Regulatory Guide 1.48. These valves are qualified to IEEE 323-1974,

-1975, and 382-1972 (Section 3.11).

supports and support structures comply with the requirements of the ASME Code.

analysis of the rector vessel head vent piping is based on the following plant operating ditions defined in the ASME Code, Section III:

1. Normal Condition Pressure, deadweight, and thermal expansion analysis of the vent piping during:

a. Normal reactor operation with the vent isolation valves closed and

b. Post refueling venting

2. Upset Condition (including safety grade cold shutdown)

3. Faulted Condition Loads generated by the safe shutdown earthquake (SSE). Loads generated by valve thrust during venting. In accordance with ASME III, faulted conditions are not included in fatigue evaluations.

Class 1 piping used for the reactor vessel head vent is 1 inch schedule 160 and, therefore, in ordance with ASME III, is analyzed following the procedures of NC-3600 for Class 2 piping.

all plant operating conditions listed above, the piping stresses are shown to meet the uirements of equations (8), (9), and (10) or (11) of ASME III, NC-3600, with a design perature of 650F and a design pressure of 2,485 psig.

15.2 System Description RVHVS consists of two parallel flow paths with redundant isolation valves in each flow path.

venting operation uses only one of these flow paths at any one time. The equipment design meters are listed in Table 5.4-19.

active portion of the system consists of four one inch open/close solenoid-operated isolation es connected to the existing 1 inch vent pipe, which is located near the center of the reactor sel head. The system design with two valves in series in each flow path minimizes the sibility of reactor coolant pressure boundary leakage. The isolation valves in one flow path are ered by one vital power supply and the valves in the second flow path are powered by a ond vital power supply. The isolation valves are fail closed normally closed valves.

e vent system piping is supported to ensure that the resulting loads and stresses on the piping on the vent connection to vessel head are acceptable.

15.3 Safety Evaluation ne single active failure prevents a venting operation through one flow path, the redundant path vailable for venting. The two isolation valves in each flow path provide a similar method of ating the venting system. With two valves in series, the failure of any one valve or power ply will not inadvertently open a vent path. Thus, the combination of safety grade train gnments and valve failure modes will not prevent vessel head venting nor venting isolation h any single active failure.

RVHVS has two normally deenergized valves in series in each flow path. This arrangement inates the possibility of an opened flow path due to the spurious movement of one valve. As h, power lockout to any valve is not considered necessary.

would behave similarly to the hot leg break case presented in WCAP-9600, the results ented therein are applicable to a RVHVS line break. This postulated vent line break, efore, results in no calculated core uncovery.

15.4 Inspection and Testing Requirements rvice inspection is conducted in accordance with Sections 5.2.4 and 6.6.

15.5 Instrumentation Requirements system is operated from the control room and the auxiliary shutdown panel. The isolation es have stem position switches. The position indication from each valve is monitored in the trol room by status lights.

16 REFERENCES FOR SECTION 5.4 1 WCAP-8163, 1973, Reactor Coolant Pump Integrity in LOCA, Westinghouse.

2 WCAP-8768, Revision 2, 1978, Safety Related Research and Development for Westinghouse Pressurized Water Reactor, Program Summaries, Winter 1977-Summer 1978, Westinghouse.

3 WCAP-9600, 1979. Report on Small Break Accidents for Westinghouse NSSS System, (Section 3.2).

4 WCAP-7832, Evaluation of Steam Generator Tube, Tube Sheet and Divider Plate Under Combined LOCA plus SSE conditions, December 1973, Westinghouse.

5 WOG-87-102, 5/12/87, Mode 4 LOCA Concern Interim Guidance.

6 OG-90-30, 6/1/90, Shutdown LOCA Analysis Concerns That Relate to the Interim Guidance.

7 WOG-90-48, 3/6/90, RHR System Operability During Mode 4 LOCA.

it design pressure (psig) 2,485 it design temperature (F) 650 (a) it overall height (ft) 26.3 al water injection (gpm) 8 al water return (gpm) 2.5 mponent cooling water flow (gpm) (b) 216 ximum continuous component cooling water 105 et temperature (F) illed water flow (gpm) (c) 220 ximum chilled water inlet temperature (F) 45 tal weight, dry (lb) 187,852 mp Design flow, best estimate (gpm) 100,400 Developed head, best estimate (ft) 289 NPSH required (ft) Figure 5.4-2 Suction temperature, thermal design (F) 556.8 Pump discharge nozzle, inside diameter (in) 27-1/2 Pump suction nozzle, inside diameter (in) 31 Speed (rpm) 1,186 Water volume (ft3) 80 (d) tor Type: Drip proof, squirrel-cage induction, with water/air coolers Power (hp) 7,000 Voltage (V) 6,600 Phase 3 Frequency (Hz) 60 Insulation class Class B, thermalasatic epoxy insulation

rrent (amp):

Starting 3,000 @ 6,600 V Normal input, hot reactor coolant 506 10 Normal input, cold reactor coolant 664 13 mp moment of inertia, max (lb/ft2):

Flywheel 70,000 Motor 22,500 Shaft 520 Impeller 1,980 TES:

Design temperature of pressure-retaining parts of the pump assembly exposed to the reactor coolant and injection water on the high pressure side of the controlled leakage seal shall be that temperature determined for the parts for a reactor coolant loop temperature of 650F.

Component cooling water is supplied to the thermal barrier at 40 gpm, the upper bearing cooler at 170 gpm, and the lower bearing cooler at 6 gpm.

Chilled water is supplied to the air coolers at a flow rate of 110 gpm to each air cooler.

Composed of reactor coolant in the casing and of seal injection and cooling water in the thermal barrier.

PROGRAM RT UT PT MT stings yes yes rgings in shaft yes yes in studs yes yes te wheel yes

• yes

• yes

• ldments cumferential yes yes trument connections yes TES:

- Radiographic

- Ultrasonic

- Dye penetrant T - Magnetic particle Either a UT over the volume from the inner bore of the flywheel to the circle of one-half the outer radius, or a surface examination (MT/PT) of exposed surfaces defined by the volume of the disassembled flywheel.

TABLE 5.4-3 STEAM GENERATOR DESIGN DATA ign pressure, reactor coolant side (psig) 2,485 ign pressure, steam side (psig) 1,185 ign pressure, primary to secondary (psi) 1,600 ign temperature, reactor coolant side (F) 650 ign temperature, steam side (F) 600 ign temperature, primary to secondary (F) 650 al heat transfer surface area (ft2) 55,000 ximum moisture carryover (weight percent) 0.25 rall height (ft-in) 67-8 mber of U-tubes 5,626 ube nominal diameter (in.) 0.688 e wall nominal thickness (in.) 0.040 mber of manways 4 de diameter of manways (in.) 16 mber of handholes 6 mber of inspection ports 2 ign fouling factor (ft2-hr-F/Btu) 0.00006 am flow (lb/hr) 4.075 x 106

PROGRAM RT UT PT MT ET be Sheet rging yes yes adding yes

• yes annel Head fabricated) Fabrication yes** yes *** yes adding yes condary Shell and Head tes yes bes yes yes zzles (Forgings) yes yes ldments ell, longitudinal yes yes ell, circumferential yes yes adding yes annel head-tube sheet joint cladding restoration) mary nozzles to fab head yes yes nways to fab head yes yes am and feedwater nozzle to shell yes yes pport brackets yes be to tube sheet yes trument connections (primary and secondary) yes mporary attachments after removal yes ter hydrostatic test (all major pressure boundary welds yes d complete cast channel head - where accessible) zzle safe ends (if weld deposit) yes yes

RT UT PT MT ET TES:

- Radiographic

- Ultrasonic

- Dye penetrant T - Magnetic particle

- Eddy current Flat surfaces only Weld deposit

• Base material only

actor inlet piping inside diameter (in) 27-1/2 actor inlet piping, nominal wall thickness (in) 2.32 actor outlet piping inside diameter (in) 29 ctor outlet piping, nominal wall thickness (in) 2.45 olant pump suction piping inside diameter (in) 31 olant pump suction piping, nominal wall thickness (in) 2.60 ssurizer surge line piping, nominal pipe size (in) 14 ssurizer surge line piping, nominal wall thickness (in) 1.406 actor Coolant Loop Piping Design/operating pressure (psig) 2485 / 2235 Design temperature (F) 650 ssurizer Surge Line Design pressure (psig) 2485 Design temperature (F) 680 ssurizer Safety Valve Inlet Line Design pressure (psig) 2485 Design temperature (F) 680 ssurizer (Power-Operated) Relief Valve Inlet Line Design pressure (psig) 2485 Design temperature (F) 680 actor Head Vent Piping Design pressure (psig) 2485 Design temperature (F) 650 Nominal pipe size (in) 1 Wall thickness (schedule) 160

ssurizer Relief Tank Inlet Line Design pressure (psig) 600 Design temperature (F) 600 op Stop Valve Bypass Line Design pressure (psig) 2485 Design temperature (F) 650 Loop stop valve bypass line nominal pipe size (in) 8 Loop stop valve bypass line nominal wall thickness (in) 0.906

RT* UT* PT

• tings and Pipe (Castings) yes yes tings and Pipe (Forgings) yes yes ldments Circumferential yes yes Nozzle to runpipe yes yes xcept no RT for nozzles less than 6 inches)

Instrument connections yes stings yes yes (after finishing) rgings yes yes (after finishing)

TES:

RT - Radiographic UT - Ultrasonic PT - Dye Penetrant

OPERATION SGCS NORMAL actor coolant system initial pressure (psig) 375 375 actor coolant system initial temperature (F) 350 350 ximum component cooling water supply temperature (F) 113 110 ximum component cooling water outlet temperature F 145 145 oldown time, after reactor shutdown (hr) 72 36 actor coolant system temperature at end of cooldown (F) 200 200

sidual Heat Removal Pump mber 2 sign pressure (psig) 600 sign temperature (F) 400 sign flow (gpm) 4,000 sign head (ft) 350 SH required at 3,800 gpm (ft) 18 SH required at runout flow 5,500 gpm (ft) 25 wer (hp) 400 sidual Heat Exchanger mber 2 sign heat removal capacity (Btu/hr) 35.27 x 106 imated UA (Btu/hr F) 3.5 x 106 Tube Side Shell Side sign pressure (psig) 600 175 sign temperature (F) 400 200 sign flow (lb/hr) 1.98 x 106 3.3 x 106 et temperature (F) 120 92.2 tlet temperature (F) 102.2 102.9 Austenitic Stainless terial Carbon Steel Steel Reactor Coolant id Component Cooling Water

EFFECTS ANALYSIS Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

1. Motor-operated a. Fails to open Provides isolation of a. Failure blocks reactor a. Valve open/close position 1. Valve is electricall gate valve on demand fluid flow from the coolant flow from hot leg of indication at CB; RC loop 1 interlocked with R 8701A (8701B RCS to the suction of RC loop 1 (loop 4) through (loop 4) hot leg pressure to RHR suction li analogous) RHR pump 1 (pump train A (train B) of indication at CB: RHR train isolation valve 88

2) RHRS. Failure reduces A (train B) discharge (8812B), with RH redundancy of RHR coolant flow indication and low flow charging pump su trains provided. No effect on alarm at CB; and RHR pump line isolation valv safety for system operation. 1 (pump 2) discharge 8804A (8804B) an Plant cooldown pressure indication and low with a prevent-op requirements will be met by flow alarm at CB; and RHR pressure interlock reactor coolant flow from pump 1 (pump 2) discharge PT405/PT-405A, hot leg of RC loop 4 (loop 1) pressure indication at CB. PT403/403A of R flowing through train B loop 1 (loop 4) ho (train A) of RHRS, The valve cannot however, time required to opened remotely f reduce RCS temperature will the CB if one of th be extended. indication isolatio valves is open or i loop pressure exce 412.5 psia. The va can be manually opened.

2. Motor-operated Same as item Same as item 1 Same as item 1. Same as item 1. Same as item 1, e gate valve 1 for pressure interl 8702A (8702B PT405/405A analogous) (PT-403/403A) co

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

3. RHR pump 1 Fails to Provides fluid flow of Failure results in loss of reactor Open pump switchgear circuit The RHRS shares (RHR pump 2 deliver reactor coolant coolant flow from hot leg of breaker indication at CB; components with t analogous) working through RHR heat RC loop 1 (loop 4) through circuit breaker close position ECCS. Pumps are fluid exchange 1 (heat train A (train B) of monitor light for group tested as part of th exchanger 2) to RHRS. Failure reduces monitoring of components at ECCS testing prog reduce RCS redundancy of RHR coolant CB; common breaker trip (see Section 6.3.4 temperature during trains provided. No effect on alarm at CB; RC loop 1 cooldown operation safety for system operation. (loop 4) hot leg pressure Plant cooldown indication at CB; RHR train requirements will be met by A (train B) discharge reactor coolant flow from flow indication and low flow hot leg of RC loop 4 (loop 1) alarm CB; and pump flowing through train B discharge pressure indication (train A) of RHRS, at CB.

however, time required to reduce RCS temperature will be extended.

4. Motor-operated a. Fails closed Provides regulation of a. Failure blocks miniflow line a. Valve open/close position 1. Valve is automatic globe valve fluid flow through to suction of RHR pump 1 indication at CB; and RHRS controlled to open FCV-610 miniflow bypass line (pump 2) during cooldown train A (train B) pump discharge is (FCV-611 to suction of RHR operation. No effect on discharge flow indication at than 772 gpm and analogous) pump 1 (pump 2) to safety for system operation. CB. when the discharg protect against Plant cooldown exceeds approxim overheating of the requirements will be met by 1633 gpm. These pump and loss of reactor coolant flow from are nominal valve discharge flow from hot leg of RC loop 4 (loop 1) the pump. flowing through train B (train A) of RHRS, however, time required to reduce RCS temperature will be extended.

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

b. Fails open b. Failure allows for a portion Same as item 4.a.

of RHR heat exchanger 1 (heat exchanger 2) discharge flow to be bypassed to suction of RHR pump 1 (pump 2). RHRS train A (train B) is degraded for the regulation of coolant temperature by RHR heat exchanger 1 (heat exchanger 2). No effect on safety for system operation. Cooldown of RCS within established specification cooldown rate may be accomplished through operator action of adjusting throttle valves HCV-606 (HCV-607) and FCV-618 (FCV-619) to compensate for the open miniflow line and controlling cooldown with redundant RHRS train B (train A).

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

5. Air piston a. Fails to open Controls rate of fluid a. Failure prevents coolant a. RHR pump 1 (pump 2) 1. Valve is designed operated on demand flow bypassed around discharged from RHR pump discharge flow temperature open and is butterfly valve for flow RHR heat exchanger 1 1 (pump 2) from bypassing and RHRS train A (train electrically wired FCV-618 increase (heat exchanger 2) RHR heat exchanger 1 (heat B) discharge to RCS cold that electrical sole (FCV-619 (Auto during cooldown exchanger 2) resulting in leg flow temperature of the air diaphrag analogous) mode CB operation mixed mean temperature of recording at CB; and RHRS operator is energiz switch coolant flow to RCS being train A (train B) open the valve. Va selection) low. RHRS train A (train discharge to RCS cold leg normally open t B) is degraded for the flow indication at CB (TR align RHRS for E regulation of controlling 612). operation during p temperature of coolant. No power operation a effect on safety for system load follow.

operation. Cooldown of RCS 2. Valve is designed within established normal plant cool specification rate may be operation. It is req accomplished through for safety grade co operator action of throttling shutdown operatio flow control valve HCV-606 only one train of R (HCV-607) and controlling available and cooldown with redundant instrument air is l RHRS train B (train A).

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

b. Fails to close b. Failure allows coolant b. Same as item 5.a.

on demand discharged from RHR pump for flow 1 (pump 2) to bypass RHR reduction heat exchanger 1 (heat (Auto exchanger 2) resulting in mode CB mixed mean temperature of switch coolant flow to RCS being selection) high. RHRS train A (train B) is degraded for the regulation of controlling temperature of coolant. No effect on safety for system operation. Cooldown of RCS within established specification rate may be accomplished through operation action of throttling flow control valve HCV-606 (HCV-607) and controlling cooldown with redundant RHRS train B (train A),

however, cooldown time will be extended.

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

6. Air piston a. Fails to close Controls rate of fluid a. Failure prevents control of a. Same methods of detection 1. Valve is designed operated on demand flow through RHR coolant discharge flow from as those stated for item 5.a. open. Valve is butterfly valve for flow heat exchanger 1 (heat RHR heat exchanger 1 (heat In addition, monitor light normally open t HVC-606 reduction exchanger 2) during exchanger 2) resulting in and alarm (valve closed) for align RHRS for E (HCV-607 cooldown operation loss of mixed mean group monitoring of operation during p analogous) temperature coolant flow components at CB. power operation a adjustment to RCS. No load follow.

effect on safety for system operation. Cooldown of RCS within established specification rate may be accomplished by operator action of controlling cooldown with redundant RHR train B (train A).

b. Fails to open b. Same as item 6.a. b. Same as item 6.a.

on demand for flow increase

7. Motor-operated Fails to close Provides isolation of No effect on safety for Valve open/closed position Valve is normally gate valve on demand fluid from the RWST system operation. Plant indication at CB and valve open to align R 8812A (8812B) to suction of RHR cooldown requirements will (closed) monitor light and for ECCS operatin analogous) pump 1 (pump 2) be met by reactor coolant alarm at CB. during plant powe during cooldown flow from hot leg loop 4 operation and load operation (loop 1) flowing through follow. Valve mus train B (train A) of closed during plan RHRS, however, time cooldown to satisf required to reduce RCS electrical interlock temperature will be permit valves 870 extended. and 8702A (8701 8702B) to be open

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

8. Motor-operated Fails to close Provides separation Failure reduces the Same as item 7.

gate valve on demand between the two RHR redundancy for isolating 8716A (8716B trains during RHR trains during analogous) cooldown operation cooldown. Negligible effect on system operation.

Isolation valve 8716B (8716A) provides backup isolation between the two RHR trains.

9. Centrifugal Fails to Provides fluid flow of Failure reduces redundancy Charging pump discharge 1. The charging pum charging pump 1 deliver borated water from of providing water to the header pressure and flow provide boration a (pump 3 working the BAT or RWST to RCS at high RCS pressures. indication at CB. Open/close makeup flow to th analogous) fluid the RCS Fluid flow from charging pump switchgear circuit RCS during safety pump 1 (pump 3) will be breaker indication on CB. grade cold shutdo lost. Minimum flow Circuit breaker close operations. Note (

requirements for boration position monitor light. For 2. Analysis of chargi and makeup will be met by group monitoring of pump 2 being on l charging pump 3 (pump 1). component at CB. Common analogous to that breaker trip alarm at CB. presented for char pumps 1 and 3.

10. Motor-operated Fails to close Provides isolation of Failure reduces redundancy Same as item 7. The charging pum gate valve on demand fluid discharge from of providing VCT suction is isolated LCV-112B the VCT to the discharging isolation. the VCT and align (LCV-112C suction of charging Negligible effect on safety the BAT (for bora analogous) pumps for system operation. or RWST (for ma Alternate isolation valve during safety grad LCV-112C (LCV-112B) shutdown operatio provides backup tank discharge isolation.

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

11. Motor-operated Fails to open Provides isolation of Failure reduces redundancy Valve open/close position The charging pum gate valve on demand fluid discharge from of providing fluid from indication at CB (open) suction is aligned LCV-112D the RWST to the RWST to suction of charging monitor light and alarm at RWST for makeu (LCV-112E suction of charging pumps. Negligible effect on CB. the RCS during E analogous) pumps safety for system operation. and safety grade c Alternate isolation valve shutdown operatio LCV-112E (LCV-112D) opens to provide backup flow path to suction of charging pumps.

12. Motor-operated Fails to close Provides isolation of Failure reduces redundancy Same as item 7 except no Normal charging l gate valve 8105 on demand fluid flow from the of providing isolation of valve (closed) monitor alarm isolated during saf (8106 analogous) charging pump charging pump discharge to for group monitoring. grade cold shutdo discharge header to normal charging line of operations. Borati the CVCS normal CVCS. Negligible effect on and makeup flow charging line to the safety for system operation. provided to RCS RCS Alternate isolation valve through redundant 8105 (8106) provides ECCS headers to t backup normal CVCS RCS cold legs.

charging line isolation.

13. Motor-operated Fails to close Provides isolation MELB isolation may be Same as item 7. Note (4) gate valve on demand barrier to isolate provided by closing isolation 8468A (8468B charging pump valve 8468B (8468A).

analogous) suction flow paths in the event of a MELB in charging pump suction header

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

14. Motor-operated Fails to close Provides isolation HELB isolation may be Same as item 7. Note (5) gate valve on demand barrier to isolate provided by closing isolation 8438A (8438B charging pump valve 8438B (8438A).

analogous) discharge flow paths in the event of a HELB in charging pump discharge header

15. Solenoid Fails to open Provides control of Failure reduces redundancy Valve position indication at Same as item 12.

operated globe on demand fluid flow from of controlling boration and CB; and charging pump 1 valve charging pump 1 makeup flow to the RCS. (pump 3) discharge header HCV-190A (pump 3) to RCS Negligible effect on safety flow indication at CB.

(HCV-190B) during plant boration for system operation.

and makeup Alternate control valve HCV-190B (HCV-190A) controls flow from charging pump 3 (pump 1).

15a. Motor-operated Fails to open Provides isolation of Same as Item 15 Same as Item 15 Same as Item 12 Globe Valve MV on demand fluid flow from pump/

8116 (pumps) to RCS

16. Solenoid a. Fails to open Provides isolation of a. Failure reduces redundancy a. Valve open/close position 1. The RC head letd operated globe on demand fluid flow from the of providing flow from the indication at CB; and RV path to the CHS o valve 8095A RV head to the CHS RV head to the CHS or PRT. head letdown high provides fluid flo (8095B or PRT Negligible effect on safety temperature indication and of the RCS to analogous) for system operation. RV alarm at CB. accommodate bor head letdown flow provided flow into the RCS by parallel head letdown path through alternate isolation valve 8095B (8095A).

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

b. Fails to close b. Failure reduces redundancy b. Same as item 16.a.

on demand of isolating flow from the RV head to the CHS or PRT.

Negligible effect on safety for system operation. RV head letdown flow isolation provided by alternate series isolation valve 8096A (8096B).

17. Solenoid a. Fails to open Same as item 16 a. Same as item 16.a except for a. Same as item 16.a. 1. Same as item 16.1 operated globe on demand alternative isolation valve except that the RV valve 8096A 8096B (8096A). Letdown Path is t (8096B PRT.

analogous)

b. Fails to close b. Same as item 16.b except for b. Same as item 16.a.

on demand alternative series isolation valve 8095A (8095B).

18. Solenoid Fails to open Same as item 16 Same as item 16.a except Valve position indication at Same as item 16.1 operated globe on demand except that flow is that flow is from the RV CB; RV letdown temperature except that the RV valve from the RV head to head to the PRT and the indication at CB. Letdown Path is t HCV-442A the PRT alternative parallel isolation PRT.

(HCV-442B valve HCV-442B analogous) (HCV-442A).

19. Solenoid a. Fails to open Provides isolation of a. Failure reduces redundance a. Valve open/close position 1. Pressurizer vent p operated power on demand fluid flow from of providing flow from indication at CB; pressurizer the PRT provides operated relief pressurizer to PRT pressurizer to PRT. power operated relief valve flow out of the RC valve PCV-455A Negligible effect on safety outlet temperature indication permit RCS (PCV-456 for system operation. at CB. depressurization t analogous) Pressurizer vent flow RHRS initiation provided by a parallel conditions.

pressurizer vent path through alternate isolation valves PCV-456A or PCV-455A.

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

b. Fails to close b. Failure reduces redundancy b. Same as item 19.a.

on demand of isolating flow from the pressurizer to the PRT.

Negligible effect on safety for system operation.

Pressurizer vent flow isolation provided by alternate series isolation valve 8000A (or 8000B).

20. Motor-operated a. Fails to close Same as item 19 a. Same as item 19.a except a. Same as item 19.a. 1. Same as item 19.1 gate valve on demand pressurizer vent flow 8000A (8000B isolation provided by analogous) alternate series isolation valve PCV-455A (PCV-456).

21. Motor-operated Fails to close Provides isolation of Failure prevents isolation of Valve open/closed position Accumulators are gate valve on demand fluid flow from accumulator 1 (accumulator indication at CB, valve isolated or vented 8808A (8808B, accumulator 1 2, accumulator 3 and (closed) monitor light and during plant coold 8808C, and (accumulator 2, accumulator 4) from the alarm at CB and to not effect RCS 8808D accumulator 3, and RCS. Negligible effect on accumulator pressure depressurization t analogous) accumulator 4) to the safety for system operation. indication and low alarm at RHRS initiation RCS Accumulator 1 (accumulator CB. conditions.

2, accumulator 3 and accumulator 4) is depressurized by opening vent isolation valves 8875A (8875B or 8875C or 8875D) and HCV-943A, or vent isolation valves 8875E (8875F, 8875G or 8875H) and HCV-943B.

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

22. Solenoid Fails to open Provides venting of Failure reduces redundancy Valve open/closed position Same as item 21.

operated globe on demand nitrogen gas from for venting accumulator 1 indication at CB and valve 8875A accumulator 1 (accumulator 2, accumulator accumulator pressure (8875B, 8875C (accumulator 2, 3 and accumulator 4) to indication and low alarm at and 8875D accumulator 3 and containment. No effect on CB.

analogous) accumulator 4) to safety for system operation.

containment Accumulator 1 (accumulator 2, accumulator 3, accumulator 4) can be vented by opening vent valves 8875E (8875F, 8875G and 8875H) and HCV-943B or isolated valve 8808A (8808B, 8808C, 8808D).

23. Solenoid Fails to open Same as item 22 Failure reduces redundancy Same as item 22. Same as item 22.

operated globe on demand for venting accumulator 1 valve 8875E (accumulator 2, accumulator (8875F, 8875G 3 and accumulator 4) to and 8875H containment. No effect on analogous) safety for system operation.

Accumulator 1 (accumulator 2, accumulator 3 and accumulator 4) can be vented by opening vent valves 8875A (8875B, 8875C, and 8875D) and HCV-943A or isolated from the RCS by closing isolation valve 8808A (8808B, 8808C, and 8808D).

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

24. Solenoid Fails to open Provides venting of Venting can be accomplished Valve position indication at Same as item 22.

operated globe on demand nitrogen gas from via HCV-943B, (943A). CB and accumulator valve accumulators to pressure indication and low HCV-943A containment alarm at CB.

(943B analogous)

25. Boric acid Fails to deliver Provides fluid of Failure reduces redundancy Pump motor start relay The boric acid tra transfer pump working concentrated boric of providing concentrated position indication (open) at pumps provide bo pump 1 (pump 2 fluid acid from BAT to boric acid to charging pump CB and local pump flow to the chargi analogous) charging pump suction. Fluid flow from discharge pressure indication pumps suction.

suction boric acid transfer pump 1 PI-113 (PI-114).

(pump 2) will be lost.

Minimum flow requirements for boration will be met by boric acid transfer pump 2 (pump 1).

26. Motor-operated Fails to open Provides isolation of Failure reduces redundancy Valve open/close position The charging pum globe valve 8104 on demand fluid flow from either of providing concentrated indication at CB; and suction is aligned boric acid transfer boric acid to charging pump boration flow indication gravity drain lines pump to charging suction. Negligible effect on (FI-183A) at CB. (8507A/B) for bor pump suction safety for system operation. of the RCS during Concentrated boric acid safety grade cold provided to charging pump shutdown operatio suction through alternate isolation valve 8507A/B.

27. Air operated Fails to open Same as item 26 Same as item 26 Same as item 26 except for Same as item 26.

diaphragm valve on demand flow indication (FT-110).

8439 NOTES:

(1) Components 5, 7, 8, 15 and 21 through 24 are components of the ECCS that perform a safety grade cold shutdown function.

Components 9 through 14, 25, 26, and 27 are components of the CVCS that perform a safety grade cold shutdown function.

Components 16 through 20 are components of the RCS that perform a safety grade cold shutdown function.

Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks (2) List of Acronyms and Abbreviations Auto - Automatic CB - Control board CVCS - Chemical and volume control system ECCS - Emergency core cooling system RC - Reactor coolant RCS - Reactor coolant system RHR - Residual heat removal RHRS - Residual heat removal system RWST - Refueling water storage tank BAT - Boric acid tank VCT - Volume control tank MELB - Moderate energy line break HELB - High energy line break RV - Reactor vessel PRT - Pressurizer relief tank (3) As part of the plant operation; periodic tests, surveillance inspections and instrument calibrations are made to monitor equipment and performance. Failures may be detected during such monitoring of equipment in addition to detection methods noted.

(4) Certain initiating MELB events, postulated to occur in the operating CHS pump suction piping, when combined with a single active failure of the standby CHS pump to start, may lead to a loss of all charging.

For this condition, the SIH pumps will provide the required RCS inventory and boration flow to achieve safe shutdown.

(5) Certain initiating HELB events, postulated to occur in the operating CHS pump discharge piping, when combined with a single active failure of the standby CHS pump to start, may lead to a loss of all charging.

For this condition, the SIH pumps will provide the required RCS inventory and boration flow to achieve safe shutdown.

sign pressure (psig) 2485 sign temperature (F) 680 rge line nozzle diameter (inch) 14 atup rate of pressurizer using heaters only (F/hr) 55 ernal volume (ft3) 1800

psig drostatic test pressure 3107 sign pressure 2485 fety valves (begin to open) 2485 gh pressure reactor trip 2370 wer operated relief valves 2335 (1) gh pressure deviation alarm 2310 (2) ssure spray valves (full open) 2310 (2) ssure spray valve (begin to open) 2260 (2) portional heaters (begin to operate) 2250 (2) erating pressure 2235 portional heater (full operation) 2220 (2) ckup heaters on 2210 (2) w pressure deviation alarm 2210 (2) w pressure reactor trip (typical, but variable) 1885 TE:

At 2335 psig, a pressure signal initiates actuation (opening) of these valves. Remote manual control is also provided.

Actual setpoints will vary depending on M/A station settings and controller response to plant conditions.

RT 1 UT 1 PT 1 MT 1 ads:

Plates yes Cladding yes ell:

Plates yes Cladding yes aters:

Tubing 2 yes yes Centering of element yes zzle (forgings) yes yes 3 yes 3 ldments:

Shell, longitudinal yes yes Shell, circumferential yes yes Cladding yes Nozzle safe end (if forging) yes yes Instrument connection yes Support skirt, longitudinal seam yes yes Support skirt to lower head yes yes Temporary attachments (after removal) yes All external pressure boundary welds after shop hydrostatic yes test TES:

RT - Radiographic UT - Ultrasonic PT - Dye penetrant MT - Magnetic particle UT and ET MT or PT

sign pressure (psig) 100 pture disc release pressure (psig) Nominal: 91 range: 86-100 sign temperature (F) 340 tal rupture disc relief capacity at 100 psig (lb/hr) 1.6 x 106

actor Coolant System 3 Pressurizer safety valves Figure 5.1-1 2 Pressurizer power operated relief valves Figure 5.1-1 sidual Heat Removal System 2 Residual heat removal pump suction line from the Reactor Coolant System Figure 5.4-6 hot legs emical and Volume Control System 1 Seal water return line Figure 9.3-8 1 Letdown line Figure 9.3-8

TABLE 5.4-15 REACTOR COOLANT SYSTEM DESIGN PARAMETERS ign/normal operating pressure (psig) 2485 / 2235 operational plant hydrotest (psig) 3107 ign temperature (F) 650

COOLANT SYSTEM VALVES RT (1) UT (1) PT (1) stings (larger than 4 inches) yes yes (2 inches to 4 inches) yes (2) yes rgings yes (3) yes TES:

RT - Radiographic UT - Ultrasonic PT - Dye penetrant Weld ends only Forged stems UT only

ssurizer Safety Valves Number 3 Maximum relieving capacity, ASME rated flow per valve (lb/hr) 420,000 Set pressure (psig) 2485 Design temperature (F) 650 Fluid Saturated steam ckpressure Normal (psig) 3 to 5 Expected during discharge (psig) 500 ssurizer Power Relief Valves Number 2 Design pressure (psig) 2485 Design temperature (F) 650 Relieving capacity at 2350 psia, minimum per valve (lb/hr) 210,000 Fluid Saturated steam Relieving capacity at 2,438 psia, minimum per valve (lb/hr) 353,880 Fluid Subcooled water

Loading Equipment Loading Category Combinations Stress Limits Codes Steam Generator and App. XVII-2000 and Reactor Coolant Pump Design, Normal & Upset Dead Weight Paragraph NF-3230 Supports

+Thermal ASME Boiler and Pressure Vessel Code,Section III,

+1/2 SSE Subsection NF 1974 Edition Faulted Dead Weight App. F-1370 through 1974 Winter Addenda

+SSE

+Pipe rupture ASME Boiler and Pressure App. XVII-2000 and Design, Normal & Upset Dead Weight Vessel Code,Section III, Paragraph NF-3230 Subsection NF 1974 Edition

+Thermal Pressurizer Supports +1/2 SSE Faulted Dead Weight App. F-1370

+SSE

+Pipe rupture

Loading Equipment Loading Category Combinations Stress Limits Codes App. XVII-2000 and Dead Weight Paragraph NF-3230 for linear type supports Paragraph NF-3220 for Design, Normal & Upset +Initial plate and shell type Pressurization supports

+Thermal ASME Boiler and Pressure RPVSS +1/2 SSE Vessel Code,Section III, (Neutron Shield Tank) App. F-1323.1 for plate Subsection NF 1974 Edition Faulted Dead Weight and shell type supports including 1974 Summer Adde App. F-1370 for linear

+SSE type supports

+Pipe rupture

+Initial and Asymmetric Pressurization

ABLE 5.4-19 REACTOR VESSEL HEAD VENT SYSTEM EQUIPMENT DESIGN PARAMETERS ves Number of remote valves (6 solenoid, 1 motor operated) 7 Design pressure (psig) 2485 Design temperature (F) 650 Maximum operating temperature (F) 620 ng Vent line, nominal diameter (in) 1 Design pressure (psig) 2485 Design temperature (F) 650 Maximum operating temperature (F) 620

al leakoff for flowserve seals will now be located 45 degrees CCW from the second stage et pressure connections.

CONTAINMENT RECIRCULATION figure indicated above represents an engineering controlled drawing that is Incorporated by erence in the MPS-3 FSAR. Refer to the List of Effective Figures for the related drawing ber and the controlled plant drawing for the latest revision.

Mode A Initiation of Residual Heat Removal System Operation s mode presents the process flow conditions for the initiation of RHS operation. This begins second phase of plant cooldown, when the reactor coolant temperature and pressure have been uced to 350°F and 375 psig by use of the steam generators, transferring heat to the secondary

. During Mode A operation, one RHS loop is aligned for RCS cooldown and the second loop ains aligned for safety injection (RWST to RHS connection is not shown in Figure 5.4-6).

residual heat removal subsystem takes suction from its respective RCS hot leg, discharging ugh the heat exchanger with the return flow routed to the RCS cold legs. During the initial ses of RHS operation, reactor coolant flow through the heat exchangers is manually limited to trol the rate of heat removal. The total flow is automatically regulated by flow control valves he heat exchanger bypass lines to maintain a constant total return flow. The heat removal rate mited to both control the RCS cooldown rate to 100°F/hr, based on equipment stress siderations, and to limit component cooling water temperature to a maximum of 145°F.

ing this initial phase of RHS operation, one or two reactor coolant pumps are maintained in ration. This results in a slight RHS return flow imbalance between the four RCS cold legs due heir different operating pressures. In the data presented, reactor coolant pump Number 2 is med operating.

Mode B Initiation of Second Residual Heat Removal Loop s mode presents the process flow conditions once the reactor coolant temperature has been uced to < 260°F. The second RHS loop is aligned to take suction from its respective RCS hot discharging through the heat exchanger with return flow routed to the RCS cold legs.

Mode C End Conditions of Normal Cooldown 140°F s mode presents the process flow conditions for the completion of RHS operation, refer to tion 5.4.7.2.3.4 for normal cooldown time details.

flow distribution of this mode, maintains RCS core cooling by controlling reactor coolant through the heat exchangers with bypass flow adjustments.

ctor coolant pump operation has also been terminated at this time, with all RCS cold legs in ilibrium.

ODE A INITIATION OF SINGLE TRAIN RESIDUAL HEAT REMOVAL SYSTEM OPERATION Flow Pressure Temperature ocation Fluid (psig) (°F) (gpm) (lb/hr) 1 RC 375 350 4186 1.86E + 6 2 RC 372 350 4186 1.86E + 6 3 RC 481 350 4186 1.86E + 6 4 RC 488 350 1176 5.24E + 5 5 RC 488 109 1057 5.24E + 5 6 RC 434 283 4005 1.86E + 6 7 RC 372 350 Note 1 8 RC 482 350 2992 1.33E + 6 9 RC 426 283 4005 1.83E + 6 10 RC 428 283 0 11 RC - - 0 12 RC N/A N/A 0 0 13 RC N/A N/A 0 0 14 RC N/A N/A 0 0 15 RC N/A N/A 0 0 16 RC N/A N/A 0 0 17 RC N/A N/A 0 0 18 RC N/A N/A 0 0 19 RC N/A N/A 0 0 20 RC N/A N/A 0 0 21 RC N/A N/A 0 0 TES:

Miniflow continues until flow at location 3 is greater than approximately 1,633 gpm. The miniflow is then closed.

The RCS cold leg distribution is a result of operating reactor coolant pump number 2 during this phase of RHR operation.

MODE B INITIATION OF SECOND RESIDUAL HEAT REMOVAL LOOP Flow Pressure Temperature ocation Fluid (psig) (°F) (gpm) (lb/hr) 1 RC 375 260 4120 1.93E + 6 2 RC 372 260 4120 1.93E + 6 3 RC 492 260 4120 1.93E + 6 4 RC 499 260 2016 9.47E + 5 5 RC 498 124 1915 9.47E + 5 6 RC 433 194 4002 1.93E + 6 7 RC 372 260 0 0 8 RC 492 260 2104 9.88E + 5 9 RC 426 194 4002 1.93E + 6 10 RC 428 194 0 0 11 RC - - 0 0 12 RC 375 260 4120 1.93E + 6 13 RC 374 260 4120 1.93E + 6 14 RC 496 260 4120 1.93E + 6 15 RC 503 260 1836 8.62E + 5 16 RC 502 127 2284 8.62E + 6 17 RC 428 201 4012 1.93E + 6 18 RC 374 260 2284 1.07E + 6 19 RC 497 260 0 0 20 RC 422 201 4012 1.93E + 6 21 RC 423 201 0 0

MODE C END CONDITIONS OF NORMAL COOLDOWN 140°F Flow Pressure Temperature ocation Fluid (psig) (°F) (gpm) (lb/hr) 1 RC 0/Note 1 140 2950 1.45E + 06 2 RC 0 140 2950 1.45E + 06 3 RC 147 140 2950 1.45E + 06 4 RC 153 140 2950 1.45E + 06 5 RC 152 101 2921 1.45E + 06 6 RC 34 101 2921 1.45E + 06 7 RC 0 140 0/Note 2 0/Note 2 8 RC 148 140 0 0 9 RC 34 101 2921 1.45E + 06 10 RC 33 101 0 0 11 RC - - 0 0 12 RC 0/Note 1 140 2950 1.45E + 06 13 RC 0 140 2950 1.45E + 06 14 RC 147 140 2950 1.45E + 06 15 RC 154 140 2950 1.46E + 06 16 RC 148 99 2920 1.46E + 06 17 RC 34 99 2920 1.45E + 6 18 RC 0 140 0 0 19 RC 149 140 0/Note 2 0/Note 2 20 RC 33 99 2920 1.45E + 6 21 RC 32 99 2920 0 TES:

RCS is assumed depressurized with the water level drained to the centerline of reactor coolant piping.

Conservative design assumptions presume that the bypass line is isolated; during normal cooldown operations, the bypass line is typically open.

RHRS VALVE ALIGNMENT CHART Operational Mode Valve Number A B C 1 O O O 2 O O O 3 C C C 4 O* O* O*

5 O* O* O*

6 C C C 7 C C C 8 C O O 9 C O O 10 O* O* O*

11 O C C 12 O* O* O*

13 C C C 14 O O O 15 C O O TES:

Open Closed Partially open lve disc partially closed by means of a permanent "Travel Limiter" on valve actuator.

AND STEAM GENERATOR