ML17212A074

Final Safety Analysis Report, Rev. 30, Chapter 5, Reactor Coolant System and Connected Systems

ML17212A074
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Site:	Millstone
Issue date:	06/29/2017
From:	Dominion Nuclear Connecticut
To:	Office of Nuclear Reactor Regulation
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{{#Wiki_filter:Millstone Power Station Unit 3 Safety Analysis Report Chapter 5

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 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 5-i Rev. 30

tion Title Page 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 Identified Leakage .................................................................................... 5.2-24 5.1.1 Definition of Identified Leakage............................................................... 5.2-24 5.1.2 Collection and Monitoring of Identified Leakage .................................... 5.2-24 5.1.3 Controlled Leakage................................................................................... 5.2-25 5.2 Unidentified Leakage................................................................................ 5.2-26 5.2.1 Definition of Unidentified Leakage .......................................................... 5.2-26 5.2.2 Collection of Unidentified Leakage.......................................................... 5.2-26 5.2.3 Detection of Unidentified Leakage........................................................... 5.2-26 5.2.4 Leakage Detection Method Sensitivity and Response Times................... 5.2-27 5.2.5 Leakage Detection Method Indicators and Alarms .................................. 5.2-27 5.2.6 Seismic Capability of Leakage Detection Methods.................................. 5.2-28 5.2.7 Testing and Calibration............................................................................. 5.2-28 5.3 Intersystem Leakage ................................................................................. 5.2-28 5.4 Technical Specifications ........................................................................... 5.2-31 5.5 Primary Coolant Sources Outside Containment ....................................... 5.2-31 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 5-ii Rev. 30

tion Title Page 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 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 .............................................................................................. 5.4-7 1.3.5 Critical Speed.............................................................................................. 5.4-7 1.3.6 Missile Generation ...................................................................................... 5.4-7 1.3.7 Pump Cavitation ......................................................................................... 5.4-7 5-iii Rev. 30

tion Title Page 1.3.8 Pump Overspeed Considerations ................................................................ 5.4-8 1.3.9 Anti-Reverse Rotation Device .................................................................... 5.4-8 1.3.10 Shaft Seal Leakage...................................................................................... 5.4-8 1.3.11 Seal Discharge Piping ................................................................................. 5.4-9 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 Cool-ants ............................................................................................................ 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..................................................................................... 5.4-15 2.6 Quality Assurance..................................................................................... 5.4-17 3 Reactor Coolant Piping ............................................................................. 5.4-18 3.1 Design Bases............................................................................................. 5.4-18 3.2 Design Description ................................................................................... 5.4-18 3.3 Design Evaluation..................................................................................... 5.4-21 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 ................................................................................ 5.4-22 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 ................................................................................ 5.4-23 5 Main Steam Isolation System ................................................................... 5.4-23 6 Reactor Core Isolation Cooling System.................................................... 5.4-23 7 Residual Heat Removal System................................................................ 5.4-23 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...................................................................................... 5.4-29 7.2.4 Control ...................................................................................................... 5.4-34 7.2.5 Applicable Codes and Classifications....................................................... 5.4-35 7.2.6 System Reliability Considerations............................................................ 5.4-35 5-iv Rev. 30

tion Title Page 7.2.7 Manual Actions......................................................................................... 5.4-37 7.3 Performance Evaluation............................................................................ 5.4-38 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 .............................................................................. 5.4-39 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................................................................................................. 5.4-40 10.3 Design Evaluation..................................................................................... 5.4-41 10.3.1 System Pressure ........................................................................................ 5.4-41 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 .................................................................. 5.4-44 11 Pressurizer Relief Discharge System ........................................................ 5.4-44 11.1 Design Basis ............................................................................................. 5.4-44 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 ................................................................................... 5.4-47 12.3 Design Evaluation..................................................................................... 5.4-47 12.4 Tests and Inspections ................................................................................ 5.4-48 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................................................................................. 5.4-50 14.1 Description................................................................................................ 5.4-50 14.1.1 Reactor Vessel Structural Support (RVSS) .............................................. 5.4-50 5-v Rev. 30

tion Title Page 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 ............................................................................................. 5.4-52 14.3 Evaluation ................................................................................................. 5.4-52 14.4 Tests and Inspections ................................................................................ 5.4-53 15 Reactor Vessel Head Vent System ........................................................... 5.4-53 15.1 Design Basis ............................................................................................. 5.4-53 15.2 System Description ................................................................................... 5.4-54 15.3 Safety Evaluation ...................................................................................... 5.4-55 15.4 Inspection and Testing Requirements....................................................... 5.4-55 15.5 Instrumentation Requirements .................................................................. 5.4-55 16 References for Section 5.4 ........................................................................ 5.4-55 5-vi Rev. 30

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 5-vii Rev. 30

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 5-viii Rev. 30

List of Figures mber Title 1 (Sheets 1-63) P&IDs Reactor Coolant System -2 Reactor Coolant System Process Flow Design Notes to Figure 5.1-2: Mode A Steady State Full Power Operation -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 5 (Sheets 1-3) P&IDs Low Pressure Safety Injection / Containment Recirculation 6 Residual Heat Removal System Process Flow Diagram (Mode A) Notes to Figure 5.4-6: Mode A Initiation of Residual Heat Removal System Operation 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 15 Pressurizer Safety Valve Support System 5-1 Rev. 30

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 5.1-1 Rev. 30

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 5.1-2 Rev. 30

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, 5.1-3 Rev. 30

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.

5.1-4 Rev. 30

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 5.1-5 Rev. 30

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. 5.1-6 Rev. 30

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) SS Power (MWt) 3,666 3,666 actor Power (MWt) 3,650 3,650 ermal Design Flows (gpm) Active Loop (c) 90,800 90,800 Reactor 363,200 363,200 tal Reactor Flow (106 lb/hr) 135.3 136.9 mperatures (°F) Reactor Vessel Outlet 622.6 615.1 Reactor Vessel Inlet 556.4 547.9 Steam Generator Outlet 556.0 547.6 Steam Generator Steam 537.4 531.2 Feedwater 445.3 445.3 eam Pressure (psia) 942 894 tal Steam Flow (106 lb/hr) 16.29 16.25 st Estimate Flows (gpm) Active Loop 97,300 99,700 Reactor 389,200 398,800 5.1-7 Rev. 30

System Thermal and Hydraulic Data (a) (b) 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 589.5°F. Parameters based on full power operation with 0% equivalent steam generator tube plugging and reactor vessel average temperature of 581.5°F. 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. 5.1-8 Rev. 30

FIGURE 5.1-1 (SHEETS 1-63) 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. 5.1-9 Rev. 30

MPS-3 FSAR FIGURE 5.1-2 REACTOR COOLANT SYSTEM PROCESS FLOW DIAGRAM LOOP 3 REACTOR REACTOR COOLANT COOLANT PRESSURIZER PUMP PUMP 42 REACTOR COOLANT PUMP LOOP 4 STEAM STEAM GENERATOR GENERATOR FIGURE 5.1-2 REACTOR COOLANT SYSTEU PROCESS FLOW DIAGRAM NOTES: MILLSTONE NUCLEAR POWER STATION THIS DIAGRAM IS A SIMPLIFICATION OF THE SYSTEM INTENDED TO UNIT 3 FACILITATE THE UNDERSTANDING OF THE PROCESS. FOR DETAILS OF cll~Al SAFETY ANALYSIS REPORT THE PIPING, VALVES, INSTRUMENTATION, ETC. REFER TO THE ENGINEERING FLOW DIAGRAM. REFER TO PROCESS FLOW DIAGRAM NnV~MRFR lGR7 TABLES FOR THE CONDITIONS AT EACH NUMBERED POINT. November 1987 Rev. 20.2

MPS-3 FSAR NOTES TO FIGURE 5.1-2 Mode A Steady State Full Power Operation Flow (1) Location 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 - 10-18 R.C. See Loop No. 1 Specifications 19-27 R.C. See Loop No. 1 Specifications 28-36 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 - Page 1 of 2 Rev. 16

MPS-3 FSAR NOTES TO FIGURE 5.1-2 Mode A Steady State Full Power Operation Flow (1) Location Fluid Pressure psig Temperature °F GPM (2) lb/hr (3) Volume 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 - - 450 51 PRT Water 3.0 120.0 - - 1350 (1) Flows measured at 130°F and 2300 psia. (2) At the conditions specified (3) x 106 Page 2 of 2 Rev. 16

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 Table 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 5.2-1 Rev. 30

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, Rev. 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. 5.2-2 Rev. 30

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 102 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. 5.2-3 Rev. 30

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 5.2-4 Rev. 30

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 on ure 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. 5.2-5 Rev. 30

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 Section 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. 5.2-6 Rev. 30

ssure Transient Analyses ME Section III, Appendix G, establishes guidelines and upper limits for RCS pressure arily for low temperature conditions ( 350°F). The mitigation system (Section 5.2.2.11) sfies these conditions at temperatures 226°F, 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 50°F 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 5.2-7 Rev. 30

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 5.2-8 Rev. 30

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 160°F.

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 5.2-9 Rev. 30

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 specifications d for the reactor internals required for emergency core cooling, for any mode of normal ration or under postulated accident conditions, and for core structural load bearing members 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. 5.2-10 Rev. 30

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. 5.2-11 Rev. 30

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 60°F 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 120°F. 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. 5.2-12 Rev. 30

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.

stinghouse 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 5.2-13 Rev. 30

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 270°F 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. 5.2-14 Rev. 30

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 5.2-15 Rev. 30

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.

stinghouse recognizes that the heat affected zones of welded component must, of necessity, be ted into the sensitization temperature range, 800°F to 1500°F. 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 350°F 5.2-16 Rev. 30

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 800°F to 1,500°F 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 stinghouse 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 800°F to 1,500°F during fabrication into components. If, during the course abrication, the steel is inadvertently exposed to the sensitization temperature range, 800°F to 0°F, 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 800°F to 1,500°F for less than 1 hour

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.

5.2-17 Rev. 30

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. 5.2-18 Rev. 30

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 52. 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. 5.2-19 Rev. 30

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 5.2-20 Rev. 30

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.

5.2-21 Rev. 30

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 5.2-22 Rev. 30

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. 5.2-23 Rev. 30

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 Identified Leakage 5.1.1 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 5.1.2 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 operated relief valves. High temperature or flow actuates an alarm in the control room. These valves discharge to the pressurizer relief tank (Section 9.3.3). Level indication and high level alarm are provided in the control room.

5.2-24 Rev. 30

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.

5.1.3 Controlled Leakage

1. Controlled leakage consists of seal water flow supplied to the reactor coolant pump seals.

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

5.2-25 Rev. 30

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.

d. Increasing level in the containment drains transfer tank: indication and alarm in control room.

5.2 Unidentified Leakage 5.2.1 Definition of Unidentified Leakage dentified leakage is all leakage which is not identified leakage. 5.2.2 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. 5.2.3 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. 5.2-26 Rev. 30

5.2.4 Leakage Detection Method Sensitivity and Response Times sitivity and response times for leakage detection methods 1 through 4, Subsection 5.2.5.2.3, as follows:

1. Unidentified leakage sump level and sump pump instrumentation Sump level change and sump pump run time are utilized to determine the rate of flow of unidentified leakage into the sump. This detection method is capable of 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.

5.2.5 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 5.2-27 Rev. 30

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

             #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.

2. Containment airborne particulate and gaseous radioactivity 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.

5.2.6 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). 5.2.7 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 5.3 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:

5.2-28 Rev. 30

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.

2. Secondary side of reactor coolant pump thermal barrier 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 5.2-29 Rev. 30

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 emergency core cooling flow path within approximately 30 minutes in the ESF Building and within approximately 1 hour for leaks in the Auxiliary Building (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). 5.2-30 Rev. 30

er to Millstone Unit 3 for Technical Specifications for applicable RCPB leakage detection hods. 5.5 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. endix J to 10 CFR 50 addresses leak rate testing which must be performed not only on the tainment structure but also on the systems which penetrate the containment barrier and are 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. 5.2-31 Rev. 30

ntory 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. 6 REFERENCES FOR SECTION 5.2 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. 5.2-32 Rev. 30

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.) 12 Youngblood, B.J., Use of ASME Code Case N-407 for Millstone Nuclear Power Station, Unit 3, Letter dated 2/12/85 for Docket No. 50-423 to W. G. Counsil of Northeast 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. 5.2-33 Rev. 30

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 5.2-34 Rev. 30

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 5.2-35 Rev. 30

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 5.2-36 Rev. 30

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 5.2-37 Rev. 30

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 5.2-38 Rev. 30

rgings SA-182, Type F304 and F304H, or Type 403 per Westinghouse Procedure 80280NL tes SA-240, Type 304 es ASTM A-358, Grade 304, Class 1, SA358 Grade 304 Class 1 bes SA-213, Type 304; SA249 Grade TP304; ASTM A-511, MT 304; and ASTM A-554, MT 304 rs SA-479, Type 304 and 316; ASTM A-276, 304 and SB-166 stings SA-351, Gr. CF8 lting SA-193, Gr. B8M Code Case 1618, Inconel 750 SA-637, Gr. 688 Type 2; SA-479, Type 316, Strain Hardened (Code Case 1618) ts SA-194, Gr. 8 or 8A; SA-479, Type 304 and SA-637, Grade 688, Type 2 cking devices SA-479, Type 304, 304L or Type 316, SA-240, Type 304, ASTM A-240, Type 304; and ASTM B-166 ld buttering ER 308, ER 308L, E308-15, E308L-15, E308T-3 5.2-39 Rev. 30

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 60 S/cm at 25°C. 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 25°C; 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 250°F by scavenging with hydrazine. During power operation with the specified hydrogen concentration maintained in the coolant, the residual oxygen concentration control value becomes 0.005 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. 5.2-40 Rev. 30

LOADS (KIPS, INCH) CONDITION Fx Fy Fz Mx My Mz AD WEIGHT 0 7 0 0 0 0 (5) a (20) (5) (100) (1) (32) ERMAL 18 33 10 135 0 243 b (20) (75) (20) (523) (5) (135) ISMIC 1/2 SSE 2 12 11 150 0 27 (20) (30) (20) (390) (2) (134) ISMIC SSE 2 27 14 190 0 27 (35) (50) (35) (645) (2) (235) LVE OPER. (OCCASIONAL) 1 14 5 70 0 14 (30) (100) (30) (560) (2) (204) ULTED CONDITION 18 277 92 1246 0 244 (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. 5.2-41 Rev. 30

Mark Number Service Location 3CCE*RV40A&B Charging Pump Cooler Relief Valves Auxiliary Building 3CCE*RV43A-C Cooler Relief Valves Auxiliary Building 3CCI*RV31A&B Safety Injection Pump Cooler Relief ESF Building Valves 3CCI*RV36A&B Cooler Relief Valves ESF Building 3CCP*RV39 Excess Letdown Heat Exchanger Relief Containment Valve 3CCP*RV54A-D Reactor Coolant Pump Thermal Barrier 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 3CCP*RV258A-D Reactor Coolant Pump Upper Bearing 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 3CHS*RV7006 Letdown Reheat Heat Exchanger Relief Auxiliary Building Valve 3CHS*RV8119 Letdown to Low Pressure 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 3CHS*RV8124 Charging Pump Suction Header Relief 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 5.2-42 Rev. 30

Mark Number Service Location 3FWS*RV47A-D 3FWS*CTV41A-D Bonnet Relief 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 RHR Pump Suction Relief Valves Containment HS*RV8708A&B 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 3SIL*RV8856A&B RHR Pumps Safety Injection Line 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 5.2-43 Rev. 30

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 5.2-44 Rev. 30

MPS-3 FSAR FIGURE 5.2-1 REACTOR VESSEL INSPECTION AREA FLANGE TO UPPER SHELL OUTLET NOZZLE TO CIRCULAR WELD SHELL WELD (TYP. OF 4) INLET NOZZLE TO SHELL WELD (TYP. OF 4) UPPER SHELL UPPER TO INTERMEDIATE SHELL LONGITUDINAL WELD CIRCULAR WELD (TYP. OF 3) INTERMEDIATE SHELL LONGITUDINAL WELD (TYP. OF 3) LOWER TO INTERMEDIATE SHELL CIRCULAR WELD LOWER SHELL LONGITUDINAL WELDS (TYP. OF 3) LOWER HEAD TO SHELL WELD LOWER HEAD MERIDIONAL WELDS (TYP. OF 4) LOWER HEAD DISC TO LOWER RING CIRCULAR WELD September 1997 Rev. 20.2

MPS-3 FSAR FIGURE 5.2-2 MODEL F STEAM GENERATOR INSPECTION AREA

                                                " ' - - - - - STEAM OUTLET W/FLOW
                                .-"'::;;;.---,-.-I--';;;;~         R ESTRIC TOR fEEDWATER INL£ T lCLASS 2
                                                           ~CHANNEL          HEAD TO TUBE CLASS 1                                               SHEET CIRCUMFERENTtAL WELD
                                                         ----- PRIMARY MANWA,"S PR 1M ARY COOLANT                                           sTues E. NUTS NOZZLE t INLET t-OUTLET) TO SHELL WELDS                                          FIGURE 5.2-2 MODEL F STEAM GENERATOR INLET & OUTlET OOZZLE                   INSPECTION AREA INNER RADIUS                            MILLSTONE NUCLEAR POWER STATION UNIT 3 FINAL SAFETY A NALYSJS REPORT SEPTEMBER 1997 September 1997                                           Rev. 20.2

MPS-3 FSAR FIGURE 5.2-3 PRESSURIZER INSPECTION AREAS RELIEF. SPRAY AND SAFETY NOZZLE INNER RADIUS (5 TYP) UPPER HEAD TO SHELL WELD ----~ UPPER SHELL COURSE LONGITUDINAL WELD ~ o ("') UPPER SHELL TO UPPER INTERMEDIATE SHELL WELD UPPER INTERMEDIATE LONGITUDINAL WELD UPPER INTERMEDIATE SHELL TO LOwER INTERMEDIATE SHELL WELD _----~~--.1 LOWER INTERMEDIATE LONGITUDINAL WELD ----t--_ -(1'1 ID co N LOWER INTERMEDIATE SHELL TO LOWER SHELL WELD - - - - - LOWER SHELL COURSE LONGITUDINAL WELD ---t---__ LOWER HEAD TO SHELL WELD - - - - _

                           '"' \                           .....

J I'

                                 \.                     /
                                    "- ,             ,/
                                         -,     ,,-/
                                            \ I SURGE l\OZZLE INNER RADIUS December 1997                                   Rev. 20.2

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. 5.3-1 Rev. 30

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 (400°F minimum) post weld heat treatment is applied for 4 hours, 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 5.3-2 Rev. 30

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.

5.3-3 Rev. 30

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. 5.3-4 Rev. 30

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) (579°F melting point). 97.5 percent lead (Pb), 1.75 percent silver (Ag), 0.75 percent tin (Sn) (590°F 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. 5.3-5 Rev. 30

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 100°F, ASTM E185-82 requires that the program contain a 5.3-6 Rev. 30

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 5.3-7 Rev. 30

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 j - t d N 0 FY --- --------- C j [ 1 - e ]e 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) 5.3-8                                Rev. 30

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 5.3-9 Rev. 30

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 5.3-10 Rev. 30

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. 5.3-11 Rev. 30

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. 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-5.3-12 Rev. 30

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: 5.3-13 Rev. 30

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 25 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 5.3-14 Rev. 30

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 100°F 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 Section 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 5.3-15 Rev. 30

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 5.3-16 Rev. 30

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. 5.3-17 Rev. 30

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.

5.3-18 Rev. 30

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. 5.3-19 Rev. 30

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 5.3-20 Rev. 30

5.3-21 Rev. 30 Avg. Upper Shelf NMWD MMWD Component Code No. Grade Cu (%) N (%) T (°F) RT (°F) (ft-lb) (ft-lb) 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 89.0 Inter, Shell B9805-2 A533B, CL. 1 0.05 0.64 -60 6.2 90.0 70.7 Inter, Shell B9805-3 A533B, CL. 1 0.05 0.65 -40 -3.3 106.3 136.5 5.3-22 Rev

Avg. Upper Shelf NMWD MMWD Component Code No. Grade Cu (%) N (%) T (°F) RT (°F) (ft-lb) (ft-lb) Lower Shell B9820-1 A533B, CL. 1 0.08 0.63 -50 7.0 76.7 124.5 Lower Shell B9820-2 A533B, CL. 1 0.07 0.60 -30 38.8 75.7 114.5 Lower Shell B9820-3 A533B, CL. 1 0.06 0.61 -30 18.6 79.3 124.0 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 5.3-23 Rev

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. 5.3-24 Rev. 30

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 n/cm2 F=Fluence (E 1 MeV)10 at Expiration Date at Location 54 EFPY 54 EFPY se Plate (B9805-1) 2.70 133 ld 2.70 30 5.3-25 Rev. 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 5.3-26 Rev. 30

MPS-3 FSAR FIGURE 5.3-1 IDENTIFICATION AND LOCATION OF BELTLINE REGION MATERIAL FOR THE REACTOR VESSEL 90° 101-124A B9805-1 B9805-2 INTERMEDIATE SHELL 0° 180° 101-124C 101-124B B9805-3 270° CORE 101-171 90° 101-142A B9820-3 B9820-1 LOWER SHELL 0° 180° 101-142C 101-142B B9820-2 270° Rev. 20.2

MPS-3 FSAR FIGURE 5.3-2 REACTOR VESSEL CONTROL ROD VENT PIPE MECHANISM HOUSING COOLING DUCT LIFTING LUG SUPPORT RING CLOSURE STUD, NUT & WASHER MONITOR TUBE INLET NOZZLE OUTLET NOZZLE CORE SUPPORT LUG INSTRUMENTATION TUBE June 1997 Rev. 20.2

MPS3 UFSAR 5.4 COMPONENT AND SUBSYSTEM DESIGN 5.4.1 REACTOR COOLANT PUMPS 5.4.1.1 Pump Flywheel Integrity The integrity of the reactor coolant pump flywheel is assured on the basis of the following design and quality assurance procedures. 5.4.1.1.1 Design Bases The calculated stresses at operating speed are based on stresses due to centrifugal forces. The stress resulting from the interference fit of the flywheel on the shaft is less than 2,000 psi at zero speed, but this stress becomes zero at approximately 600 rpm because of radial expansion of the hub. The reactor coolant pumps run at approximately 1,190 rpm and may operate briefly at overspeeds up to 109 percent (1,295 rpm) during loss of off site electrical power. For conservatism, however, 125 percent of operating speed was selected as the design speed of the reactor coolant pumps. The flywheels are given a preoperational test of 125 percent of the maximum synchronous speed of the motor. 5.4.1.1.2 Fabrication and Inspection The flywheel consists of two thick plates bolted together. The flywheel material is produced by a process that minimizes flaws in the material and improves its fracture toughness properties (i.e., an electric furnace with vacuum degassing). Each plate is fabricated from SA-533, Grade B, Class 1 steel. Supplier certification reports are available for all plates and demonstrate the acceptability of the flywheel material on the basis of the requirements of NRC Regulatory Guide 1.14. Flywheel blanks are flame-cut from the SA-533, Grade B, Class 1 plates, with at least 0.5 inch of stock left on the outer surface and bore surface for machining to final dimensions. The finished machined bores, keyways, and drilled holes are subjected to magnetic particle or liquid penetrant examinations in accordance with the requirements of Section III of the ASME Code. The finished flywheels, as well as the flywheel material (rolled plate), are subjected to 100 percent volumetric ultrasonic inspection using procedures and acceptance standards specified in Section III of the ASME Code. The reactor coolant pump motors are designed such that, by removing the cover to provide access or by removing the flywheel from the pump motor shaft, the flywheel is available to allow an inservice inspection program. For a description of inservice inspection of the flywheels, refer to the MP3 ISI Program. 5.4.1.1.3 Material Acceptance Criteria The reactor coolant pump motor flywheel conforms to the following material acceptance criteria: 5.4-1 Rev. 30

MPS3 UFSAR

1. The nil-ductility transition temperature (NDTT) of the flywheel material is obtained by two drop weight tests (DWT) which exhibit no-break performance 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 10°F.

2. A minimum of three Charpy V-notch (C) impact specimens from each plate shall be tested at ambient (70°F) 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 70°F and, therefore, the flywheel material has a reference nil-ductility temperature (RT) of 10°F. An evaluation of flywheel overspeed has been performed which concludes that flywheel integrity will be maintained (WCAP-8163, 1973).

Thus, it is concluded that flywheel plate materials are suitable for use and can meet Regulatory Guide 1.14 acceptance criteria on the basis of suppliers certification data. The degree of compliance with Regulatory Guide 1.14 is further discussed in Section 1.8. 5.4.1.2 Reactor Coolant Pump Assembly 5.4.1.2.1 Design Bases The reactor coolant pump assembly ensures an adequate core cooling flow rate for sufficient heat transfer to maintain a departure from nucleate boiling ratio (DNBR) greater than 1.30 within the parameters of operation. The required net positive suction head is, by conservative pump design, always less than that available by system design and operation. Sufficient pump assembly rotational inertia is provided by a motor flywheel, motor rotor, and pump rotating parts which provide adequate flow during coastdown conditions. This forced flow following an assumed loss of off site electrical power and the subsequent natural circulation effect provides the core with adequate cooling. The reactor coolant pump motor is tested, without mechanical damage, at overspeeds up to and including 125 percent of normal speed. The integrity of the flywheel during a loss-of-coolant accident (LOCA) has been demonstrated and is undergoing generic review by the NRC (WCAP-8163, 1973). The reactor coolant pump is shown on Figure 5.4-1. The reactor coolant pump design parameters are given in Table 5.4-1. Code and material requirements are provided in Section 5.2. 5.4.1.2.2 Pump Assembly Description Design Description The reactor coolant pump is a vertical, single-stage, controlled leakage, centrifugal pump designed to pump large volumes of reactor coolant at high temperatures and pressures. 5.4-2 Rev. 30

MPS3 UFSAR The pump assembly consists of three major sections: the hydraulics, the seals, and the motor.

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.

Additional components of the pump are the shaft, pump radial bearing, thermal barrier heat exchanger assembly, coupling, spool piece, and motor stand. Description of Operation The reactor coolant enters the suction nozzle, is pumped by the impeller through the diffuser, and exits through the discharge nozzle. The diffuser adapter limits the leakage of reactor coolant back to the suction. Seal injection flow, under slightly higher pressure than the reactor coolant, enters the pump through a connection on the thermal barrier flange and is directed into the plenum between the thermal barrier housing and the shaft. The flow splits with the major portion flowing down the shaft through the radial bearing and into the reactor coolant system. The remaining seal injection flow passes up the shaft through the seals. Component cooling water (Section 9.2.2.1) is provided to the thermal barrier heat exchanger. During normal operation, the thermal barrier limits the heat transfer from hot reactor coolant to the radial bearing and to the seals. In addition, if a loss of seal injection flow should occur, the thermal barrier heat exchanger cools the reactor coolant to an acceptable level before it enters the bearing and seal area. The reactor coolant pump motor oil lubricated bearings are of conventional design. The radial bearings are the segmented pad type, and the thrust bearing is a double-acting Kingsbury type. Component cooling water is supplied to the external upper bearing oil cooler and to the integral lower bearing oil cooler. Each RCP motor is equipped with an oil collection system to mitigate the consequences of oil leaks. Section 9.5.11 describes this system in detail. 5.4-3 Rev. 30

MPS3 UFSAR The motor is a drip-proof, squirrel-cage, induction motor with Class B thermalastic epoxy insulation, and fitted with external water/air coolers. The rotor and stator are of standard construction and are cooled by air. Six resistance temperature detectors are embedded in the stator windings to sense stator temperature. A flywheel and an anti-reverse rotation device are located at the top of the motor. The internal parts of the motor are cooled by air. Integral vanes on each end of the rotor draw air in through cooling slots in the motor frame. This air passes through the motor with particular emphasis on the stator end turns. It is then routed to the external water/air heat exchangers, which are supplied with chilled water (Section 9.2.2.2). Each motor has two such coolers, mounted diametrically opposed to each other. Coolers are sized to maintain optimum motor operating temperature. The air is finally exhausted to the containment environment. Each of the reactor coolant pump assemblies is equipped for continuous monitoring of reactor coolant pump shaft and frame vibration levels. Shaft vibration is measured by two relative motion shaft probes mounted on top of the pump seal housing; the probes are located 90 degrees apart in the same horizontal plane and mounted near the pump shaft. Frame vibration is measured by two velocity seismoprobes located 90 degrees apart in the same horizontal plane and mounted at the top of the motor support stand. Proximeters and converters linearize the probe output which is displayed on monitor meters in the control room. The monitor meters automatically indicate the highest output from the relative probes and seismoprobes; manual selection allows monitoring of individual probes. Indicator lights display caution and danger limits of vibration. The spool piece, a removable shaft segment, is located between the motor coupling flange and the pump coupling flange. The spool piece allows removal of the pump seals with the motor in place. The pump internals, motor, and motor stand can be removed from the casing without disturbing the reactor coolant piping. The flywheel is available for inspection by removing the cover. All parts of the pump in contact with the reactor coolant are austenitic stainless steel except for seals, bearings, and special parts. 5.4.1.3 Design Evaluation 5.4.1.3.1 Pump Performance The reactor coolant pumps are sized to deliver flow at rates which equal or exceed the required flow rates. Initial RCS tests confirm the total delivery capability. Thus, assurance of adequate forced circulation coolant flow is provided prior to initial plant operation. The estimated performance characteristics are shown on Figure 5.4-2. The knee, at approximately 25 percent design flow, introduces no operational restrictions, since the pumps only operate at a speed which corresponds to full flow. The reactor trip system ensures that pump operation is within the assumptions used for loss-of-coolant flow analyses, which also assures that adequate core cooling is provided to permit an orderly reduction in power if flow from a reactor coolant pump is lost during operation. 5.4-4 Rev. 30

MPS3 UFSAR Major parameters influencing the seal environment which can effect seal life include axial and radial shaft motions, radial shaft vibrations, temperature, pressure, oxidizing water chemistry, the presence of particulates, and pump start/stop cycles. The sealing system has demonstrated through design, testing, and field operation to be capable of withstanding all specified operating conditions. The seal cartridge uses three identical seal stages based on hydrodynamic operating principles. The critical parts of each seal stage are the rotating face ring, stationary face ring, and secondary seals. A secondary seal O-ring is used to isolate stage pressures and provides a sliding secondary seal between the stationary ring and the balance sleeve. This arrangement eliminates the requirement for a flat surface to support the stationary ring. The stationary face subassembly is mounted to the pressure breakdown device with springs. By flexibly mounting the stationary face subassembly, the stationary face can accommodate axial and radial displacement of the rotating face subassembly with minimum disruption to the lubricating film. In addition, the backing springs provide the seal closure force when sealing pressure is low and aid the hydraulic force balance when sealing pressure is low. The optimized deflection control of the seal design results in repeatable and predictable behavior with greater operating margin to tolerate transients. During normal operation, each seal stage will be subjected to a differential pressure of approximately one-third of reactor coolant system (RCS) pressure. Each of the three individual sealing stages is designed to withstand full RCS pressure indefinitely with the RCP idle, and for a limited period of time with the pump running at a nominal speed of 1200 rpm, to allow for a controlled shutdown. The seal is designed to operate with a thin fluid film gap. As a result, design allowances must be made for short-term contact of the seal face ring materials, particularly during low pressure pump starts. Therefore, the stationary seal face ring material is resin-impregnated graphite. Rotating face ring materials for this application include chromium carbide, silicon carbide, silicon nitride, and tungsten carbide. Tungsten carbide is used in the seal because of its good fracture resistance and thermal conductivity along with favorable tribologic properties. All of the elastomers performing static sealing functions in the seal cartridge are ethylene propylene. The normal operating mode of the sealing system, with one-third of RCS pressure across each stage is created by tubular seal staging flow coils. The coil is part of a subassembly designated the pressure breakdown device (PBD). There is a separate staging coil for each sealing stage, located in the pressure retaining housing for that stage. Thus, each coil acts as an orifice to reduce the pressure available at each seal stage, resulting in equal pressure distribution amongst the stages (unless there is significant leakage through one or more of the seal stages). A second function of 5.4-5 Rev. 30

MPS3 UFSAR the flow, aside from developing seal system pressure distribution, is to provide cooling flow through the sealing system to carry away frictional heat generated by the rotating seal parts. Maintaining stable seal temperatures is important to limit thermal gradients during transient conditions. The existing cooling systems - thermal barrier and injection - have been maintained without change for the RCP. The effect of loss of off site power on the pump itself is to cause a temporary stoppage in the supply of injection flow to the pump seals and also of the component cooling water for seal and bearing cooling. The emergency generators are started automatically due to loss of off site electrical power so that component cooling flow and seal injection flow are automatically restored. 5.4.1.3.2 Coastdown Capability It is important to reactor protection that the reactor coolant continues to flow for a short time after reactor trip. In order to provide this flow following loss of outside electrical power, each reactor coolant pump is provided with a flywheel. Thus, the rotating inertia of the pump, motor, and flywheel is employed during the coastdown period to continue the reactor coolant flow. The coastdown flow transients are provided on the figures in Section 15.3. The pump/motor system is designed for the Safe Shutdown Earthquake (SSE) at the site. Hence, it is concluded that the coastdown capability of the pumps is maintained even under the most adverse case of loss of off site electrical power coincident with the SSE. Core flow transients and figures are provided in Section 15.3.1. 5.4.1.3.3 Bearing Integrity The design requirements for the reactor coolant pump bearings are primarily aimed at ensuring a long life with negligible wear, so as to give accurate alignment and smooth operation over long periods of time. The surface bearing stresses are held at very low values, and even under the most severe seismic transients do not begin to approach loads which cannot be adequately carried for short periods of time. Because there are no established criteria for short time, stress related failures in such bearings, it is not possible to make a meaningful quantification of such parameters as margins to failure, safety factors, etc. A qualitative analysis of the bearing design, embodying such considerations, gives assurance of the adequacy of the bearing to operate without failure. Low lube oil levels in the motor lube oil sumps signal an alarm in the control room. Each motor bearing containing embedded temperature detectors, and so initiation of failure is monitored as a high bearing temperature on the control room computer. Upon control room receipt of a low level alarm, bearing temperature is monitored and once the manufacturers recommended maximum temperature is reached, the reactor is tripped followed by RCP trip. If bearing temperature indications are ignored, and the bearing proceeded to failure, the low melting point of Babbitt metal on the pad surfaces ensures that sudden seizure of the shaft will not occur. In this event, the motor continues to operate, as it has sufficient reserve capacity to drive the pump under such 5.4-6 Rev. 30

MPS3 UFSAR conditions. However, the high torque required to drive the pump will require high current which will lead to the motor being shutdown by the electrical protection systems. 5.4.1.3.4 Locked Rotor It may be hypothesized that the pump impeller might severely rub on a stationary member and then seize. Analysis has shown that under such conditions, assuming instantaneous seizure of the impeller, the pump shaft fails in torsion just below the coupling to the motor, disengaging the flywheel and motor from the shaft. This constitutes a loss of coolant flow in the loop. Following such a postulated seizure, the motor continues to run without any overspeed, and the flywheel maintains its integrity, as it is still supported on a shaft with two bearings. Flow transients are provided in Section 15.3.3 for the assumed locked rotor. There are no other credible sources of shaft seizure other than impeller rubs. A sudden seizure of the pump bearing is precluded by graphite in the bearing. Any seizure in the seals results in a shearing of the anti rotation pin in the seal ring. The motor has adequate power to continue pump operation even after the above occurrences. Indications of pump malfunction in these conditions are initially given by high temperature signals from the bearing water temperature detector, and by excessive CVC seal return (CBO) indications, respectively. 5.4.1.3.5 Critical Speed The reactor coolant pump shaft is designed so that its operating speed is below its first critical speed. This shaft design, even under the most severe postulated transient, gives low values of actual stress. 5.4.1.3.6 Missile Generation Precautionary measures taken to preclude missile formation from reactor coolant pump components assure that the pumps do not produce missiles under any anticipated accident condition. Appropriate components of the reactor coolant pump have been analyzed for missile generation. Any fragments of the motor rotor would be contained by the heavy stator frame. The same conclusion applies to the pump impeller because the small fragments that might be ejected would be contained by the heavy casing. Further discussion and analysis of missile generation are contained in WCAP-8163. 5.4.1.3.7 Pump Cavitation The minimum net positive suction head required by the reactor coolant pump at best estimate flow is approximately a 300 foot head (approximately 133 psi). In order for the controlled leakage seal to operate correctly, it is necessary to require a minimum differential pressure of approximately 200 psi across the seal. This corresponds to a primary loop pressure at which the minimum net positive suction head is exceeded and no limitation on pump operation occurs from this source. 5.4-7 Rev. 30

MPS3 UFSAR 5.4.1.3.8 Pump Overspeed Considerations For turbine trips actuated by either the reactor trip system or the turbine protection system, the generator and reactor coolant pumps remain connected to the external network for 30 seconds to prevent any pump overspeed condition. An electrical fault requiring immediate trip of the generator (with resulting turbine trip) could result in an overspeed condition. However, the turbine control system and the turbine intercept valves limit the overspeed to less than 120 percent. As additional backup, the turbine protection system has a mechanical overspeed protection trip, usually set at about 110 percent (of turbine speed). In case a generator trip deenergizes the pump buses, the reactor coolant pump motors will be transferred to off site power within 6 to 10 cycles. Overspeed of the pump, due to a discharge side pipe rupture, is prevented by the motor which when connected to the electrical system acts as an induction generator. The electrical connection box is located 180 degrees from the pump discharge side so that both the electrical leads and the connection box are protected by the motor from a jet impingement of the reactor coolant. This protection is required for 5 seconds so the motor can prevent overspeed due to the described condition. Further discussion of pump overspeed considerations is contained in WCAP-8163. 5.4.1.3.9 Anti-Reverse Rotation Device Each of the reactor coolant pumps is provided with an anti-reverse rotation device in the motor. This anti-reverse mechanism consists of pawls mounted on the outside diameter of the flywheel, a serrated ratchet plate mounted on the motor frame, a spring return for the ratchet plate, and two shock absorbers. At an approximate forward speed of 70 rpm, the pawls drop and bounce across the ratchet plate; as the motor continues to slow, the pawls drag across the ratchet plate. After the motor has slowed and come to a stop, the dropped pawls engage the ratchet plate and, as the motor tends to rotate in the opposite direction, the ratchet plate also rotates until it is stopped by the shock absorbers. The rotor remains in this position until the motor is energized again. When the motor is started, the ratchet plate is returned to its original position by the spring return. As the motor begins to rotate, the pawls drag over the ratchet plate. When the motor reaches sufficient speed, the pawls are bounced into an elevated position and are held in that position by friction resulting from centrifugal forces acting upon the pawls. While the motor is running at speed, there is no contact between the pawls and ratchet plate. Considerable plant experience with the design of the anti-reverse rotation device has shown high reliability of operation. 5.4.1.3.10 Shaft Seal Leakage 5.4-8 Rev. 30

MPS3 UFSAR Leakage along the reactor coolant pump shaft is controlled by three identical mechanical face-type sealing stages in series assembled as a single cartridge assembly, such that reactor coolant leakage to the containment is minimized. Since leakage flow through a given seal stage is in parallel with the staging coil for that stage, effectively by-passing the coil, cavity pressures in the seal can change with variations in seal leakage. The pressure differential across the leaking seal stage will decrease while the two non-leaking seals equally share an increase in pressure differential (of equal magnitude to the loss of pressure differential across the leaking seal stage). 5.4.1.3.11 Seal Discharge Piping The seal reduces the leakoff pressure to that of the volume control tank. Seal return water from each pump seal is piped to a common manifold, through the seal water return filter, and through the seal water heat exchanger where the temperature is reduced to that of the volume control tank. The seal leakoff line connected to the upper stage directs seal leakage to the containment sump. 5.4.1.4 Tests and Inspections The reactor coolant pumps can be inspected in accordance with the ASME Code, Section XI, for inservice inspection of nuclear reactor coolant systems. The pump casing is cast in one piece, thus eliminating the inservice inspection of welds in the casing. Support feet are cast integral with the casing to eliminate a weld region. The design enables disassembly and removal of the pump internals for visual access to the internal surface of the pump casing. The reactor coolant pump quality assurance program is given in Table 5.4-2. 5.4.2 STEAM GENERATORS The nuclear steam supply system (NSSS) uses four Model F steam generators as shown on Figure 5.4-3. Analysis of conditions that might compromise the reactor coolant boundary are addressed in this section. 5.4.2.1 Steam Generator Materials 5.4.2.1.1 Selection and Fabrication of Materials All pressure boundary materials used in the steam generator are selected and fabricated in accordance with the requirements of Section III of the ASME Code. A general discussion of materials specifications is given in Section 5.2.3, with types of materials listed in Tables 5.2-2 and 5.2-3. Fabrication of reactor coolant pressure boundary materials is also discussed in Section 5.2.3, particularly in Sections 5.2.3.3 and 5.2.3.4. 5.4-9 Rev. 30

MPS3 UFSAR Testing has justified the selection of corrosion resistant Inconel 600, a nickel-chromium-iron alloy (ASME SB-163), for the steam generator tubes. The channel head divider plate is Inconel (ASME SB-168). The interior surfaces of the reactor coolant channel head, nozzles, and manways are clad with austenitic stainless steel. The primary side of the tube sheet is weld clad with Inconel (ASME SFA-5.14). The tubes are then seal welded to the tube sheet cladding. These fusion welds, performed in compliance with Sections III and IX of the ASME Code, are dye penetrant inspected and leak proof tested before each tube is hydraulically expanded the full depth of the tube sheet bore. Code cases used in material selection are discussed in Section 5.2.1. The extent of conformance with Regulatory Guides 1.84, Design and Fabrication Code Case Acceptability ASME Section III Division 1, and 1.85 Materials Code Case Acceptability ASME Section III Division 1, is discussed in Section 1.8. During manufacturing, cleaning is performed on the primary and secondary sides for the steam generator in accordance with written procedures which follow the guidance of Regulatory Guide 1.37, Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants, and ANSI Standard N45.2.1-1973, Cleaning of Fluid Systems and Associated Components for Nuclear Power Plants. On site cleaning and cleanliness control standards are described in the Quality Assurance Program Description Topical Report. Cleaning process specifications are discussed in Section 5.2.3.4. The fracture toughness of the materials is discussed in Section 5.2.3.3. Adequate fracture toughness of ferritic materials in the reactor coolant pressure boundary is provided by compliance with 10 CFR Part 50, Appendix G, Fracture Toughness Requirements, and Paragraph NB-2300 of Section III of the ASME Code. 5.4.2.1.2 Steam Generator Design Effects on Material Several features have been introduced into the Model F steam generator to minimize the deposition of contaminants from the secondary side flow. Such deposits could otherwise produce a local environment in which adverse conditions could develop and result in material attack. The support plates are made of corrosion resistant stainless steel 405 alloy and incorporate a four-lobe hole design (quatrefoil) that provides greater flow area adjacent to the tube outer surface and eliminates the need for interstitial flow holes. The resulting increase in flow provides higher sweeping velocities at the tube/tube support plate intersections. Figure 5.4-4 illustrates the quatrefoil broached holes. This modification in the support plate design is a major factor contributing to the increased circulation ratio. The increased circulation results in increased flow in the interior of the bundle, as well as increased horizontal velocity across the tube sheet reducing the tendency for sludge deposition. The effect of the increased circulation on the vibrational stability of the tube bundle has been analyzed with consideration given to flow induced excitation frequencies. The unsupported span length of tubing in the U-bend region and the corresponding optimum number of anti-vibration bars has been determined. The anti-vibration bars are fabricated from square Inconel barstock, which is then chrome plated to improve frictional characteristics. Also, due to the increased circulation ratio, the moisture separating equipment has 5.4-10 Rev. 30

MPS3 UFSAR been modified to maintain an adequate margin with respect to the moisture carryover. To provide added strength as well as resistance to vibration, the quatrefoil tube support plate thickness has been increased. In addition, 12 peripheral supports also provide stability to the plates so that tube fretting or wear due to flow induced plate vibrations at the tube support contact regions is minimized. Assurance against significant flow induced tube vibration has been obtained by a combination of analysis and testing. Combining both vortex shedding and turbulence effects in a conservative manner, the maximum predicted local tube wear depth of a 60 year operating design objective is less than 0.008 inch. This value is considerably below the plugging limit for a Model F steam generator tube. 5.4.2.1.3 Compatibility of Steam Generator Tubing with Primary and Secondary Coolants As mentioned in Section 5.4.2.1.1, corrosion tests which subjected the steam generator tubing material, Inconel 600 (ASME SB-163), to simulated steam generator water chemistry have indicated that the loss due to general corrosion over the 60 year operating design objective is insignificant compared to the tube wall thickness. Testing to investigate the susceptibility of this material to stress corrosion in caustic and chloride aqueous solutions has indicated the Inconel 600 has excellent resistance to general and pitting type corrosion in severe operating water conditions. Many reactor years of successful operation have shown the same low general corrosion rates as indicated by the laboratory tests. Operating experience has revealed areas on secondary surfaces and in crevice regions where localized corrosion rates were significantly greater than the low general corrosion rates. Intergranular attack intergranular stress corrosion cracking and tube wall thinning were experienced in localized areas, although not at the same location or under the same environmental conditions (water chemistry, temperature and sludge composition). The secondary side water chemistry program as described in Section 10.3.5 minimizes the possibility for developing localized corrosion and essentially eliminates the secondary side tube wall thinning phenomenon. Successful all volatile treatment AVT operation requires maintenance of low concentrations of impurities in the steam generator bulk water, thus reducing the potential for formation of highly concentrated solutions in localized areas, which is the precursor of corrosion. By restriction of the total alkalinity in the steam generator and prohibition of extended operation with free alkalinity, the AVT program should minimize the possibility for recurrence of intergranular corrosion in localized areas due to excessive levels of free caustic. Laboratory testing has shown that the Inconel 600 tubing is compatible with the AVT environment. Isothermal corrosion testing in high purity water has shown that commercially produced Inconel 600 exhibiting normal microstructures tested at normal engineering stress levels does not suffer intergranular stress corrosion cracking in extended exposure to high temperature water. These tests also showed that no general type of corrosion occurred. A series of autoclave tests in reference secondary water with planned excursions have produced no corrosion attached after 1,938 days of testing on any as produced, Inconel 600 tube samples. 5.4-11 Rev. 30

MPS3 UFSAR Successful secondary side water chemistry controls combined with a comprehensive steam generator inservice inspection program as described in Section 5.4.2.2, assure that the steam generators will provide reliable service. The inspection program will also facilitate detection of any unanticipated steam generator tube degradation. Increased margin against primary and secondary side stress corrosion cracking has been obtained by the use of thermally treated Inconel 600 tubing. Thermal treatment of Inconel tubes has been shown to be particularly effective in resisting caustic cracking. Tubing used in the Model F is thermally treated in accordance with a laboratory derived treatment process. In addition, the low rows of tubes were thermally stress relieved prior to installation. This further reduces the potential for stress corrosion cracking in the small radius U-bends. The tube support plates used in the Model F are ferritic stainless steel, which has been shown in laboratory tests to be resistant to corrosion in the AVT environment. If corrosion of ferritic stainless steel was to occur, due to concentration of contaminants, the volume of the corrosion products is essentially equivalent to the volume of the parent material consumed. This would be expected to preclude denting. The support plates are also designed with quatrefoil tube holes rather than cylindrical holes. The quatrefoil tube hole design promotes high velocity flow along the tube and should sweep impurities away from the support plate location. Additional measures are incorporated in the Model F design to prevent areas of dryout in the steam generator and accumulations of sludge in low velocity areas. Modifications to the wrapper have increased water velocities across the tube sheet. A flow distribution baffle is provided which forces the low flow area to the center of the bundle. Increased capacity blowdown pipes have been added to enable continuous blowdown of the steam generators at a high volume. The intakes of these blowdown pipes are located below the center cut out section of the flow distribution baffle in the low velocity region where sludge may be expected to accumulate. Continuous blowdown should provide protection against inleakage of impurities from the condenser. 5.4.2.1.4 Cleanup of Secondary Side Materials Several methods are employed to clean operating steam generators of corrosion causing secondary side deposits. Sludge lancing, a procedure in which a hydraulic jet inserted through an access opening (handhole) loosens deposits which are removed by means of a suction pump, can be performed when the need is indicated by the results of steam generator tube inspection. Six 6-inch access ports are provided for sludge lancing and inspection. Three of these are located above the tube sheet and three above the flow distribution baffle. Continuous blowdown is performed to regulate water chemistry. The location of the blowdown piping suction, adjacent to the tube sheet and in a region of relatively low flow velocity, facilitates the removal of particulate impurities to minimize the accumulation on the tube sheet. 5.4.2.2 Steam Generator Inservice Inspection The steam generator is designed to permit inspection of ASME Code Class 1 and 2 parts, including individual tubes. The design includes a number of openings to provide access to both the primary and secondary sides of the steam generator. The specified inspection program 5.4-12 Rev. 30

MPS3 UFSAR complies with the edition of the ASME Code, Division 1, Section XI required by 10 CFR 50.55a, effective January 5, 1977. The openings include four manways, two for access to both chambers of the reactor coolant channel head inlet and outlet sides and two in the steam drum for inspection and maintenance of the moisture separators; six, 6 inch handholes, three located just above the tube sheet secondary surface and three located just above the flow distribution baffle; and two, 2.5 inch inspection ports located on the tube lane diameter between the upper tube support plate and the Row 1 U-bend. Additional access to the tube U-bend is provided through each of the three deck plates. For proper functioning of the steam generator, some of the deck plate openings are covered with welded, but removable, hatch plates. Inspection/access to the primary sides is provided by two, 16 inch manways located in the channel head. Regulatory Guide 1.83, Inservice inspection of PWR Steam Generator tubes, and Generic Letter 2004-01, Requirements for Steam Generator tube inspections, provide recommendations concerning the inspection of tubes, which cover inspection equipment, baseline inspections, tube selection, sampling and frequency of inspection, methods of recording, and required actions based on findings. Regulatory Guide 1.121, Basis for Plugging Degraded PWR Steam Generator Tubes, provides recommendations concerning the tube plugging. Agreement with Regulatory Guides 1.83 and 1.121 is discussed in Section 1.8. The minimum requirements for inservice inspection of steam generators, including tube plugging criteria, are established as part of the Technical Specifications. The inservice inspection program for the reactor coolant boundary is discussed in Section 5.2.4. 5.4.2.3 Design Basis Steam generator design data are given in Table 5.4-3. Code classifications for the steam generator components are given in Section 3.2. Although the ASME classification for the secondary side is specified to be Class 2, the current philosophy is to design all pressure retaining parts of the steam generator, and thus both the primary and secondary pressure boundaries, to satisfy the criteria specified in Section III of the ASME Code for Class 1 components. The design stress limits, transient conditions, and combined loading conditions applicable to the steam generator are discussed in Section 3.9N.1. Estimates of radioactivity levels anticipated in the secondary side of the steam generators during normal operation and the bases for the estimates are given in Chapter 11. The accident analysis of a steam generator tube rupture is discussed in Chapter 15. A design objective of the internal moisture separator equipment is that moisture carryover should not 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 5.4-13 Rev. 30

MPS3 UFSAR The water chemistry on the reactor side, selected to provide the necessary boron content for reactivity control, should minimize corrosion of RCS surfaces. The effectiveness of the water chemistry of the steam side in affecting corrosion control is discussed in Chapter 10. Compatibility of steam generator tubing with both primary and secondary coolants is discussed further in Section 5.4.2.1.3. The steam generator is designed to minimize unacceptable damage from mechanical or flow induced vibration. Tube support adequacy is discussed in the Design Evaluation Section. The tubes and tube sheet are analyzed and confirmed to withstand the maximum accident loading conditions as they are defined in Section 3.9N.1. Further consideration is given in the Design Evaluation Section to the effect of tube wall thinning on accident condition stresses. 5.4.2.4 Design Description The steam generator is a Model F, vertical shell and U-tube evaporator, with integral moisture separating equipment. Figure 5.4-3 shows the model, indicating several of its improved design features described in the following paragraphs. On the primary side, the reactor coolant flows through the inverted U-tubes, entering and leaving through nozzles located in the hemispherical bottom head of the steam generator. The head is divided into inlet and outlet chambers by a vertical divider plate extending from the apex of the head to the tube sheet. Steam is generated on the shell side, flows upward, and exits through the outlet nozzle at the top of the vessel. Feedwater enters the steam generator at an elevation above the top of the U-tubes, through a feedwater nozzle. The water is distributed circumferentially around the steam generator by means of a feedwater ring and then flows through an annulus between the tube wrapper and shell. The feedwater enters the ring via a welded thermal sleeve connection and leaves through inverted J tubes located at the flow holes at the top of the ring. The J tubes are arranged to distribute the bulk of the colder feedwater to the hot leg side of the tube bundle. The feed ring is designed to minimize conditions which can result in water hammer occurrences in the feedwater piping. At the bottom of the wrapper, the water is directed toward the center of the tube bundle by a flow distribution baffle. This baffle arrangement serves to minimize the tendency in the relatively low velocity fluid for sludge deposition. Flow blocking devices discourage the water from flowing up the bypass lane as it enters the tube bundle, where it is converted to a steam-water mixture. Subsequently, the steam-water mixture from the tube bundle rises into the steam drum section, where 16 individual centrifugal moisture separators remove most of the entrained water from the steam. The steam continues to the secondary separators for further moisture removal, increasing its quality to a designed minimum of 99.75 percent. The moisture separators reintroduce the separated water, which is combined with entering feedwater to flow back down the annulus between the wrapper and shell for recirculation through the steam generator. The dry steam exits from the steam generator through the outlet nozzle which is provided with a steam flow restrictor (Section 5.4.4). 5.4-14 Rev. 30

MPS3 UFSAR 5.4.2.5 Design Evaluation Forced Convection The effective heat transfer coefficient is determined by the physical characteristics of the Model F steam generator and the fluid conditions in the primary and secondary systems for the nominal 100 percent design case. It includes a conservative allowance for fouling and uncertainty. A designed heat transfer area is provided to permit the achievability of the full design heat removal rate. Natural Circulation Flow The driving head created by the change in coolant density as it is heated in the core and rises to the outlet nozzle initiates convection circulation. This circulation is enhanced by the fact that the steam generators, which provide a heat sink, are at a higher elevation than the reactor core which is the heat source. Thus, natural circulation is provided for the removal of decay heat during hot shutdown in the unlikely event of loss of forced circulation. Mechanical and Flow-Induced Vibration Under Normal Operation Conditions In the design of the steam generators, the possibility of degradation of tubes due to either mechanical or flow-induced excitation is thoroughly evaluated. This evaluation includes detailed analysis of the tube support systems, as well as an extensive research program with tube vibration model tests. In evaluating degradation due to vibration, consideration is given to sources of excitation, such as those generated by primary fluid flowing within the tubes, mechanically induced vibration, and secondary fluid flow on the outside of the tubes. During normal operation, the effects of primary fluid flow within the tubes and mechanically induced vibration are considered to be negligible and should cause little concern. Thus, the primary source of tube vibrations is the hydrodynamic excitation by the secondary fluid on the outside of the tubes. In general, three vibration mechanisms have been identified:

1. Vortex shedding

2. Fluidelastic excitation

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

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

5.4-15 Rev. 30

MPS3 UFSAR

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.

Fluidelastic excitation was observed during the testing. The amplitudes of the vibrations were smaller than those of the turbulent flow induced vibrations. Therefore, fluidelastic excitation is excluded from consideration as a factor in steam generator tube bundle vibrations. Flow-induced vibrations due to flow turbulence cause stresses in the tubes that are more than two orders of magnitude below the endurance limit (30,000 psi) of the tube material. Therefore, the contribution to fatigue is negligible, and fatigue degradation from flow-induced vibration is not anticipated. Summarizing the results of analysis and tests of steam generator for vibration, it can be stated that a check of all modes of tube vibration mechanisms has been completed. The conclusions that can be drawn are that the primary source of tube vibration is fluid turbulence and the magnitude of the vibration is so small that when combined with its total random nature, its contribution to tube fatigue is negligible. Therefore, fatigue degradation due to flow induced vibration is not anticipated. Allowable Tube Wall Thinning Under Accident Conditions An evaluation has been performed to determine the extent of tube wall thinning that can be tolerated under accident conditions. The worst case loading conditions are assumed to be imposed upon uniformly thinned tubes, at the most critical location in the steam generator. Under such a postulated design basis accident, vibration is of short enough duration that there is no endurance problem to be considered. The steam generator tubes, existing originally at their minimum wall thickness and reduced by a conservative general corrosion and erosion loss, can be shown to provide an adequate safety margin (i.e., sufficient wall thickness, in addition to the minimum required for a maximum stress less than the allowable stress limit, as it is defined by the ASME Code). The results of a study made on D series (0.75 inch nominal diameter, 0.043 inch nominal wall thickness) tubes under accident loadings are discussed in WCAP-7832 (1973). These results demonstrate that a minimum wall thickness of 0.026 inch would have a maximum faulted condition stress (i.e., due to combined LOCA and safe shutdown earthquake loads) that is less than the allowable limit. This thickness is 0.010 inch less than the minimum D series tube wall thickness of 0.039 inch, which is reduced to 0.036 inch by the assumed general corrosion and erosion rate. Thus, an adequate safety margin is exhibited. The corrosion rate is based on a conservative weight loss rate for Inconel tubing in flowing 650°F primary side reactor coolant fluid. The weight loss, when equated to a thinning rate and projected over a 60 year design objective with appropriate reduction after initial hours, is equivalent to 0.083 mil thinning. The assumed corrosion rate of 3 mils leaves a conservative 2.917 mils for general corrosion thinning on the secondary side. 5.4-16 Rev. 30

MPS3 UFSAR The Model F steam generator was analyzed using similar assumptions of general corrosion and erosion rates. The overall similarity between previous tubes studied and the Model F tubes makes it reasonable to expect the same general results, that is, to conclude that the ability of the Model F steam generator tubes to withstand accident loadings is not impaired by a lifetime of general corrosion losses. This is confirmed by specific analysis. 5.4.2.6 Quality Assurance The steam generator nondestructive examination program is given in Table 5.4-4. Radiographic inspection and acceptance standards are in accordance with the requirements of Section III of the ASME Code. Liquid penetrant inspection is performed on weld deposited tube sheet cladding, channel head cladding, divider plate to tube sheet and to channel head weldments, tube to tube sheet weldments, and weld deposit cladding. Liquid penetrant inspection and acceptance standards are in accordance with the requirements of Section III of the ASME Code. Magnetic particle inspection is performed on the tube sheet forging, channel head casting, nozzle forgings, 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 Magnetic particle inspection and acceptance standards are in accordance with the requirements of Section III of the ASME Code.

Ultrasonic tests are performed on the tube sheet forgings, tube sheet cladding, secondary shell and head plates, and nozzle forgings. Inspection and acceptance standards are in accordance with the requirements of Section III of the ASME Code. The heat transfer tubing is subjected to eddy current testing and ultrasonic examination. Inspection and acceptance standards are in accordance with the requirements of Section III of the ASME Code. Hydrostatic tests are performed in accordance with Section III of the ASME Code. In addition, the heat transfer tubes are subjected to a hydrostatic test pressure not less than 1.25 times the primary side design pressure prior to installation into the vessel. 5.4-17 Rev. 30

MPS3 UFSAR 5.4.3 REACTOR COOLANT PIPING 5.4.3.1 Design Bases The reactor coolant system (RCS) piping is designed and fabricated to accommodate the system pressures and temperature attained under all expected modes of plant operation or anticipated system interactions. Stresses are maintained within the limits of Section III of the ASME Nuclear Power Plant Components Code. Section 5.2 provides code and material requirements. Materials of construction are specified to minimize corrosion/erosion and ensure compatibility with the operating environment. The piping in the RCS is Safety Class 1 and is designed and fabricated in accordance with ASME Section III, Class 1 requirements. Stainless steel pipe conforms to ANSI B36.19 for sizes 0.5 inch through 12 inches and wall thickness Schedules 40S through 80S. Stainless steel pipe outside of the scope of ANSI B36.19 conforms to ANSI B36.10. The minimum wall thickness of the loop pipe and fittings are not less than that calculated using the ASME III Class 1 formula of Paragraph NB-3641.1(3) with an allowable stress value of 17,550 psi. The pipe wall thickness for both bypass and pressurizer surge lines is Schedule 160. The minimum pipe bend radius is 5 nominal pipe diameters; ovality does not exceed 8 percent. All butt welds, branch connection nozzle welds, and boss welds are of a full penetration design. Section 5.2.3 discusses processing and minimization of sensitization. Flanges conform to ANSI B16.5. Socket weld fittings and socket joints conform to ASNI B16.11. Section 5.2.4 discusses inservice inspection. 5.4.3.2 Design Description Table 5.4-5 gives principal design data for the reactor cooling piping. Pipe and fittings are cast, forged, or seamless without longitudinal or electroslag welds, and comply with the requirements of the ASME Code, Section II, Parts A and C, Section III, and Section IX. The RCS piping is specified in the smallest sizes consistent with system requirements. This design philosophy results in the reactor inlet and outlet piping diameters given in Table 5.4-5. The 5.4-18 Rev. 30

MPS3 UFSAR line between the steam generator and the pump suction is larger to reduce pressure drop and improve flow conditions to the pump suction. The reactor coolant piping and fittings which make up the loops are austenitic stainless steel. There is no electroslag welding on these components. All smaller piping which comprise part of the RCS such as the pressurizer surge line, spray and relief line, loop drains and connecting lines to other systems are also austenitic stainless steel. The nitrogen supply line for the pressurizer relief tank is carbon steel. All joints and connections are welded, except for the pressurizer relief and the pressurizer code safety valves, where flanged joints are used. Thermal sleeves are installed in the crossover leg at the 2 inch chemical volume and control system (CHS) charging line connection with each reactor coolant loop. The other thermal sleeves are on the pressurizer where the surge line connects and where the spray line connects to the pressurizer. Thermal sleeves are used where thermal stresses could develop due to rapid changes in fluid temperature during normal operational transients. All piping connections from auxiliary systems are made above the horizontal centerline of the reactor coolant piping, with the exception of:

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.

Penetrations 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.

5.4-19 Rev. 30

MPS3 UFSAR

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

The RCS piping includes those sections of piping interconnecting the reactor vessel, steam generator, 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.

4. Residual heat removal lines to or from the reactor coolant loops up to the designated check valve or isolation valve.

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.

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).

5.4-20 Rev. 30

MPS3 UFSAR

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).

Section 5.2 discusses details of the materials of construction and codes used in the fabrication of reactor coolant piping and fittings. 5.4.3.3 Design Evaluation Section 3.9 discusses piping load and stress evaluation for normal operating loads, blowdown loads, and combined normal, blowdown and seismic loads. 5.4.3.3.1 Material Corrosion/Erosion Evaluation The water chemistry is selected to minimize corrosion. Periodic analysis of the coolant chemical composition is performed to verify that the reactor coolant quality meets the specifications. The design and construction are in compliance with ASME Section XI. Pursuant to this, all pressure containing welds out to the second valve that delineates the RCS boundary are available for examination with removal insulation. Components constructed with stainless steel operate satisfactorily under normal plant chemistry conditions in pressurized water reactor systems, because chlorides, fluorides, and particularly oxygen, are controlled to very low levels. (Section 5.2.3) Periodic analysis of the coolant chemical composition is performed to monitor the adherence of the system to desired reactor coolant water quality listed in Table 5.2-4. Maintenance of the water quality to minimize corrosion is accomplished using the chemical and volume control system and sampling system which are described in Chapter 9. 5.4.3.3.2 Sensitized Stainless Steel Section 5.2.3 discusses sensitized stainless steel. 5.4.3.3.3 Contaminant Control Contamination of stainless steel and Inconel by copper, low melting temperature alloys, mercury and lead is prohibited. Prior to application of thermal insulation, the austenitic stainless steel surfaces are cleaned and analyzed in accordance with Regulatory Guide 1.37 as described in Section 1.8. 5.4-21 Rev. 30

MPS3 UFSAR 5.4.3.4 Tests and Inspections Table 5.4-6 gives the RCS piping NDE program. Volumetric examination is performed throughout 100 percent of the wall volume of each pipe and fitting in accordance with the applicable requirements of Section III of the ASME Code for all pipe 27.5 inches and larger. All unacceptable defects are eliminated in accordance with the requirements of the same section of the code. A liquid penetrant examination is performed on both the entire outside and inside surfaces of each finished fitting in accordance with the criteria of ASME Section III. Acceptance standards are in accordance with the applicable requirements of ASME Section III. The pressurizer surge line conforms to SA-376 Grade 304, with supplementary requirements S2 (transverse tension tests), and S6 (ultrasonic test). The S2 requirement applies to each length of pipe. The S6 requirement applies to 100 percent of the piping wall volume. The material is examined in accordance with ASME Code, Section III and ASME Section II, SA 655, 1977 edition. The end of pipe sections, branch ends and fittings are machined back to provide a smooth weld transition adjacent to the weld path. 5.4.4 MAIN STEAM LINE FLOW RESTRICTOR 5.4.4.1 Design Basis The outlet nozzle of the steam generator contains a flow restrictor designed to limit steam flow in the unlikely event of a break in the main steam line. With a restrictor, a large increase in steam flow creates a backpressure which limits further increase in flow. Several protective advantages are thereby provided: rapid rise in containment pressure is prevented, the rate of heat removal from the reactor coolant is maintained within acceptable limits, thrust forces on the main steam line piping are reduced, and stresses on internal steam generator components, particularly the tube sheet and tubes, are maintained within acceptable limits. Another design objective is to minimize waterhammer type loads and unrecovered pressure loss across the restrictor during normal operation. 5.4.4.2 Design Description The flow restrictor consists of seven Inconel (ASME SB-163) venturi inserts which are inserted into the holes in an integral steam outlet low alloy steel forging. The inserts are arranged with one venturi at the centerline of the outlet nozzle and the other six equally spaced around it. After insertion into the low allow steel forging holes, the Inconel venturi nozzles are welded to the Inconel cladding on the inner surface of the forging. 5.4.4.3 Design Evaluation The flow restrictor design has been sufficiently analyzed to assure its structural adequacy. The equivalent throat diameter of the steam generator outlet is 16 inches, and the resultant pressure 5.4-22 Rev. 30

MPS3 UFSAR drop through the restrictor at 100 percent steam flow is approximately 3.1 psi. This is based on a design flow rate of 4.07 x 106 lb/hr. Materials of construction and manufacturing of the flow restrictor are in accordance with Section III of the ASME Code. 5.4.4.4 Tests and Inspections Since the restrictor is not a part of the steam system pressure boundary, no tests and inspection beyond those conducted during fabrication are performed. 5.4.5 MAIN STEAM ISOLATION SYSTEM The main steam isolation system is described in Sections 6.2.4 and 10.3. 5.4.6 REACTOR CORE ISOLATION COOLING SYSTEM This section is not applicable to the Millstone 3 reactor core, as it applies to a boiling water reactor core design and Millstone 3 has a pressurized water reactor. 5.4.7 RESIDUAL HEAT REMOVAL SYSTEM The residual heat removal system (RHS) transfers heat from the reactor coolant system (RCS) to the component cooling system (CCP) to reduce the temperature of the reactor coolant to the cold shutdown temperature at a controlled rate during the second part of normal plant cooldown or a safety grade cold shutdown (SGCS) and maintains this temperature until the plant is started up again. The RHS may be aligned to the RCS for cooldown operation once RHS entry conditions are achieved (RCS temperature and pressure reduced to at or below 350°F and 375 psig, respectively). Parts of the RHS also serve as parts of the emergency core cooling system (ECCS) during the injection phase of a loss-of-coolant accident (Section 6.3). The RHS may be used to transfer refueling water between the refueling cavity and the refueling water storage tank at the beginning and end of the refueling operations. Relief valves in the RHS pump suction lines from the RCS provide low temperature overpressure protection for the reactor vessel when the RHS is unisolated from the RCS (Section 5.2.2.11). Nuclear plants employing the same RHS design as the Millstone 3 Steam Electric Station are given in Section 1.3. 5.4.7.1 Design Bases RHS design parameters are listed in Table 5.4-7. The RHS is designed to operate in conjunction with other plant systems to reduce the temperature of the RCS during the second phase of plant cooldown. 5.4-23 Rev. 30

MPS3 UFSAR The RHS is capable of being placed in operation approximately four hours after reactor shutdown when the temperature and pressure of the RCS are approximately 350°F and 375 psig, respectively. Assuming that two heat exchangers and two pumps are in service and that each heat exchanger is supplied with component cooling water at design flow and temperature, the RHS is designed to reduce the temperature of the reactor coolant from 350°F to 200°F within 20 hours. However, during normal cooldown only one RHS heat exchanger and pump are used for cooling until the reactor coolant temperature is reduced to 260°F. This limitation is imposed based on the Technical Specifications requirement of 1 RHS train being operable in Mode 4 to mitigate a LOCA event and the issue raised by the Westinghouse Owners Group that flashing in the RHS suction line would occur due to the elevated temperature of the water trapped in the suction line in conjunction with the rapid depressurization upon RHS pump start. Consequently, one RHS train remains aligned to the RWST for use as an injection path to the RCS until the RCS temperature corresponds to the saturation temperature of the RWST elevation head above the RHR pump suction which would prevent flashing. Assuming this configuration, the RHS is capable of cooling the reactor coolant from 350°F to 200°F within 41.25 hours with one reactor coolant pump operating and within 72.25 hours with 2 reactor coolant pumps operating. The heat load by the RHS during the cooldown transient includes residual and decay heat from the core and reactor coolant pump heat. The RHS is also designed to operate in conjunction with the other systems of the cold shutdown design to achieve and maintain cold shutdown using only safety grade systems, as required by Branch Technical Position RSB 5-1. See Safety Grade Cold Shutdown (one and/or two RHS trains(s) in service), Section 5.4.7.2.3.5. The RHS is designed to be isolated from the RCS whenever the RCS pressure exceeds the RHS design pressure. The RHS is isolated from the RCS on the suction side by three normally closed, motor-operated valves in series on each suction line. Two of the motor-operated valves are interlocked to prevent its opening if RCS pressure is greater than 412.5 psia and alarm 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 discussed in detail in Sections 5.4.7.2.4 and 7.6.2.) The third motor-operated valve is closed and deenergized at the motor control center (MCC). The motor-operated valve closest to the pump suction is closed and deenergized at the MCC. The RHS is isolated from the RCS on the discharge side by three check valves in each return line. Also provided on the discharge side is a normally open motor-operated valve downstream of each RHS heat exchanger. Each inlet line to the RHS is equipped with a pressure relief valve sized to relieve the flow of one charging pump at the relief valve set pressure. These relief valves are provided to protect the RHS system (and the reactor pressure vessel when the RHS is unisolated from the RCS) from inadvertent overpressurization during plant cooldown or startup. Each discharge line from the RHS to the RCS is equipped with a pressure relief valve designed to relieve the maximum possible back leakage through the valves isolating the RHS from the RCS. 5.4-24 Rev. 30

MPS3 UFSAR The RHS is designed for a single nuclear power unit and is not shared among nuclear power units. The RHS is designed to be fully operable from the control room for normal operation except for opening the outermost and inner most pump suction valve in each train. These valves are closed and deenergized at the MCC. The MCCs for the innermost valves are located in the ESF building on the 36 foot elevation. The MCCs for the outermost valves are located in the auxiliary building in the vicinity of the rod drive control center. These MCCs are accessible should RHS operability be required after an accident (FSAR Table 12.3-3). Manual operations required of the operator are: closing the suction valves to the RWST, opening the suction isolation valves, positioning the flow control valves downstream of the RHS heat exchangers, and starting the RHS pumps. Manual actions, including those required for safety grade cold shutdown, are also discussed in Sections 5.4.7.2.3.5, 5.4.7.2.6 and 5.4.7.2.7. By nature of its redundant two train design, the RHS is designed to accept all major component single failures with the only effect being an extension in the required cooldown time. There are no motor-operated valves in the RHS that are subject to common mode flooding. Provisions to protect the equipment from flooding are discussed in Section 3.4. For two low probability electrical system single failures, i.e., failure in the suction isolation valve interlock circuitry, or emergency generator failure in conjunction with loss of off site power, limited operator action outside the control room is required to open the suction isolation valves. The spurious operation of a single RHS motor-operated valve can be accepted without loss of cooling function as a result of the redundant two train design. Missile protection, protection against dynamic effects associated with the postulated rupture of piping, and seismic design are discussed in Sections 3.5, 3.6, and 3.7, respectively. 5.4.7.2 System Design 5.4.7.2.1 Schematic Piping and Instrumentation Diagrams The RHS, as shown on Figures 5.4-5 and 5.4-6, consists of two residual heat exchangers, two residual heat removal pumps, and the associated piping, valves, and instrumentation necessary for operational control. The suction lines to the RHS are connected to the hot legs of two reactor coolant loops, while the return lines are connected to the cold legs of each of the reactor coolant loops. These return lines are also the ECCS low head injection lines (Figure 6.3-1). The RHS suction lines are isolated from the RCS by three normally- closed motor-operated valves in series. The two normally closed isolation valves inside containment in each RHS suction line receive power from the same Class 1E source as the RHS pump in that line while the valve outside containment is powered by the opposite train. This arrangement ensures that single failure requirements for RHS accessibility and isolation are met. Each discharge line is isolated from the RCS by three check valves located inside the containment and by a normally open motor-operated valve located outside the containment. (The check valves and the motor-operated valve on each discharge line are not part of the RHS; these valves are shown as part of the ECCS; Figure 6.3-1.) 5.4-25 Rev. 30

MPS3 UFSAR During RHS operation, reactor coolant flows from the RCS to the residual heat removal pumps, through the tube side of the residual heat exchangers, and back to the RCS. The heat is transferred to the component cooling water circulating through the shell side of the residual heat exchangers. Coincident with operation of the RHS, a portion of the reactor coolant flow may be diverted from downstream of the residual heat exchangers to the CHS low pressure letdown line for cleanup and/or pressure control. By regulating the diverted flow rate and the charging flow, the RCS pressure may be controlled. Pressure regulation is necessary to maintain the pressure range dictated by the fracture prevention criteria requirements of the reactor vessel and by the shaft seal differential pressure and net positive suction head requirements of the reactor coolant pumps. The RCS cooldown rate is manually controlled by regulating the reactor coolant flow through the tube side of the residual heat exchangers. A line containing a flow control valve bypasses each residual heat exchanger and is used to maintain a constant return flow to the RCS. Instrumentation is provided to monitor system pressure, temperature, and total flow. The RHS may be used for filling the refueling cavity before refueling. After refueling operations, water is pumped back to the refueling water storage tank until the water level is brought down to the flange of the reactor vessel. The remainder of the water is removed via a drain connection at the bottom of the refueling canal. When the RHS is in operation, the water chemistry is the same as that of the reactor coolant. Provision is made for the process sampling system (Section 9.3.2) to extract samples from the flow of reactor coolant downstream of the residual heat exchangers. A local sampling point is also provided on each residual heat removal train, between the pump and heat exchanger. The RHS functions in conjunction with the high head portion of the ECCS to provide injection of borated water from the refueling water storage tank into the RCS cold legs during the injection phase following a loss-of-coolant accident. Long term recirculation is performed by the containment recirculation system discussed in Sections 6.2.2 and 6.3. The use of the RHS as part of the ECCS is more completely described in Section 6.3. Description 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 5.4-26 Rev. 30

MPS3 UFSAR 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

2. Residual heat removal pump suction line from the refueling water storage tank 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 1,542 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. 5.4.7.2.2 Equipment and Component Descriptions The materials used to fabricate RHS components are in accordance with the applicable code requirements. All parts of components in contact with borated water are fabricated or clad with austenitic stainless steel or equivalent corrosion resistant material. Component parameters are given in Table 5.4-8. Residual Heat Removal Pumps Two pumps are installed in the RHS. The pumps are sized to deliver reactor coolant flow through the residual heat exchangers to meet the plant cooldown requirements. The use of two separate RHR trains assures that cooling capacity is only partially lost should one pump become inoperative. The RHS pumps are protected from overheating and loss of suction flow by mini-flow bypass lines that assure flow to the pump suction should the pump suction be isolated or the RCS pressure be above the shutoff head of the pump. A valve located in each mini-flow line is regulated by a signal from the flow transmitters located in each pump discharge header. The 5.4-27 Rev. 30

MPS3 UFSAR control valves open when the RHS pump discharge flow is less than 772 gpm and close when the flow exceeds 1,542 gpm. A pressure sensor in each pump discharge header provides a signal for an indicator in the control room. A high pressure alarm is also actuated by the pressure sensor. The two pumps are vertical, centrifugal units with mechanical seals on the shafts. All pump surfaces in contact with reactor coolant are austenitic stainless steel or equivalent corrosion resistant material. The RHS pumps also function as the low head safety injection pumps in the ECCS. (See Section 6.3 for further information and for the RHS pump performance curves.) Residual Heat Exchangers Two residual heat exchangers are installed in the system. The heat exchanger design is based on heat load and temperature differences between reactor coolant and component cooling water existing 24 hours after reactor shutdown when the temperature difference between the two systems is small. The installation of two heat exchangers in separate and independent residual heat removal trains assures that the heat removal capacity of the system is only partially lost if one train becomes inoperative. The residual heat exchangers are of the shell and U-tube type. Reactor coolant circulates through the tubes, while component cooling water circulates through the shell. The tubes are welded to the tube sheet to prevent leakage of reactor coolant. The residual heat exchangers also function as part of the ECCS (Section 6.3). Residual Heat Removal System Valves Valves that perform a modulating function are equipped with two sets of packings and an intermediate leakoff connection that discharges to the drain header. Manual and motor-operated valves have backseats to facilitate repacking and to limit stem leakage when the valves are open. Motor-operated valves are stopped in the open direction by limit switches and therefore must be back seated manually. Leakage connections are provided where required by valve size and fluid conditions. The RHS heat exchanger outlet butterfly valves have been provided with actuator throttle limiters that have been set to prevent full opening of the valves in the event of a loss of the (non safety) Instrument Air. The RHS heat exchanger bypass butterfly valves have been modified to fail open in the event of a loss of Instrument Air. Upon loss of air, the outlet valves will fail open to the pre-set open position and the bypass valves will fail full open to allow continued cooldown without adversely affecting CCP piping with an RCS temperature as high as 350°F. 5.4-28 Rev. 30

MPS3 UFSAR 5.4.7.2.3 System Operation 5.4.7.2.3.1 Reactor Startup Generally, while at cold shutdown condition, decay heat from the reactor core is being removed by the RHS. The number of pumps and heat exchangers in service depends upon the heat load at the time. At initiation of the plant startup, the RCS is completely filled, and the pressurizer heaters are energized. The RHS is operating and is connected to the CHS via the low pressure letdown line to control reactor coolant pressure. During this time, the RHS acts as an alternate letdown path. The manual valves downstream of the residual heat exchangers leading to the letdown line of the CHS are opened. The control valve in the line from the RHS to the letdown line of the CHS is then manually adjusted in the control room to permit letdown flow. Steam bubble formation in the pressurizer is accomplished by increasing the letdown flow above the charging flow with the pressurizer heaters energized. The reactor coolant pumps are normally started to heat up the system after the pressurizer bubble has been formed. When the pressurizer water level reaches the no-load programmed setpoint, pressurizer level control is shifted to the normal operational means. The RHS is then isolated from the RCS and the system pressure is controlled by normal letdown, pressurizer spray, and pressurizer heaters. 5.4.7.2.3.2 Power Generation and Hot Standby Operation During power generation and hot standby operation, the RHS is not in service but is aligned for operation as part of the ECCS. 5.4.7.2.3.3 Plant Shutdown Plant shutdown is defined as the operation which brings the plant from no-load temperature and pressure to a cold shutdown condition (i.e., to a subcritical condition with the reactor coolant temperature no greater than 200°F). 5.4.7.2.3.4 Normal Cold Shutdown The initial phase of a normal plant shutdown is accomplished by transferring heat from the RCS to the steam and power conversion system. Circulation of the reactor coolant is provided by the reactor coolant pumps and heat removal is accomplished by using the steam generators and dumping steam to the condenser. In conjunction with this portion of the cooldown, the reactor coolant is borated to the concentration required for cold shutdown and depressurized to a pressure permitting RHS operation. Boration and makeup for the contraction of the RCS due to cooling are performed using the charging, letdown, and makeup control portions of the CHS. 5.4-29 Rev. 30

MPS3 UFSAR The depressurization function is performed by initiating pressurizer spray from the discharge of the operating reactor coolant pump. When the reactor coolant temperature and pressure are reduced to at or below 350°F and 375 psig, no less than 4 hours after reactor shutdown, the second phase of cooldown starts with the RHS being placed in operation. Startup of the RHS includes a warmup period during which time reactor coolant flow through the heat exchangers is limited to minimize thermal shock. The rate of heat removal from the reactor coolant is manually controlled by regulating the coolant flow through the residual heat exchangers. By adjusting the control valves downstream of the residual heat exchangers, the mixed mean temperature of the return flow is controlled. Coincident with the manual adjustment, each heat exchanger bypass valve is automatically regulated to give the required total flow. The reactor cooldown rate is limited by RCS equipment cooling rates based on allowable stress limits, as well as the operating temperature limits of the component cooling water system. As the reactor coolant temperature decreases, the reactor coolant flow through the residual heat exchanger is increased by adjusting the control valve in each heat exchangers tube side outlet line. Modifications to the RHS system have been made to preclude overheating of the RHS heat exchanger (shell side) cooling water piping (CCP system) in the event of a loss of Instrument Air during a Normal or safety grade cold shutdown (SGCS) cooldown. The RHS heat exchanger outlet butterfly valves have been provided with actuator throttle limiters that have been set to prevent full opening of the valves in the event of a loss of the (non safety) Instrument Air. The RHS heat exchanger bypass butterfly valves have been modified to fail open in the event of a loss of Instrument Air. Upon loss of air, the outlet valves will fail open to the pre-set open position and the bypass valves will fail full open to allow continued cooldown without adversely affecting CCP piping with an RCS temperature as high as 350°F. The changes have no effect on the RHS injection flowpath when RHS is used during the SI phase following a LOCA. See also FSAR Section 6.3.2.2.5. During plant shutdown with the RHS in operation, operation with a steam bubble in the pressurizer is maximized to provide RCS pressure control. The RCS is augmented by regulating the charging flow rate and the rate of letdown from the RHS to the CHS. After the reactor coolant is reduced below a temperature of 160°F and the reactor coolant pump is stopped, cooling of the pressurizer is continued by providing auxiliary spray from the CHS. After the reactor coolant pressure is reduced and the temperature is 140°F or lower, the RCS may be opened for refueling or maintenance. 5.4.7.2.3.5 Safety Grade Cold Shutdown While the plant shutdown basis is hot standby for those events involving a primary or secondary system piping passive failure, it is cold shutdown for those events which are initiated from normal 5.4-30 Rev. 30

MPS3 UFSAR operating conditions. In accordance with the functional requirements of Branch Technical Position RSB 5-1, safety grade cold shutdown is defined as the ability to take the plant from normal operating conditions to cold shutdown, with or without off site power, with the most limiting single failure, using only safety related equipment and limited action outside of the control room, and within a reasonable period of time following shutdown. Should portions of the normal shutdown systems be unavailable, the operator should maintain the plant in a hot standby condition while making the normal systems functional. However, for cases in which the Demineralized Water Storage Tank (DWST) is the exclusive source of demineralized water, the operator should use any of the normal systems available in conjunction with safety grade backups for those systems which cannot be made available in order to ensure cold shutdown can be achieved without depleting the DWST. The safety grade provisions are to be used only upon the inability to make available the equipment normally used for the given function. In the extreme case where all of the normal shutdown systems are unavailable, a safety grade cold shutdown would be accomplished. For Millstone 3, this is postulated to occur as a result of a safe shutdown earthquake (SSE), coincident with a loss of off site power, and the loss of one RHS train 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.

A safety 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 5.4-31 Rev. 30

MPS3 UFSAR 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 hours 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.

Depressurization of the RCS throughout the safety grade cold shutdown process is accomplished by the safety grade solenoid-operated pressurizer PORVs. In order to ensure that the RCS is not repressurized by the safety injection accumulators, the motor-operated accumulator isolation valves are closed prior to RCS pressure dropping below the accumulator discharge pressure. Two of the accumulator isolation valves are powered from the orange safety train while the other two valves are powered from the purple safety train. Additional protection against inadvertent repressurization of the RCS by the accumulators is provided by redundant Class 1E solenoid-operated accumulator vent valves which permit venting of the accumulators in the remote event that the discharge line should fail to isolate. The RHS is designed to operate in conjunction with the other safety grade systems of the cold shutdown design in order to address the functional requirements of SRP Section 5.4.7 and Branch Technical Position RSB 5-1. The SRP requires that plant safety systems have the capacity to bring the reactor to conditions permitting the operation of the RHS within a reasonable period of time, defined as 36 hours, assuming a single failure of an active component with only either on site or off site power available. The BTP requires that the plant have the capacity to bring the reactor to a cold shutdown condition, within a reasonable period of time following shutdown, assuming the most limiting failure. Therefore, the SRP, in conjunction with the BTP, require that the plant be capable of achieving RHS entry conditions within 36 hours of reactor trip and achieving cold shutdown within an unspecified additional reasonable period of time. The Millstone 3 safety grade cold shutdown design enables the nuclear steam supply to be taken from hot standby to cold shutdown conditions using only safety grade systems, with or without off site power, and with the most limiting single failure. The safety grade cold shutdown design also enables the RCS to be taken from hot standby to conditions that will permit initiation of RHS operation within 36 hours, and then to cold shutdown within an additional 36 hours. Therefore, the Millstone 3 licensing basis is to achieve cold shutdown within 72 hours of reactor trip. Per Section 14.2.7.9, the Millstone 3 instrument air system is non-safety related; therefore, the safety grade cold shutdown design must be capable of achieving cold shutdown without the use of instrument air. 5.4-32 Rev. 30

MPS3 UFSAR With instrument air available and a single failure, cold shutdown conditions can be achieved within 40 hours of reactor trip. With instrument air unavailable and a single failure, limited operator action outside of the control room is required. A loss of instrument air causes the RHS heat exchanger bypass valves to fail open, thus reducing the flow to the RHS heat exchanger. This arrangement reduces the heat removal rate in order to protect the reactor plant component cooling water system from overheating. In order to increase the heat removal rate as the RCS temperature decreases, operator action is required to throttle the operating heat exchanger bypass valve. This limited operator action is justified since it is required only after a single failure and, if initiated 30 hours after reactor trip, will result in cold shutdown conditions within 52 hours of reactor trip. With instrument air unavailable and no single failure, the operator would sequence on the second RHS train once the RCS temperature was reduced to 260°F, and still achieve cold shutdown conditions within 68.5 hours. Therefore, in all cases, a safety grade cold shutdown can be achieved without challenging the usable DWST inventory or overheating the reactor plant component cooling water system, and within the licensing basis of 72 hours. 5.4.7.2.3.6 Refueling Both residual heat removal pumps may be utilized during refueling to pump borated water from the refueling water storage tank to the refueling cavity. During this operation, the residual heat removal pumps are stopped, the isolation valves in the inlet lines of the RHS are closed, the isolation valves to the refueling water storage tank are opened, and the residual heat removal pumps are restarted. The reactor vessel head is lifted slightly. The refueling water is then pumped into the reactor vessel through the normal RHS return lines and into the refueling cavity through the open reactor vessel. The reactor vessel head is gradually raised as the water level in the refueling cavity increases. After the water level reaches the normal refueling level, the residual heat removal pumps are stopped, the inlet isolation valves are opened, the refueling water storage tank supply valves are closed, the residual heat removal pumps are restarted, and the residual heat removal is resumed. During refueling, the RHS is maintained in service with the number of pumps and heat exchangers in operation as required by the heat load. Following refueling, either the residual heat removal pumps or the spent fuel purification system pumps can be used to drain the refueling cavity. If the residual heat removal pumps are used to drain the refueling cavity, the refueling water level is lowered to the top of the reactor vessel flange by pumping water from the RCS to the refueling water storage tank. The vessel head is then replaced and the normal RHS flow path reestablished. The remainder of the water is removed from the refueling canal via a drain connection in the bottom of the canal as described in Section 9.1.3.2. 5.4-33 Rev. 30

MPS3 UFSAR 5.4.7.2.4 Control Each inlet line to the RHS is equipped with a pressure relief valve sized to relieve the flow of one charging pump at the relief valve set pressure. These relief valves also protect the RHS system (and the reactor pressure vessel when the RHS is unisolated from the RCS) from inadvertent overpressurization during plant cooldown or startup. Each valve has a relief flow capacity of 560 gpm at a set pressure of 440 psig. An analysis has been conducted to confirm the capability of the RHS relief valve to prevent overpressurization in the RHS. All credible events were examined for their potential to overpressurize the RHS. These events included normal operating conditions, infrequent transients, and abnormal occurrences. The analysis confirmed that one relief valve has the capability to keep the RHS maximum pressure within code limits. Each discharge line from the RHS to the RCS is equipped with a pressure relief valve to relieve the maximum possible back leakage through the valve separating the RHS from the RCS. Each valve has a relief flow capacity of 20 gpm at a set pressure of 600 psig. These relief valves are located in the low pressure safety injection portion of the ECCS (Figure 5.4-5). The fluid discharged by the suction side relief valves is collected in the pressurizer relief tank. The fluid discharged by the discharge side relief valves is collected in the primary drains transfer tank (Section 9.3.3). The design of the RHS includes three motor-operated gate isolation valves in series on each inlet line between the high pressure RCS and the lower pressure RHS. They are closed during normal operation and are opened only for residual heat removal during a plant cooldown after the RCS pressure is reduced to 375 psig or lower and RCS temperature is reduced to approximately 350°F. During a plant startup, the inlet isolation valves are shut after drawing a bubble in the pressurizer and prior to increasing RCS pressure above 425 psig. Two of the three isolation valves in each inlet line are provided with prevent-open interlocks. It should be noted that when controlling valve 8701A from the ASP, the RCS low pressure interlock is not available. This design feature allows one train of RHR cooling when the control room is inaccessible. Although spurious opening of these two isolation valves in series is considered unlikely, the third isolation valve in each inlet train is closed and deenergized at the MCC to prevent overpressure of RHS piping. The isolation valves closest to the pump suctions are deenergized at the MCC to prevent a fire induced spurious hot short from damaging the valve in the credited train rendering that train non-functional. The two interlocked valves in each RHS subsystem are separately and independently interlocked with pressure signals to prevent their being opened whenever the RCS pressure is greater than approximately 412.5 psia. The two interlocked valves in each RHS subsystem are also separately and independently alarmed if RCS pressure signal is 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 closes the motor-operated valve closest to the pump. The use of two independently powered motor-operated valves in each of the two inlet lines, along with two independent pressure interlock signals for each function, assures a design which meets applicable single failure criteria. Not only more than one single failure, but also different failure 5.4-34 Rev. 30

MPS3 UFSAR mechanisms must be postulated to defeat the function of preventing possible exposure of the RHS to normal RCS operating pressure. These productive interlock designs, in combination with plant operating procedures, provide diverse means of accomplishing the protective function. For further information on the instrumentation and control features refer to Section 7.6.2. The RHS inlet isolation valves are provided with red-green position indicator lights on the main control board and the auxiliary shutdown panel. The indicator lights for the innermost RHS suction MOV are extinguished when deenergized at the MCC in MODES 1, 2 and 3. Isolation of the low pressure RHS from the high pressure RCS is provided on the discharge side by a normally open motor-operated valve and three check valves in series. These check valves are located in the ECCS and their testing is described in Section 6.3.4.2. 5.4.7.2.5 Applicable Codes and Classifications The entire RHS is designed as Nuclear Safety Class 2, except the suction isolation valves inside containment which are Class 1. Component codes and classifications for the RHS and the other systems relied upon for safety grade cold shutdown are given in Section 3.2. 5.4.7.2.6 System Reliability Considerations General Design Criterion 34 requires that a system to remove residual heat be provided. The safety function of this system is to transfer fission product decay heat and other residual heat from the core at a rate sufficient to prevent fuel or pressure boundary design limits from being exceeded. Safety grade systems are provided in the plant design to perform this safety function. The 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.

For LOCA conditions, the safety grade system which performs the function of removing residual heat from the reactor core is the ECCS, which operates in conjunction with the charging pump cooling water system, safety injection pump cooling water system and the service water system. The auxiliary feedwater system, along with the steam generator safety valves and steam generator atmospheric relief bypass valves, provides a completely separate, independent, and diverse means of performing the safety function of removing residual heat, which is normally performed by the 5.4-35 Rev. 30

MPS3 UFSAR RHS system when RCS temperature is less than 350°F. The auxiliary feedwater system is capable of performing this function for an extended period of time following plant shutdown. In order to achieve conditions that permit initiation of RHS operation, two other functions (boration and depressurization) must be performed. The boration function is normally provided by the CHS. 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. In addition, all charging may be lost as a result of certain postulated fire conditions (see FSAR Section 9.5.1 and the FPER for SIH system performance requirements). For these conditions, the SIH pumps will provide the required RCS inventory and boration flow to achieve safe shutdown. When the reactor coolant pumps are not available, due to loss of off site power or following a manual pump trip, the depressurization function may be provided by the CHS. The normal function and inherent reliability of the CHS is discussed in detail in Section 9.3.4.1. The RHS is provided with two residual heat removal pumps, and two residual heat removal heat exchangers arranged in two separate, independent flowpaths. To assure reliability, each residual heat removal pump is connected to a different emergency bus. Each residual heat removal train is isolated from the RCS on the suction side by three motor-operated valves in series. Each motor-operated valve receives power via a separate motor control center, and one of the three valves in series in the same train receives power from a different emergency bus than do the other two valves and the pump. Two of the suction isolation valves in each RHS subsystem are also interlocked and alarmed to prevent exposure of the RHS to the normal operating pressure of the RCS (Section 5.4.7.2.4). RHS operation for normal conditions and for major failures is accomplished from the control room with limited operator action outside the control room. The redundancy in the RHS system design provides the system with the capability to maintain its cooling function even with major single failures, such as failure of an RHS pump, valve, or heat exchanger, since the redundant train can be used for continued heat removal. Should it be necessary to take the plant to cold shutdown conditions using only safety grade systems, portions of the RCS (Section 5.4.15) and the ECCS (Section 6.3) are also relied upon for boration, letdown, makeup and depressurization. These safety grade provisions would be used only upon failure of the equipment normally used for the given function. Boration is accomplished by using the centrifugal charging pumps to supply borated water from the boric acid tanks to the RCS via the charging bypass line or the high head safety injection lines in the ECCS. See Section 9.3.4.2 for further details. Letdown to accommodate boration and any other addition to the RCS inventory is provided by the reactor vessel head vent system letdown path to the pressurizer relief tank. See Section 5.4.15.2 for further details. Depressurization is accomplished by discharging RCS inventory via the safety grade pressurizer power-operated relief valves. Two parallel lines are provided with solenoid-actuated valves which 5.4-36 Rev. 30

MPS3 UFSAR can be remotely operated to relieve to the pressurizer relief tank. The ECCS accumulators are also provided with safety grade isolation and venting capability in order to ensure that depressurization can be completed. The pressurizer relief tank, the vessel head letdown valves, and the pressurizer relief valves are described in Sections 5.4.11, 5.4.12, and 5.4.13, respectively, and are shown on Figure 5.1-1. The systems used for boration/inventory control and for depressurization are remotely operable with either on site or off site power available and assuming the most limiting single failure. A failure modes and effects analysis (FMEA) of the portions of the RCS, ECCS, and CHS that are used for safety grade cold shutdown is included in the RHS - Cold Shutdown Operations - FMEA (Table 5.4-9). The reliability of these systems ensures that conditions permit RHS operation can be allowed. RHS operation for normal conditions, even with a major failure is accomplished from the control room with limited operator action outside the control room. The redundancy in the RHS design provides the system with the capability to maintain its cooling function even with a major single failure, such as failure of a residual heat removal pump, valve, or heat exchanger or of an emergency power source, without impact on the redundant trains continued heat removal. The only effect would be an extension of the time required for cooldown. The capability of the RHRS or safety grade cooldown is demonstrated in the RHS - Cold Shutdown Operation - FMEA (Table 5.4-9). 5.4.7.2.7 Manual Actions The RHS is designed to be fully operable from the control room for normal operation except for opening the outermost and innermost pump suction valve in each train. The outermost and innermost valves are closed and deenergized at the MCC. The outermost MOVs MCCs are located in the auxiliary building in the vicinity of the rod drive control center. The innermost MOVs MCCs are located in the ESF building on the 36 foot level. The MCCs are accessible should RHS operability be required after an accident (FSAR Table 12.3-3). Manual operations required of the operator include: opening the suction and discharge isolation valves, positioning the flow control valves downstream of the residual heat exchangers, and starting the residual heat removal pumps. If the plant is in mode 1, 2, or 3, all three of the RHR isolation valves in each flow path require manual closure upon alarm of valve open and RCS pressure greater than 440 psig. 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. Assuming the most limiting single failure, the RHS can still be operated with limited operator action required outside of the control room, with the only effect being an extension in the cooldown time. Manual operation consists of opening one of the suction/isolation valves, and in the event instrument air is not available, throttling the operating heat exchanger bypass valve to increase RHS heat exchanger flow; see Section 5.4.7.2.3.5. 5.4-37 Rev. 30

MPS3 UFSAR 5.4.7.3 Performance Evaluation The performance of the RHS system in reducing reactor coolant temperature is evaluated through the use of heat balance calculations on the RCS and CCP at stepwise intervals following the initiation of RHS operation. Heat removal through the RHS and CCP heat exchangers is calculated at each interval by use of standard water-to-water heat exchanger performance correlations; the resultant fluid temperatures for the RHS and CCP systems are calculated and used as input to the next intervals heat balance calculation. Assumptions utilized in the series of heat balance calculations describing plant RHS cooldown are as follows:

1. RHS operation is initiated no earlier than four hours after reactor shutdown.

2. RHS operation begins at a reactor coolant hot leg temperature of 350°F or below.

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 145°F for normal and 145°F for a safety grade cold shutdown.

5. One reactor coolant pump is assumed running until the coolant temperature is at 160°F 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.

5.4.7.4 Preoperational Testing Preoperational testing of the RHS is addressed in Chapter 14. 5.4.8 REACTOR WATER CLEANUP SYSTEM This is a BWR requirement and, as such, does not apply to Millstone 3, which is a PWR plant. 5.4.9 MAIN STEAMLINES AND FEEDWATER PIPING Main steamlines and feedwater piping are discussed in Sections 10.3 (main steam supply system), 10.4.7 (condensate and feedwater systems), and 10.4.9 (auxiliary feedwater system). 5.4.10 PRESSURIZER 5.4.10.1 Design Bases The general configuration of the pressurizer is shown on Figure 5.4-8. The design data of the pressurizer are given in Table 5.4-10. Codes and material requirements are provided in Section 5.2. 5.4-38 Rev. 30

MPS3 UFSAR The pressurizer provides a point in the RCS where liquid and vapor can be maintained in equilibrium under saturated conditions for pressure and control purposes, for steady state operations and during transients. 5.4.10.1.1 Pressurizer Surge Line The surge line is sized to minimize the pressure drop between the RCS and the safety valves in order to obtain maximum allowable discharge flow from the safety valves, as necessary. The surge line and the thermal sleeves at each end are designed to withstand the thermal stresses resulting from volume surges of relatively hotter or colder water which may occur during operation. The pressurizer surge line nozzle diameter is given in Table 5.4-10 and the pressurizer surge line dimensions are shown on Figure 5.1-1. 5.4.10.1.2 Pressurizer The volume of the pressurizer is equal to, or greater than, the minimum volume of steam, water, or total 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 5.4.10.2 Design Description 5.4.10.2.1 Pressurizer Surge Line The pressurizer surge line connects the pressurizer to one reactor hot leg providing for continuous coolant volume pressure adjustments between the RCS and the pressurizer.

5.4-39 Rev. 30

MPS3 UFSAR 5.4.10.2.2 Pressurizer The pressurizer as shown on Figure 5.4-8 is a vertical, cylindrical vessel with hemispherical top and bottom heads constructed of carbon steel, with austenitic stainless steel cladding on all internal surfaces exposed to the reactor coolant. A stainless steel liner or tube may be used in lieu of cladding in some nozzles. The surge line nozzle and removable electric heaters are installed in the lower pressurizer head. The heaters are removable for maintenance or replacement. A thermal sleeve is provided to minimize stresses in the surge line nozzle. A retaining screen is located above the nozzle to prevent any foreign matter from entering the RCS. Baffles in the lower section of the pressurizer prevent an insurge of cold water from flowing directly to the steam/water interface and assist mixing. Spray line nozzles, relief and safety valve connections are located in the upper head of the vessel. Spray flow is modulated by automatically controlled air-operated valves. The spray valves also can be operated manually by a switch in the control room. A small continuous spray flow is provided through a manual bypass valve around the power-operated spray valves to assure that the pressurizer liquid is homogeneous with the coolant and to prevent excessive cooling of the spray piping. During an outsurge from the pressurizer, flashing of water to steam and generating of steam by automatic actuation of the heaters retain the pressure above the minimum allowable limit. During an insurge from the RCS, the spray system, which is fed from two cold legs, condenses steam in the vessel to prevent the pressurizer pressure from reaching the setpoint of the power-operated relief valves for normal design transients. Heaters are energized on high water level during insurge to heat the subcooled surge water that enters the pressurizer from the reactor coolant loop. Material specifications are provided in Table 5.2-7 for the pressurizer, pressurizer relief tank, and the surge line. Design transients for the components of the RCS are discussed in Section 3.9(N).1. Additional details on the pressurizer design cycle analysis are given in Section 5.4.10.3.5. Spray Line Temperatures Temperatures in the spray lines from the cold legs of two loops are measured and indicated. Alarms to warn the operator from these signals are actuated by low spray water temperature. Alarm conditions indicate insufficient flow in the spray lines. Safety and Relief Valve Discharge Temperatures Temperatures in the pressurizer safety and relief valve discharge lines are measured and indicated. An increase in a discharge line temperature is an indication of leakage or relief through the associated valve. 5.4-40 Rev. 30

MPS3 UFSAR 5.4.10.3 Design Evaluation 5.4.10.3.1 System Pressure Whenever a steam bubble is present within the pressurizer, RCS pressure is maintained by the pressurizer. Analyses indicate that proper control of pressure is maintained for the operating conditions. A safety limit has been set to ensure that the RCS pressure does not exceed the maximum transient value allowed under the ASME Code, Section III, and thereby assure continued integrity of the RCS components. Evaluation of plant conditions of operation which follow indicate that this safety limit is not reached. During startup and shutdown, the rate of temperature change in the RCS is controlled by the operator. Heatup rate is controlled by pump energy and by the pressurizer electrical heating capacity. This heatup rate takes into account the continuous spray flow provided to the pressurizer. When the reactor core is shutdown, the heaters are deenergized. When the pressurizer is filled with water, i.e., during initial system heatup, and near the end of the second phase of plant cooldown, RCS pressure is maintained by the letdown flow rate via the Residual Heat Removal System. 5.4.10.3.2 Pressurizer Performance The normal operating water volume at full load conditions is a percentage of the free internal vessel volume. Under part load conditions, the water volume in the vessel is reduced for proportional reductions in plant load. The various plant operating transients are analyzed and the design pressure is not exceeded with the pressurizer design parameters as given in Table 5.4-10. 5.4.10.3.3 Pressure Setpoints The RCS design and operating pressure together with the safety, power relief and pressurizer spray valves setpoints, and the protection system setpoint pressures are listed in Table 5.4-11. The design pressure allows for operating transient pressure changes. The selected design margin considers core thermal lag, coolant transport times and pressure drops, instrumentation and control response characteristics, and system relief valve characteristics. 5.4.10.3.4 Pressurizer Spray Two separate, automatically controlled spray valves with remote manual overrides are used to initiate pressurizer spray. In parallel with each spray valve is a manual throttle valve which permits a small continuous flow through both spray lines to reduce thermal stresses and thermal shock when the spray valves open, and to help maintain uniform water chemistry and temperature in the pressurizer. Temperature sensors with low alarms are provided in each spray line to alert the 5.4-41 Rev. 30

MPS3 UFSAR operator to insufficient bypass flow. The layout of the common spray line piping to the pressurizer forms a water seal which prevents the steam buildup back to the control valves. The spray rate is selected to prevent the pressurizer pressure from reaching the operating setpoint of the power relief valves during a step reduction in power level of ten percent of full load. The pressurizer spray lines and valves are large enough to provide adequate spray using as the driving force the differential pressure between the surge line connection in the hot leg and the spray line connection in the cold leg. 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. The spray valves and spray line connections are arranged so that the spray will operate when one reactor coolant pump is not operating. The line may also be used to assist in equalizing the boron concentration between the reactor coolant loops and the pressurizer. A flow path from the chemical and volume control system to the pressurizer spray line is also provided. This additional facility provides auxiliary spray to the vapor space of the pressurizer during cooldown when the reactor coolant pumps are not operating. The thermal sleeves on the pressurizer spray connection and the spray piping are designed to withstand the thermal stresses resulting from the introduction of cold spray water. 5.4.10.3.5 Pressurizer Design Analysis The 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 5.4-42 Rev. 30

MPS3 UFSAR 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.

5.4.10.3.6 Natural Circulation Following Loss of Off Site Power One bank of pressurizer backup heaters (manually connected to an emergency power source within 60 minutes) is sufficient to maintain natural circulation following a loss of off site power. 5.4.10.4 Inspection and Testing Requirements The pressurizer is designed and constructed in accordance with ASME Code Section III. To implement the requirements of ASME Code Section XI the following welds are designed and constructed to present a smooth transition surface between the parent metal and the weld metal. The 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 The liner within the safe end nozzle region extends beyond the weld region to maintain a uniform geometry for ultrasonic inspection.

Peripheral support rings are furnished for the removable insulation modules. The pressurizer quality assurance program is given in Table 5.4-12. 5.4-43 Rev. 30

MPS3 UFSAR 5.4.10.5 Instrumentation Requirements Refer to Chapter 7 for details of the instrumentation associated with pressurizer pressure, level, and temperature. 5.4.11 PRESSURIZER RELIEF DISCHARGE SYSTEM The pressurizer relief discharge system collects, cools and directs for processing the steam and water discharged from the various safety and relief valves in the containment. The system consists of the pressurizer relief tank, the safety and relief valve discharge piping, the relief tank spray header and associated piping, and the tank nitrogen supply, the vent to containment and the drain to the reactor plant gaseous drains. Table 5.4-14 shows these valves with reference to their FSAR figures. 5.4.11.1 Design Basis Codes and materials of the pressurizer relief tank Figure 5.4-7 and associated piping are given in Section 5.2. Design data for the tank are given in Table 5.4-13. The system design is based on the requirement to absorb a discharge of steam equivalent to 110 percent of the full power pressurizer steam volume. The steam volume requirement is approximately that which would be experienced if the plant were to suffer a complete loss of load accompanied by a turbine trip but without the resulting reactor trip. The minimum volume of water in the pressurizer relief tank is determined by the energy content of the steam to be condensed and cooled, by the assumed initial temperature of the water, and by the desired final temperature of the water volume. The initial water temperature is assumed to be 120°F, which corresponds to the design maximum expected containment temperature for normal conditions. Provision is made to permit cooling the tank should the water temperature rise above 120°F during plant operation. The design final temperature is 200°F, which allows the contents of the tank to be drained directly to the reactor plant gaseous drains system without cooling. The vessel saddle supports and anchor bolt arrangement are designed to withstand the loadings resulting from a combination of nozzle loadings acting simultaneously with the vessel dead weight loadings. 5.4.11.2 System Description The piping and instrumentation diagram for the pressurizer relief discharge system is given on Figure 5.1-1. The steam and water discharged from the various safety and relief valves inside containment is routed to the pressurizer relief tank if the discharged fluid is of reactor grade quality. Table 5.4-14 provides an itemized list of valves discharging to the tank together with references of the corresponding piping and instrumentation diagrams. 5.4-44 Rev. 30

MPS3 UFSAR The tank normally contains water and a predominantly nitrogen atmosphere. In order to obtain effective condensing and cooling of the discharged steam, the tank is installed horizontally and the steam is discharged through a sparger pipe located near the bottom, under the water level. The sparger holes are designed to insure a resultant steam velocity close to sonic. The tank is also equipped with an internal spray and a drain which are used to cool the water following a discharge. Cold water is drawn from the primary grade water system, and the content of the tank is drained to the reactor plant gaseous drains system. The nitrogen gas blanket is used to control the atmosphere in the tank and to allow room for the expansion of the original water plus the condensed steam discharge. The tank gas volume is calculated using a final pressure based on an arbitrary design pressure of 100 psig. The design discharge raises the worst case initial conditions to 50 psig, a pressure low enough to prevent fatigue of the rupture disks. Provision is made to permit the gas in the tank to be periodically analyzed to monitor the concentration of hydrogen and/or oxygen. The contents of the vessel are drained to the reactor plant gaseous drains system. 5.4.11.2.1 Pressurizer Relief Tank The general configuration of the pressurizer relief tank is shown on Figure 5.4-7. The tank is a horizontal, cylindrical vessel with elliptical dished heads. The vessel is constructed of austenitic stainless steel and is overpressure protected in accordance with ASME Code Section VIII, Division 1, by means of two safety heads with stainless steel rupture discs. A flanged nozzle is provided on the tank for the pressurizer discharge line connection to the sparger pipe. The tank is also equipped with an internal spray connected to a cold water inlet and with a bottom drain, which are used to cool the tank following a discharge. 5.4.11.3 Safety Evaluation The pressurizer relief discharge system does not constitute part of the reactor coolant pressure boundary per 10 CFR 50, Section 50.2, since all of its components are downstream of the reactor coolant system safety and relief valves. Thus, General Design Criteria 14 and 15 are not applicable. Furthermore, complete failure of the auxiliary systems serving the pressurizer relief tank does not impair the capability for safe plant shutdown. The design of the system piping layout and piping restraints is consistent with Regulatory Guide 1.46. Compliance to Regulatory Guide 1.46 by restraining the safety and relief valve discharge piping so that integrity and operability of the valves are maintained in the event of a rupture. Regulatory Guide 1.67 is not applicable since the system is not an open discharge system. The pressurizer relief discharge system is capable of handling the design discharge of steam without exceeding the design pressure and temperature. The volume of water in the pressurizer relief tank is capable of absorbing the heat from the assumed discharge maintaining the water 5.4-45 Rev. 30

MPS3 UFSAR temperature below 200°F. If a discharge exceeding the design basis should occur, the relief device on the tank would pass the discharge through the tank to the containment sumps. The rupture discs on the relief tank have a relief capacity equal to or greater than the combined capacity of the pressurizer safety valves. The tank design pressure is twice the calculated pressure resulting from the design basis safety valve discharge described in Section 5.4.11.1. The tank and rupture discs holders are also designed for full vacuum to prevent tank collapse if the contents cool following a discharge without nitrogen being added. The discharge piping from the safety and relief valves to the relief tank is sufficiently large to prevent backpressure at the safety valves from exceeding 20 percent of the setpoint pressure at full flow. 5.4.11.4 Instrumentation Requirements The pressurizer relief tank pressure transmitter provides an indication of pressure relief tank pressure. An alarm is provided to indicate high tank pressure. The pressurizer relief tank level transmitter supplies a signal for an indicator with high and low level alarms. The temperature of the water in the pressurizer relief tank is indicated, and an alarm actuated by high temperature informs the operator that cooling of the tank contents is required. 5.4.11.5 Inspection and Testing Requirements The system components are subject to non destructive and hydrostatic testing during construction in accordance with Section VIII, Division 1 of the ASME Code (Table 5.4-12). During plant operation, periodic visual inspections and preventive maintenance are conducted on the system components according to normal industrial practice. 5.4.12 VALVES 5.4.12.1 Design Bases As noted in Section 5.2, all valves out to and including the second valve normally closed or capable of automatic or remote closure, larger than three-quarter inch, are ANS Safety Class 1, and ASME III, Code Class 1 valves. All three-quarter inch or smaller valves in lines connected to the reactor coolant system (RCS) are Class 2 since the interface with the Class 1 piping is provided with suitable orificing for such valves. Exceptions to this are the pressurizer steam space isolation valves and RHS PLTB lines which are ASME III Class 1 with the orifice located downstream of the isolation valve. Design data for the RCS are given in Table 5.4-15. For a check valve to qualify as part of the RCS it must be located inside the containment system. When the second of two normally open check valves is considered part of the RCS (as defined in 5.4-46 Rev. 30

MPS3 UFSAR Section 5.1), and verification of proper valve closure is required, non-intrusive techniques (e.g., radiography) are employed to perform this verification. To ensure that the valves meet the design objectives, the materials of construction minimize corrosion/erosion and ensure compatibility with the environment, leakage is minimized to the extent practicable by design, and stresses are maintained within the limits of the ASME Section III Code. 5.4.12.2 Design Description All valves in the RCS are constructed primarily of stainless steel. All manual and motor-operated valves in the RCS which are 2.5 inches and larger were originally provided with double packed stuffing boxes and intermediate lantern ring leakoff connections. The PORV block valves were replaced with valves that do not require leakoff connections. All throttling control valves, regardless of size, are provided with double stuffing boxes and with stem leakoff connections. All leakoff connections are piped to a closed collection system. Leakage to the atmosphere is essentially zero for these valves. Gate valves at the engineered safety features interface are wedge design and are essentially straight through. The wedges are flexwedge or solid. All gate valves have backseats. Check valves are either swing type or tilting disc for size 2.5 inches and larger. All check valves which contain radioactive fluid are stainless steel and do not have body penetrations other than the inlet, outlet and bonnet. The check hinge is services through the bonnet. The accumulator check valve is designed such that at the required flow the resulting pressure drop is within the specified limits. All operating parts are contained within the body. The disc has limited rotation to provide a change of seating surface and alignment after each valve opening. The reactor coolant loop stop valves are remotely controlled motor- operated gate valves which permit any loop to be isolated from the reactor vessel. One valve is installed on each hot leg and one on each cold leg. The design of the valve is basically the same as noted above with the additional feature that each set of packing is capable of being tightened independently of the other sets of packing. Also, the valve is a paralleled disc design. RCS parameters are given in Table 5.4-15. 5.4.12.3 Design Evaluation The design/analysis requirements for Class 1 valves, as discussed in Section 5.2, limit stress to levels which ensure the structural integrity of the valves. In addition, the testing programs described in Subsection 3.9N.3.2.2 demonstrate the ability of the valves to operate as required during anticipated and postulated coolant conditions. Reactor coolant chemistry parameters are specified in the design specifications to assure the compatibility of valve construction materials with the reactor coolant. To ensure that the reactor coolant continues to meet these parameters, the chemical composition of the coolant is analyzed periodically as discussed in the technical specifications. 5.4-47 Rev. 30

MPS3 UFSAR The above requirements and procedures, coupled with the previously described design features for minimizing leakage, ensure that the valves perform their intended functions as required during plant operation. 5.4.12.4 Tests and Inspections Tests and examinations of RCS valves are performed in accordance with the requirements of the ASME Code, Section III. There are no full penetration welds within valve body walls. Valve nondestructive examinations are given in Table 5.4-16. The tests and inspection discussed in Section 3.9 are performed to ensure the operability of active valves. In place operational testing is performed on valves as required by the ASME Code, Section XI, as indicated in the Technical Specifications. Valves are accessible for disassembly and internal visual inspection to the extent practical. Inservice inspection is discussed in Section 5.2.4. 5.4.13 SAFETY AND RELIEF VALVES 5.4.13.1 Design Bases The pressurizer safety valves are designed to accommodate the maximum surge resulting from complete loss of load. Sizing of the pressurizer safety valves is discussed in Section 5.2.2. The pressurizer power-operated relief valves are designed to limit pressurizer pressure to a value below the fixed high pressure reactor trip setpoint. They are designed to fail to the closed position on power loss. 5.4.13.2 Design Description The pressurizer safety valves are of the pop type. The valves are spring loaded, open by direct fluid pressure action, and have back pressure compensation features. The piping connecting the pressurizer nozzles to their respective safety valves are shaped in the form of a loop seal. However, loop seal drains are maintained open to eliminate the formation of a water seal. EPRI testing showed water seals cause substantial safety valve discharge pipe loads. Condensate resulting from normal heat losses drains back to the pressurizer via a drain tapped to the low point of the loop seal. The pressurizer power operated relief valves are solenoid operated valves which are operated automatically or by remote manual control. The pressurizer power operated relief valves are provided with a positive position indication in the control room (open/closed indication lights which are activated by limit switches). Remotely operated stop valves are provided to isolate the power operated relief valves if excessive leakage develops. Positive position indication (open/closed) for the stop valves is located in the control room. 5.4-48 Rev. 30

MPS3 UFSAR The power operated relief valves (PORVs), the PORV block valves, and pressurizer level instrumentation are powered from the Class IE power system (Section 8.3.1). Temperatures in the pressurizer safety and relief valve discharge lines are measured and indicated in the control room. An increase in a discharge line temperature is an indication of leakage or relief through the associated valve. Valves identical to Millstone 3s power operated relief valves (PORVs) and safety valves were tested, in a program conducted by EPRI under full flow, expected saturated steam operating conditions. Power operated relief valve tests were completed in August 1981 and safety valve tests were completed in December 1981. Testing of valves was performed and test results were evaluated by Westinghouse and a report was generated. Additionally, testing of valves similar to the PORV block valves, is documented in Duke Engineering Services Inc. Report TR-161, Dynamic Test Program for BW/IP International, Inc. - Valve Division Inch Parallel Disk Gate Motor-Operated Valve, dated 9/8/97. This test verified valve operability under full flow conditions. The PORVs were analyzed by Westinghouse in 1998 and qualified for operation during subcooled water conditions. The block valves were similarly qualified to operate with subcooled water in accordance with GL89-10 requirements per the licensee's program. Design parameters for the pressurizer safety and power operated relief valves are given in Table 5.4-17. 5.4.13.3 Design Evaluation The pressurizer safety valves prevent RCS pressure from exceeding 110 percent of system design pressure, in compliance with the ASME Code. The pressurizer power operated relief valves prevent actuation of the fixed reactor high pressure trip for all design transients up to and including the design step load decreases with steam dump. The relief valves also limit the opening of the spring loaded safety valves. The pressurizer power-operated relief valves also provide a safety grade means to depressurize the RCS for safety grade cold shutdown. See Section 5.4.7.2.3.5. 5.4.13.4 Inspection and Testing Requirements Tests and examination of pressurizer safety and relief valves are performed in accordance with the requirements of the ASME Code, Section III. There are no full penetration welds within valve body walls. Valve nondestructive examinations are given in Table 5.4-16. The tests and inspections discussed in Section 3.9 are performed to ensure the operability of active valves. In place operational testing is performed on valves as required by the ASME OM Code as indicated in the technical specifications. 5.4-49 Rev. 30

MPS3 UFSAR Valves are accessible for disassembly and internal visual inspection to the extent practical. Inservice inspection is discussed in Section 5.2.4. 5.4.14 COMPONENT SUPPORTS Component supports are part of a safety system that permits movement to accommodate thermal expansion of the reactor coolant loops during plant operation while providing restraint to the reactor coolant system (RCS) components during accident conditions. Included as part of the reactor coolant system are four steam generators, four reactor coolant pumps, one pressurizer, and the reactor vessel. Supports for these components are designed to maintain their necessary safety functions during normal operating conditions, postulated safe shutdown earthquake (SSE) conditions, and accidents such as postulated extremes of pipe rupture acting concurrently with the SSE. Postulated pipe ruptures are assumed to be double-ended or longitudinal. These failures are assumed to occur in either the reactor coolant piping, pressurizer surge piping, or main steam line piping (Section 3.6). Section 3.7B discusses seismic design of supports for reactor coolant piping. Detailed design bases and results of qualification analyses are contained in Section 3.9B.3. 5.4.14.1 Description The supports are comprised of forged, cast, and welded steel sections. Linear type supports are used in all cases except for the RPV support which is a plate and shell support. The attachments to the supported equipment are non-integral and are bolted to or bear against the components. Attachment to the interface to building structure is achieved by embedded anchor bolts and shear lugs. 5.4.14.1.1 Reactor Vessel Structural Support (RVSS) The support for the reactor vessel (the neutron shield tank) is a cylindrical double-wall structure that surrounds and supports the reactor pressure vessel, and accommodates all applicable loading conditions. The RVSS transfers all loading conditions from the reactor vessel to the primary shield wall through groutings, and to the concrete anchors at its base. The RVSS also provides support for the out-of-core neutron detector monitors. The annular portion of the tank is filled with water to provide neutron shielding and a thermal barrier for protection of the surrounding structural concrete. The water is circulated through an external heat exchanger to maintain proper cooling for the system. The reactor vessel is supported at four nozzles on leveling devices mounted on top of the neutron shield tank. The functional requirement of the RPV leveling devices is to provide vertical adjustment at each RPV nozzle restraint pad during installation of the reactor vessel. During all plant conditions, the leveling device is designed to transfer only downward vertical loads from the RPV to the RVSS. Upward and side loads from the RPV are resisted by gib keys and gib gussets. The RVSS is shown on Figures 5.4-9 and 5.4-10. 5.4.14.1.2 Steam Generator Supports The supports for each steam generator consist of vertical, upper and lower lateral supports. 5.4-50 Rev. 30

MPS3 UFSAR Four individual column assemblies provide the vertical support for each steam generator. Each column assembly consists of a lower clevis, column lug, extension tube and upper column clevis. The upper clevises are bolted to the steam generator tube sheet and the lower clevises are anchored to the concrete floor. The four vertical column assemblies transmit vertical forces from the steam generator to the cubicle floor. The lateral (upper and lower) supports are provided by eight double acting hydraulic snubbers. Each lateral support has four hydraulic snubber assemblies which permit motion of the steam generator due to thermal expansion of the RCS. Vertical steam generator thermal motions are accommodated by the upper lateral support assembly. The hydraulic snubbers are designed to lock and resist dynamic forces which result from seismic and/or pipe rupture conditions. The lower lateral support assemblies are bolted to the steam generator tube sheet and the concrete wall. The upper lateral support assemblies are bolted to the steam generator restraint ring and the concrete wall. The steam generator supports are shown on Figures 5.4-11 and 5.4-12. 5.4.14.1.3 Reactor Coolant Pump Supports The reactor coolant pump is supported by three pin ended columns which provide vertical support while allowing free movement in the horizontal plane. Three independent hydraulic snubber assemblies, connected to the pump support and the reactor shield wall, provide lateral support for the pump during dynamic loading conditions while allowing thermal expansion of the RCS. The pump supports are shown on Figures 5.4-11 and 5.4-13. 5.4.14.1.4 Pressurizer Support There is one pressurizer located in the pressurizer cubicle of the containment building. The pressurizer is an integral part of the RCS and is connected to the hot leg of Loop 2 by the surge line (Section 5.4.10). The pressurizer is skirt mounted to a ring girder which is suspended from the operating floor by four hanger columns. Four horizontal support restraints, which attach the ring girder to the building structure, prevent all motions except vertical translation and horizontal rotation. Integral lugs located on the pressurizer near the center of gravity fit into striker plate assemblies embedded in the concrete floor at elevation 51 feet 4 inches These brackets allow thermal expansion of the pressurizer but resist horizontal and torsional displacements resulting from seismic and/or blowdown forces. The pressurizer support is shown on Figure 5.4-14. 5.4.14.1.5 Pressurizer Safety Valve Supports The pressurizer safety valves are mounted on a ring girder that is located on the upper portion of the pressurizer. Support flanges are bolted to the valve body which in turn are connected to the ring girder. The ring girder is supported by four columns welded to the ring and pin-connected to clevis lugs attached to the pressurizer gussets. The supports are designed to withstand the loads 5.4-51 Rev. 30

MPS3 UFSAR imposed by the safety relief piping which consist of dead weight, thermal, seismic, and simultaneous discharge of all safety valves. The pressurizer safety valve supports are shown on Figure 5.4-15. 5.4.14.2 Design Basis The final designs, established for these supports, are based on maximum load combinations. These load combinations are derived from a system analysis using blowdown forcing functions developed by Westinghouse. The maximum loads are a combination of dead weight, SSE (horizontal plus vertical), and a pipe rupture condition for each support structure. These maximum loads are used as the faulted conditions for support design. From these final support designs, the inertia, stiffness, and damping quantities are evaluated and used as a basis for further refinement by elastic structural dynamic analysis, as described in Section 3.7B.3. The designs are revised according to the computer results for more uniform stress distribution. This cycle is repeated, as required, to achieve sufficient optimization of structural design efficiency for the supports (Section 3.9B.3). The loading categories, load combinations, and stress limits for the supports are shown in Table 5.4-18. The steam generator, reactor coolant pump and pressurizer supports are classified as linear type supports. For these linear type supports subject to design, normal, upset, and emergency operating loads, the stress limits are based on the elastic analysis of the ASME III Code, Subsection NA, Appendix XVII-2000. The reactor vessel support, neutron shield tank, is a combination linear and plate and shell-type support. The stress limits for linear type supports are per Appendix XVII-2000 and the stress limits for plate and shell type supports are per NF-3220 of the ASME Code, Section III. Faulted operating conditions for all component supports have been analyzed in accordance with Appendix F of the ASME III Code. 5.4.14.3 Evaluation Detailed evaluation ensures the design adequacy and structural integrity of the reactor coolant loop and the primary equipment supports system. This detailed evaluation is made by comparing the analytical results with established criteria for acceptability as described in Section 3.9B.3. Structural analyses are performed to demonstrate design adequacy of the plant in case of an OBE or SSE and/or LOCA conditions. Loads which the system is expected to encounter during plant operation (thermal, weight, pressure) are applied and stresses are compared to allowable values as described in Section 3.9B.3. The safe shutdown earthquake (SSE) and design basis LOCA resulting in a rapid depressurization of the system, are required design conditions for public health and safety. The methods used for the analysis of the SSE and LOCA conditions are given in Section 3.9B.1. 5.4-52 Rev. 30

MPS3 UFSAR 5.4.14.4 Tests and Inspections Weld inspection and standards are specified in accordance with Section V of the ASME Code. Welder qualifications and welding procedures are specified in accordance with Section IX of the ASME Code. 5.4.15 REACTOR VESSEL HEAD VENT SYSTEM The reactor vessel head vent system (RVHVS) (Figure 5.1-1) removes non condensable gases or steam from the reactor vessel head. This system is designed to mitigate a possible condition of inadequate core cooling or impaired natural circulation resulting from the accumulation of nonconsumable gases in the RCS. Additionally, the system provides the safety grade letdown path to the pressurizer relief tank for a safety grade cold shutdown. The design of the RVHVS is in accordance with the requirements of NUREG-0737. 5.4.15.1 Design Basis The RVHVS is designed to remove non consumable gases or steam from the reactor coolant system via remote manual operations from the control room. The system discharges to the pressurizer relief tank. Additionally, a letdown flow path is provided from the reactor vessel head vent to the excess letdown heat exchanger in the chemical and volume control system (CHS). The RVHVS is designed to vent a volume of hydrogen at system design pressure and temperature approximately equivalent to one half of the reactor coolant system volume in one hour. The system provides for venting the reactor vessel head by using only safety grade equipment. Letdown to accommodate boration during a safety grade cold shutdown is also provided by this path. To ensure reliability of this function, the letdown line is provided with parallel solenoid valves. The valves are designed to fail closed such that both lines can always be isolated, and the two valves in the same line are powered by the same power train such that at least one line can always be made available. Downstream of these isolation valves, the safety grade path directs letdown to the pressurizer relief tank via parallel solenoid valves. All piping and equipment from the vessel head vent up to and including the second isolation valve in each flow path are designed and fabricated in accordance with ASME Section III, Class 1 requirements. The piping and equipment in the flow paths from the isolation valve to the modulating valves and from the isolation valves to the excess letdown heat exchanger are designed and fabricated in accordance with ASME Section III, Class 2 requirements. The remainder of the piping and equipment is non-nuclear safety. The isolation valves are included in the Westinghouse valve operability program which is an acceptable alternative to Regulatory Guide 1.48. These valves are qualified to IEEE 323-1974, 344-1975, and 382-1972 (Section 3.11). All supports and support structures comply with the requirements of the ASME Code. 5.4-53 Rev. 30

MPS3 UFSAR The analysis of the rector vessel head vent piping is based on the following plant operating conditions 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)

Loads generated by the operating basis earthquake (OBE) and by valve thrust during venting

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.

The Class 1 piping used for the reactor vessel head vent is 1 inch schedule 160 and, therefore, in accordance with ASME III, is analyzed following the procedures of NC-3600 for Class 2 piping. For all plant operating conditions listed above, the piping stresses are shown to meet the requirements of equations (8), (9), and (10) or (11) of ASME III, NC-3600, with a design temperature of 650°F and a design pressure of 2,485 psig. 5.4.15.2 System Description The RVHVS consists of two parallel flow paths with redundant isolation valves in each flow path. The venting operation uses only one of these flow paths at any one time. The equipment design parameters are listed in Table 5.4-19. The active portion of the system consists of four one inch open/close solenoid-operated isolation valves connected to the existing 1 inch vent pipe, which is located near the center of the reactor vessel head. The system design with two valves in series in each flow path minimizes the possibility of reactor coolant pressure boundary leakage. The isolation valves in one flow path are powered by one vital power supply and the valves in the second flow path are powered by a second vital power supply. The isolation valves are fail closed normally closed valves. The vent system piping is supported to ensure that the resulting loads and stresses on the piping and on the vent connection to vessel head are acceptable. 5.4-54 Rev. 30

MPS3 UFSAR 5.4.15.3 Safety Evaluation If one single active failure prevents a venting operation through one flow path, the redundant path is available for venting. The two isolation valves in each flow path provide a similar method of isolating the venting system. With two valves in series, the failure of any one valve or power supply will not inadvertently open a vent path. Thus, the combination of safety grade train assignments and valve failure modes will not prevent vessel head venting nor venting isolation with any single active failure. The RVHVS has two normally deenergized valves in series in each flow path. This arrangement eliminates the possibility of an opened flow path due to the spurious movement of one valve. As such, power lockout to any valve is not considered necessary. A break of the RVHVS line would result in a small LOCA of not greater than one inch diameter. Such a break is similar to those analyzed in WCAP-9600 (1979). Since a break in the head vent line would behave similarly to the hot leg break case presented in WCAP-9600, the results presented therein are applicable to a RVHVS line break. This postulated vent line break, therefore, results in no calculated core uncovery. 5.4.15.4 Inspection and Testing Requirements Inservice inspection is conducted in accordance with Sections 5.2.4 and 6.6. 5.4.15.5 Instrumentation Requirements The system is operated from the control room and the auxiliary shutdown panel. The isolation valves have stem position switches. The position indication from each valve is monitored in the control room by status lights. 5.4.16 REFERENCES FOR SECTION 5.4 5.4-1 WCAP-8163, 1973, Reactor Coolant Pump Integrity in LOCA, Westinghouse. 5.4-2 WCAP-8768, Revision 2, 1978, Safety Related Research and Development for Westinghouse Pressurized Water Reactor, Program Summaries, Winter 1977-Summer 1978, Westinghouse. 5.4-3 WCAP-9600, 1979. Report on Small Break Accidents for Westinghouse NSSS System, (Section 3.2). 5.4-4 WCAP-7832, Evaluation of Steam Generator Tube, Tube Sheet and Divider Plate Under Combined LOCA plus SSE conditions, December 1973, Westinghouse. 5.4-5 WOG-87-102, 5/12/87, Mode 4 LOCA Concern Interim Guidance. 5.4-55 Rev. 30

MPS3 UFSAR 5.4-6 OG-90-30, 6/1/90, Shutdown LOCA Analysis Concerns That Relate to the Interim Guidance. 5.4-7 WOG-90-48, 3/6/90, RHR System Operability During Mode 4 LOCA. 5.4-56 Rev. 30

MPS3 UFSAR TABLE 5.4-1 REACTOR COOLANT PUMP DESIGN PARAMETERS Unit design pressure (psig) 2,485 Unit design temperature (°F) 650 (a) Unit overall height (ft) 26.3 Seal water injection (gpm) 8 Seal water return (gpm) 2.5 Component cooling water flow (gpm) (b) 216 Maximum continuous component cooling water 105 inlet temperature (°F) Chilled water flow (gpm) (c) 220 Maximum chilled water inlet temperature (°F) 45 Total weight, dry (lb) 187,852 Pump 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) Motor 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 5.4-57 Rev. 30

MPS3 UFSAR TABLE 5.4-1 REACTOR COOLANT PUMP DESIGN PARAMETERS Current (amp): Starting 3,000 @ 6,600 V Normal input, hot reactor coolant 506 +/- 10 Normal input, cold reactor coolant 664 +/- 13 Pump moment of inertia, max (lb/ft2): Flywheel 70,000 Motor 22,500 Shaft 520 Impeller 1,980 NOTES:

a. 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 650°F.

b. 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.

c. Chilled water is supplied to the air coolers at a flow rate of 110 gpm to each air cooler.

d. Composed of reactor coolant in the casing and of seal injection and cooling water in the thermal barrier.

5.4-58 Rev. 30

MPS3 UFSAR TABLE 5.4-2 REACTOR COOLANT PUMP NON-DESTRUCTIVE EXAMINATION PROGRAM RT UT PT MT Castings yes yes Forgings Main shaft yes yes Main studs yes yes Plate Flywheel yes

• yes
• yes
• Weldments Circumferential yes yes Instrument connections yes NOTES:

RT - Radiographic UT - Ultrasonic PT - Dye penetrant MT - 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.

5.4-59 Rev. 30

MPS3 UFSAR TABLE 5.4-3 STEAM GENERATOR DESIGN DATA Design pressure, reactor coolant side (psig) 2,485 Design pressure, steam side (psig) 1,185 Design pressure, primary to secondary (psi) 1,600 Design temperature, reactor coolant side (°F) 650 Design temperature, steam side (°F) 600 Design temperature, primary to secondary (°F) 650 Total heat transfer surface area (ft2) 55,000 Maximum moisture carryover (weight percent) 0.25 Overall height (ft-in) 67-8 Number of U-tubes 5,626 U-tube nominal diameter (in.) 0.688 Tube wall nominal thickness (in.) 0.040 Number of manways 4 Inside diameter of manways (in.) 16 Number of handholes 6 Number of inspection ports 2 Design fouling factor (ft2-hr-°F/Btu) 0.00006 Steam flow (lb/hr) 4.075 x 106 5.4-60 Rev. 30

MPS3 UFSAR TABLE 5.4-4 STEAM GENERATOR NONDESTRUCTIVE EXAMINATION PROGRAM RT UT PT MT ET Tube Sheet Forging yes yes Cladding yes

• yes Channel Head (if fabricated) Fabrication yes** yes *** yes Cladding yes Secondary Shell and Head Plates yes Tubes yes yes Nozzles (Forgings) yes yes Weldments Shell, longitudinal yes yes Shell, circumferential yes yes Cladding yes (channel head-tube sheet joint cladding restoration)

Primary nozzles to fab head yes yes Manways to fab head yes yes Steam and feedwater nozzle to shell yes yes Support brackets yes Tube to tube sheet yes Instrument connections (primary and secondary) yes Temporary attachments after removal yes After hydrostatic test (all major pressure boundary welds yes and complete cast channel head - where accessible) Nozzle safe ends (if weld deposit) yes yes 5.4-61 Rev. 30

MPS3 UFSAR NOTES: RT - Radiographic UT - Ultrasonic PT - Dye penetrant MT - Magnetic particle ET - Eddy current Flat surfaces only

• • Weld deposit
    • Base material only 5.4-62 Rev. 30

MPS3 UFSAR TABLE 5.4-5 REACTOR COOLANT PIPING DESIGN PARAMETERS Reactor inlet piping inside diameter (in) 27-1/2 Reactor inlet piping, nominal wall thickness (in) 2.32 Reactor outlet piping inside diameter (in) 29 Rector outlet piping, nominal wall thickness (in) 2.45 Coolant pump suction piping inside diameter (in) 31 Coolant pump suction piping, nominal wall thickness (in) 2.60 Pressurizer surge line piping, nominal pipe size (in) 14 Pressurizer surge line piping, nominal wall thickness (in) 1.406 Reactor Coolant Loop Piping Design/operating pressure (psig) 2485 / 2235 Design temperature (°F) 650 Pressurizer Surge Line Design pressure (psig) 2485 Design temperature (°F) 680 Pressurizer Safety Valve Inlet Line Design pressure (psig) 2485 Design temperature (°F) 680 Pressurizer (Power-Operated) Relief Valve Inlet Line Design pressure (psig) 2485 Design temperature (°F) 680 Reactor Head Vent Piping Design pressure (psig) 2485 Design temperature (°F) 650 Nominal pipe size (in) 1 Wall thickness (schedule) 160 5.4-63 Rev. 30

MPS3 UFSAR TABLE 5.4-5 REACTOR COOLANT PIPING DESIGN PARAMETERS Pressurizer Relief Tank Inlet Line Design pressure (psig) 600 Design temperature (°F) 600 Loop 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 5.4-64 Rev. 30

MPS3 UFSAR TABLE 5.4-6 REACTOR COOLANT PIPING QUALITY ASSURANCE PROGRAM RT* UT* PT

• Fittings and Pipe (Castings) yes yes Fittings and Pipe (Forgings) yes yes Weldments

1. Circumferential yes yes

2. Nozzle to runpipe yes yes (Except no RT for nozzles less than 6 inches)

3. Instrument connections yes Castings yes yes (after finishing)

Forgings yes yes (after finishing) NOTES:

• RT - Radiographic UT - Ultrasonic PT - Dye Penetrant 5.4-65 Rev. 30

MPS3 UFSAR TABLE 5.4-7 DESIGN BASES FOR RESIDUAL HEAT REMOVAL SYSTEM OPERATION SGCS NORMAL Reactor coolant system initial pressure (psig) 375 375 Reactor coolant system initial temperature (°F) 350 350 Maximum component cooling water supply temperature (°F) 113 110 Maximum component cooling water outlet temperature °F 145 145 Cooldown time, after reactor shutdown (hr) 72 36 Reactor coolant system temperature at end of cooldown (°F) 200 200 5.4-66 Rev. 30

MPS3 UFSAR TABLE 5.4-8 RESIDUAL HEAT REMOVAL SYSTEM COMPONENT DATA Residual Heat Removal Pump Number 2 Design pressure (psig) 600 Design temperature (°F) 400 Design flow (gpm) 4,000 Design head (ft) 350 NPSH required at 3,800 gpm (ft) 18 NPSH required at runout flow 5,500 gpm (ft) 25 Power (hp) 400 Residual Heat Exchanger Number 2 Design heat removal capacity (Btu/hr) 35.27 x 106 Estimated UA (Btu/hr °F) 3.5 x 106 Tube Side Shell Side Design pressure (psig) 600 175 Design temperature (°F) 400 200 Design flow (lb/hr) 1.98 x 106 3.3 x 106 Inlet temperature (°F) 120 92.2 Outlet temperature (°F) 102.2 102.9 Material Austenitic Stainless Carbon Steel Steel Fluid Reactor Coolant Component Cooling Water 5.4-67 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND 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 fluid a. Failure blocks reactor coolant a. Valve open/close position 1. Valve is electrically gate valve on demand flow from the RCS to the flow from hot leg of RC loop 1 indication at CB; RC loop 1 interlocked with 8701A (8701B suction of RHR pump 1 (loop 4) through train A (loop 4) hot leg pressure RWST to RHR analogous) (pump 2) (train B) of RHRS. Failure indication at CB: RHR train suction line reduces redundancy of RHR A (train B) discharge isolation valve coolant trains provided. No flow indication and low flow 8812A (8812B),

effect on safety for system alarm at CB; and RHR pump with RHR to operation. Plant cooldown 1 (pump 2) discharge charging pump requirements will be met by pressure indication and low suction line reactor coolant flow from hot flow alarm at CB; and RHR isolation valve leg of RC loop 4 (loop 1) pump 1 (pump 2) discharge 8804A (8804B) and flowing through train B pressure indication at CB. with a prevent-(train A) of RHRS, however, open pressure time required to reduce RCS interlock PT405/ temperature will be extended. PT-405A, PT403/ 403A of RC loop 1 (loop 4) hot leg. MPS3 UFSAR The valve cannot be opened remotely from the CB if one of the indication isolation valves is open or if RC loop pressure exceeds 412.5 psia. The valve 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, gate valve 1 except for pressure 8702A (8702B interlock PT405/

analogous) 405A (PT-403/403A) control. 5.4-68 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS 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 reactor Failure results in loss of reactor Open pump switchgear circuit The RHRS shares (RHR pump 2 deliver coolant through RHR heat coolant flow from hot leg of breaker indication at CB; components with analogous) working exchange 1 (heat exchanger RC loop 1 (loop 4) through circuit breaker close position the ECCS. Pumps fluid 2) to reduce RCS train A (train B) of RHRS. monitor light for group are tested as part of temperature during Failure reduces redundancy of monitoring of components at the ECCS testing cooldown operation RHR coolant trains provided. CB; common breaker trip program (see No effect on safety for system alarm at CB; RC loop 1 Section 6.3.4).

operation. Plant cooldown (loop 4) hot leg pressure requirements will be met by indication at CB; RHR train reactor coolant flow from hot A (train B) discharge leg of RC loop 4 (loop 1) flow indication and low flow flowing through train B alarm CB; and pump (train A) of RHRS, however, discharge pressure indication time required to reduce RCS at CB. temperature will be extended.

4. Motor-operated a. Fails closed Provides regulation of fluid a. Failure blocks miniflow line a. Valve open/close position 1. Valve is globe valve flow through miniflow to suction of RHR pump 1 indication at CB; and RHRS automatically MPS3 UFSAR FCV-610 bypass line to suction of (pump 2) during cooldown train A (train B) controlled to open (FCV-611 RHR pump 1 (pump 2) to operation. No effect on safety discharge flow indication at when pump analogous) protect against overheating for system operation. Plant CB. discharge is less of the pump and loss of cooldown requirements will be than 772 gpm and discharge flow from the met by reactor coolant flow close when the pump. from hot leg of RC loop 4 discharge exceeds (loop 1) flowing through train 1542 gpm. These B (train A) of RHRS, flow are nominal however, time required to valves.

reduce RCS temperature will be extended. 5.4-69 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS 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 of Same as item 4.a.

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 MPS3 UFSAR (FCV-619) to compensate for the open miniflow line and controlling cooldown with reduanant RHRS train B (train A). 5.4-70 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS 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 flow a. Failure prevents coolant a. RHR pump 1 (pump 2) 1. Valve is designed to operated on demand bypassed around RHR heat discharged from RHR pump 1 discharge flow temperature fail open and is butterfly valve for flow exchanger 1 (heat (pump 2) from bypassing RHR and RHRS train A (train electrically wired FCV-618 increase exchanger 2) during heat exchanger 1 (heat B) discharge to RCS cold so that electrical (FCV-619 (Auto cooldown operation exchanger 2) resulting in leg flow temperature solenoid of the air analogous) mode CB mixed mean temperature of recording at CB; and RHRS diaphragm operator switch coolant flow to RCS being low. train A (train B) is energized to open selection) RHRS train A (train B) is discharge to RCS cold leg the valve. Valve is degraded for the regulation of flow indication at CB (TR normally open to controlling temperature of 612). align RHRS for coolant. No effect on safety for ECCS operation system operation. Cooldown of during plant power RCS within established operation and load specification rate may be follow.

accomplished through operator 2. Valve is designed action of throttling flow for normal plant control valve HCV-606 cooldown MPS3 UFSAR (HCV-607) and controlling operation. It is cooldown with redundant required for safety RHRS train B (train A). grade cold shutdown operations, if only one train of RHS is available and instrument air is lost. 5.4-71 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS 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 1 for flow (pump 2) to bypass RHR heat reduction exchanger 1 (heat exchanger 2) (Auto resulting in mixed mean mode CB temperature of coolant flow to switch RCS being high. RHRS train selection) 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 MPS3 UFSAR (HCV-607) and controlling cooldown with redundant RHRS train B (train A), however, cooldown time will be extended. 5.4-72 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS 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 flow a. Failure prevents control of a. Same methods of detection 1. Valve is designed to operated on demand through RHR heat coolant discharge flow from as those stated for item 5.a. fail open. Valve butterfly valve for flow exchanger 1 (heat RHR heat exchanger 1 (heat In addition, monitor light is normally open HVC-606 reduction exchanger 2) during exchanger 2) resulting in loss and alarm (valve closed) for to align RHRS for (HCV-607 cooldown operation of mixed mean temperature group monitoring of ECCS operation analogous) coolant flow adjustment to components at CB. during plant power RCS. No effect on safety for operation and load system operation. Cooldown of follow.

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 MPS3 UFSAR increase

7. Motor-operated Fails to close Provides isolation of fluid No effect on safety for system Valve open/closed position Valve is normally gate valve on demand from the RWST to suction operation. Plant cooldown indication at CB and valve open to align 8812A (8812B) of RHR pump 1 (pump 2) requirements will be met by (closed) monitor light and RHRS for ECCS analogous) during cooldown operation reactor coolant flow from hot alarm at CB. operating during leg loop 4 (loop 1) flowing plant power through train B (train A) operation and load of RHRS, however, time follow. Valve must required to reduce RCS be closed during temperature will be extended. plant cooldown to satisfy electrical interlock to permit valves 8701A and 8702A (8701B and 8702B) to be opened.

5.4-73 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS 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 redundancy Same as item 7.

gate valve on demand between the two RHR for isolating RHR trains during 8716A (8716B trains during cooldown cooldown. Negligible effect on analogous) operation 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 of Charging pump discharge 1. The charging charging pump 1 deliver borated water from the BAT providing water to the RCS at header pressure and flow pumps provide (pump 3 working or RWST to the RCS high RCS pressures. Fluid flow indication at CB. Open/close boration and analogous) fluid from charging pump 1 (pump pump switchgear circuit makeup flow to the

3) will be lost. Minimum flow breaker indication on CB. RCS during safety requirements for boration and Circuit breaker close grade cold makeup will be met by position monitor light. For shutdown charging pump 3 (pump 1). group monitoring of operations. Note (4) component at CB. Common 2. Analysis of breaker trip alarm at CB. charging pump 2 MPS3 UFSAR being on line is analogous to that presented for charging pumps 1 and 3.

10. Motor-operated Fails to close Provides isolation of fluid Failure reduces redundancy of Same as item 7. The charging gate valve on demand discharge from the VCT to providing VCT discharging pumps' suction is LCV-112B the suction of charging isolation. Negligible effect on isolated from the (LCV-112C pumps safety for system operation. VCT and aligned to analogous) Alternate isolation valve the BAT (for LCV-112C (LCV-112B) boration) or RWST provides backup tank (for makeup) discharge isolation. during safety grade cold shutdown operations.

5.4-74 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS 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 fluid Failure reduces redundancy of Valve open/close position The charging gate valve on demand discharge from the RWST providing fluid from RWST to indication at CB (open) pumps' suction is LCV-112D to the suction of charging suction of charging pumps. monitor light and alarm at aligned to the (LCV-112E pumps Negligible effect on safety for CB. RWST for makeup analogous) system operation. Alternate to the RCS during isolation valve LCV-112E ECCS and safety (LCV-112D) opens to provide grade cold backup flow path to suction of shutdown charging pumps. operations.

12. Motor-operated Fails to close Provides isolation of fluid Failure reduces redundancy of Same as item 7 except no Normal charging gate valve 8105 on demand flow from the charging providing isolation of charging valve (closed) monitor alarm line is isolated (8106 analogous) pump discharge header to pump discharge to normal for group monitoring. during safety grade the CVCS normal charging charging line of CVCS. cold shutdown line to the RCS Negligible effect on safety for operations.

system operation. Alternate Boration and isolation valve 8105 (8106) makeup flow provides backup normal CVCS provided to RCS MPS3 UFSAR charging line isolation. through redundant ECCS headers to the RCS cold legs.

13. Motor-operated Fails to close Provides isolation barrier to MELB isolation may be Same as item 7. Note (4) gate valve on demand isolate charging pump provided by closing isolation 8468A (8468B suction flow paths in the valve 8468B (8468A).

analogous) event of a MELB in charging pump suction header

14. Motor-operated Fails to close Provides isolation barrier to HELB isolation may be Same as item 7. Note (5) gate valve on demand isolate charging pump provided by closing isolation 8438A (8438B discharge flow paths in the valve 8438B (8438A).

analogous) event of a HELB in charging pump discharge header 5.4-75 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

15. Solenoid Fails to open Provides control of fluid Failure reduces redundancy of Valve position indication at Same as item 12.

operated globe on demand flow from charging pump 1 controlling boration and CB; and charging pump 1 valve (pump 3) to RCS during makeup flow to the RCS. (pump 3) discharge header HCV-190A plant boration and makeup Negligible effect on safety for flow indication at CB. (HCV-190B) system operation. Alternate control valve HCV-190B (HCV-190A) controls flow from charging pump 3 (pump 1). 15a. Motor-operated Fails to open Provides isolation of fluid Same as Item 15 Same as Item 15 Same as Item 12 Globe Valve MV on demand flow from pump/(pumps) to 8116 RCS

16. Solenoid a. Fails to open Provides isolation of fluid a. Failure reduces redundancy of a. Valve open/close position 1. The RC head operated globe on demand flow from the RV head to providing flow from the RV indication at CB; and RV letdown path to the valve 8095A the CHS or PRT head to the CHS or PRT. head letdown high CHS or PRT (8095B Negligible effect on safety for temperature indication and provides fluid flow analogous) system operation. RV head alarm at CB. out of the RCS to MPS3 UFSAR letdown flow provided by accommodate parallel head letdown path boration flow into through alternate isolation the RCS.

valve 8095B (8095A).

b. Fails to close b. Failure reduces redundancy of b. Same as item 16.a.

on demand 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). 5.4-76 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

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 to (8096B the 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 except that Same as item 16.a except that Valve position indication at Same as item 16.1 operated globe on demand flow is from the RV head to flow is from the RV head to the CB; RV letdown temperature except that the RV valve the PRT PRT and the alternative indication at CB. Letdown Path is to HCV-442A parallel isolation valve the PRT.

(HCV-442B HCV-442B (HCV-442A). analogous)

19. Solenoid a. Fails to open Provides isolation of fluid a. Failure reduces redundance of a. Valve open/close position 1. Pressurizer vent operated power on demand flow from pressurizer to providing flow from indication at CB; pressurizer path to the PRT operated relief PRT pressurizer to PRT. Negligible power operated relief valve provides fluid flow MPS3 UFSAR valve PCV-455A effect on safety for system outlet temperature indication out of the RCS to (PCV-456 operation. Pressurizer vent at CB. permit RCS analogous) flow provided by a parallel depressurization to pressurizer vent path through RHRS initiation alternate isolation valves conditions.

PCV-456A or PCV-455A.

b. Fails to close b. Failure reduces redundancy of b. Same as item 19.a.

on demand 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). 5.4-77 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

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 isolation 8000A (8000B provided by alternate series analogous) isolation valve PCV-455A (PCV-456).

21. Motor-operated Fails to close Provides isolation of fluid Failure prevents isolation of Valve open/closed position Accumulators are gate valve on demand flow from accumulator 1 accumulator 1 (accumulator 2, indication at CB, valve isolated or vented 8808A (8808B, (accumulator 2, accumulator 3 and accumulator (closed) monitor light and during plant 8808C, and accumulator 3, and 4) from the RCS. Negligible alarm at CB and cooldown to not 8808D accumulator 4) to the RCS effect on safety for system accumulator pressure effect RCS analogous) operation. Accumulator 1 indication and low alarm at depressurization to (accumulator 2, accumulator 3 CB. RHRS initiation and accumulator 4) is conditions.

depressurized by opening vent isolation valves 8875A (8875B or 8875C or 8875D) and HCV-943A, or vent isolation MPS3 UFSAR valves 8875E (8875F, 8875G or 8875H) and HCV-943B.

22. Solenoid Fails to open Provides venting of Failure reduces redundancy for Valve open/closed position Same as item 21.

operated globe on demand nitrogen gas from venting accumulator 1 indication at CB and valve 8875A accumulator 1 (accumulator (accumulator 2, accumulator 3 accumulator pressure (8875B, 8875C 2, accumulator 3 and and accumulator 4) to indication and low alarm at and 8875D accumulator 4) to containment. No effect on CB. analogous) containment safety for system operation. 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). 5.4-78 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

23. Solenoid Fails to open Same as item 22 Failure reduces redundancy for Same as item 22. Same as item 22.

operated globe on demand venting accumulator 1 valve 8875E (accumulator 2, accumulator 3 (8875F, 8875G 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).

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 MPS3 UFSAR 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 of Pump motor start relay The boric acid transfer pump working concentrated boric acid providing concentrated boric position indication (open) at transfer pumps pump 1 (pump 2 fluid from BAT to charging acid to charging pump suction. CB and local pump provide boration analogous) pump suction Fluid flow from boric acid discharge pressure indication flow to the charging transfer pump 1 (pump 2) will PI-113 (PI-114). pumps suction.

be lost. Minimum flow requirements for boration will be met by boric acid transfer pump 2 (pump 1). 5.4-79 Rev. 30

MPS3 UFSAR TABLE 5.4-9 RESIDUAL HEAT REMOVAL SYSTEM - COLD SHUTDOWN OPERATIONS-FAILURE MODES AND EFFECTS ANALYSIS Component (1) Failure Mode Function (2) Effect on System Operation (3) Failure Detection Methods (3) Remarks

26. Motor-operated Fails to open Provides isolation of fluid Failure reduces redundancy of Valve open/close position The charging globe valve 8104 on demand flow from either boric acid providing concentrated boric indication at CB; and pumps suction is transfer pump to charging acid to charging pump suction. boration flow indication aligned to the pump suction Negligible effect on safety for (FI-183A) at CB. gravity drain lines system operation. (8507A/B) for Concentrated boric acid boration of the RCS provided to charging pump during safety grade suction through alternate cold shutdown isolation valve 8507A/B. operations.

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. MPS3 UFSAR Components 16 through 20 are components of the RCS that perform a safety grade cold shutdown function. (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 5.4-80 Rev. 30

MPS3 UFSAR 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. MPS3 UFSAR 5.4-81 Rev. 30

MPS3 UFSAR TABLE 5.4-10 PRESSURIZER DESIGN DATA Design pressure (psig) 2485 Design temperature (°F) 680 Surge line nozzle diameter (inch) 14 Heatup rate of pressurizer using heaters only (°F/hr) 55 Internal volume (ft3) 1800 5.4-82 Rev. 30

MPS3 UFSAR TABLE 5.4-11 REACTOR COOLANT SYSTEM DESIGN PRESSURE SETTINGS psig Hydrostatic test pressure 3107 Design pressure 2485 Safety valves (begin to open) 2485 High pressure reactor trip 2370 Power operated relief valves 2335 (1) High pressure deviation alarm 2310 (2) Pressure spray valves (full open) 2310 (2) Pressure spray valve (begin to open) 2260 (2) Proportional heaters (begin to operate) 2250 (2) Operating pressure 2235 Proportional heater (full operation) 2220 (2) Backup heaters on 2210 (2) Low pressure deviation alarm 2210 (2) Low pressure reactor trip (typical, but variable) 1885 NOTE:

1. At 2335 psig, a pressure signal initiates actuation (opening) of these valves. Remote manual control is also provided.

2. Actual setpoints will vary depending on M/A station settings and controller response to plant conditions.

5.4-83 Rev. 30

MPS3 UFSAR TABLE 5.4-12 PRESSURIZER QUALITY ASSURANCE PROGRAM RT 1 UT 1 PT 1 MT 1 Heads: Plates yes Cladding yes Shell: Plates yes Cladding yes Heaters: Tubing 2 yes yes Centering of element yes Nozzle (forgings) yes yes 3 yes 3 Weldments: 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 NOTES:

1. RT - Radiographic UT - Ultrasonic PT - Dye penetrant MT - Magnetic particle

2. UT and ET

3. MT or PT 5.4-84 Rev. 30

MPS3 UFSAR TABLE 5.4-13 PRESSURE RELIEF TANK DESIGN DATA Design pressure (psig) 100 Rupture disc release pressure (psig) Nominal: 91 range: 86-100 Design temperature (°F) 340 Total rupture disc relief capacity at 100 psig (lb/hr) 1.6 x 106 5.4-85 Rev. 30

MPS3 UFSAR TABLE 5.4-14 RELIEF VALVE DISCHARGE TO THE PRESSURIZER RELIEF TANK Reactor Coolant System 3 Pressurizer safety valves Figure 5.1-1 2 Pressurizer power operated relief valves Figure 5.1-1 Residual Heat Removal System 2 Residual heat removal pump suction line from the Reactor Coolant System Figure 5.4-6 hot legs Chemical and Volume Control System 1 Seal water return line Figure 9.3-8 1 Letdown line Figure 9.3-8 5.4-86 Rev. 30

MPS3 UFSAR TABLE 5.4-15 REACTOR COOLANT SYSTEM DESIGN PARAMETERS Design/normal operating pressure (psig) 2485 / 2235 Preoperational plant hydrotest (psig) 3107 Design temperature (°F) 650 5.4-87 Rev. 30

MPS3 UFSAR TABLE 5.4-16 NON-DESTRUCTIVE EXAMINATION PROGRAM REACTOR COOLANT SYSTEM VALVES RT (1) UT (1) PT (1) Castings (larger than 4 inches) yes yes (2 inches to 4 inches) yes (2) yes Forgings yes (3) yes NOTES:

1. RT - Radiographic UT - Ultrasonic PT - Dye penetrant

2. Weld ends only

3. Forged stems UT only 5.4-88 Rev. 30

MPS3 UFSAR TABLE 5.4-17 PRESSURIZER VALVES DESIGN PARAMETERS Pressurizer 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 Backpressure Normal (psig) 3 to 5 Expected during discharge (psig) 500 Pressurizer 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 5.4-89 Rev. 30

MPS3 UFSAR TABLE 5.4-18 EQUIPMENT SUPPORTS, LOADING COMBINATIONS, AND DESIGN ALLOWABLE STRESSES Loading Equipment Loading Category Combinations Stress Limits Codes Steam Generator and Design, Normal & Upset Dead Weight App. XVII-2000 and ASME Boiler and Pressure Reactor Coolant Pump Paragraph NF-3230 Vessel Code, Section III, Supports Subsection NF 1974 Edition through 1974 Winter Addenda

                                             +Thermal
                                             +1/2 SSE Faulted                Dead Weight      App. F-1370
                                             +SSE
                                             +Pipe rupture Pressurizer Supports   Design, Normal & Upset Dead Weight      App. XVII-2000 and   ASME Boiler and Pressure Paragraph NF-3230    Vessel Code, Section III, Subsection NF 1974 Edition             MPS3 UFSAR
                                             +Thermal
                                             +1/2 SSE Faulted                Dead Weight      App. F-1370
                                             +SSE
                                             +Pipe rupture 5.4-90                                                     Rev. 30

MPS3 UFSAR TABLE 5.4-18 EQUIPMENT SUPPORTS, LOADING COMBINATIONS, AND DESIGN ALLOWABLE STRESSES Loading Equipment Loading Category Combinations Stress Limits Codes RPVSS Design, Normal & Upset Dead Weight App. XVII-2000 and ASME Boiler and Pressure (Neutron Shield Tank) Paragraph NF-3230 Vessel Code, Section III, for linear type supports Subsection NF 1974 Edition including 1974 Summer

                                              +Initial         Paragraph NF-3220 Pressurization   for plate and shell type Addenda supports
                                              +Thermal
                                              +1/2 SSE Faulted                Dead Weight      App. F-1323.1 for plate and shell type supports
                                              +SSE             App. F-1370 for linear                                          MPS3 UFSAR type supports
                                              +Pipe rupture
                                              +Initial and Asymmetric Pressurization 5.4-91                                                         Rev. 30

MPS3 UFSAR TABLE 5.4-19 REACTOR VESSEL HEAD VENT SYSTEM EQUIPMENT DESIGN PARAMETERS Valves Number of remote valves (6 solenoid, 1 motor operated) 7 Design pressure (psig) 2485 Design temperature (°F) 650 Maximum operating temperature (°F) 620 Piping Vent line, nominal diameter (in) 1 Design pressure (psig) 2485 Design temperature (°F) 650 Maximum operating temperature (°F) 620 5.4-92 Rev. 30

MPS3 UFSAR FIGURE 5.4-1 REACTOR COOLANT PUMP OIL COOLER UPPER MOTOR RADIAL BEARING FLYWHEEL THRUST BEARING MAIN LEAD CONDUIT BOX MOTOR SHAFT LOWER MOTOR RADIAL BEARING SPOOL PIECE CVCS SEAL RETURN (CBO) MIDDLE STAGE OUTLET PRESSURE (P3) LOWER STAGE OUTLET PRESSURE (P2) SEAL LEAKOFF

• COOLING WATER INLET No. 1 SEAL INJECTION WATER THERMAL BARRIER PUMP SHAFT PUMP RADIAL BEARING CASING DISCHARGE NOZZLE IMPELLER SUCTION NOZZLE MODEL 93A-1
• Seal leakoff for flowserve seals will now be located 45 degrees CCW from the second stage outlet pressure connections.

5.4-93 Rev. 30

MPS-3 FSAR FIGURE 5.4-2 REACTOR COOLANT PUMP ESTIMATED PERFORMANCE CHARACTERISTICS 600 500 TOTAL HEAD TOTAL HEAD - FEET 400 300 200 REQUIRED NET POSITIVE SUCTION HEAD 100 0 0 10 20 30 40 50 60 70 80 90 100 110 FLOW - THOUSANDS OF GPM Rev. 20.2

MPS-3 FSAR FIGURE 5.4-3 MODEL F STEAM GENERATOR

                                          " - - - - - - STEAM OUTLET W/FLOW
                         ~-:::::;J"""""---JL......L~_          RESTRICTOR SECONDARY STEAM SEPARATORS SECONDARY MANWAYS PRIMARY SEPARATORS FEEDWATER INTRODUCED THROUGH INVERTED FEEDWATER INLET                                                "J"TUBES FEEDWATER RING
                                                           -   ANTI-VIBRATION BARS U -TUBES BROACHED TUBE
                                                             ~ SUPPORT PLATES FLOW DISTRIBUTION
                                                          /    BAFF:...E
                                                       /'

FLOW BLOCKERS HANDHOLES BLOWDOWN PIPE

  & CONNECTION                                _---+-~--        TUBE SHEET DIVIDER PLATE   ---~"r-----il                        - - COOLANT CHAMBER PRIMARY COOLt-NT
                                                   ------- - PRIMARY MANWAYS NOZZLE Rev. 20.2

MPS-3 FSAR FIGURE 5.4-4 QUATRFOIL TUBE SUPPORT PLATES TUBE SUPPORT PLATE SECTION Rev. 20.2

FIGURE 5.4-5 5 (SHEETS 1-3) P&IDS LOW PRESSURE SAFETY INJECTION / 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. 5.4-97 Rev. 30

MPS-3 FSAR FIGURE 5.4-6 RESIDUAL HEAT REMOVAL SYSTEM PROCESS FLOW DIAGRAM (MODE A) 7 3 9 6 5 4 3 2 1 SIS CL RCS HLl 5 LOOP 1 2 1 14 10 8 6 11 4 SIS HL 7 18 13 10 21 20 17 16 15 14 13 12 SIS CL RCS HLl LOOP 4 12 9 8 15 19 11 11 May 1998 Rev. 20.2

MPS-3 FSAR NOTES TO FIGURE 5.4-6 Mode A Initiation of Residual Heat Removal System Operation This mode presents the process flow conditions for the initiation of RHS operation. This begins the second phase of plant cooldown, when the reactor coolant temperature and pressure have been reduced to 350°F and 375 psig by use of the steam generators, transferring heat to the secondary side. During Mode A operation, one RHS loop is aligned for RCS cooldown and the second loop remains aligned for safety injection (RWST to RHS connection is not shown in Figure 5.4-6). One residual heat removal subsystem takes suction from its respective RCS hot leg, discharging through the heat exchanger with the return flow routed to the RCS cold legs. During the initial phases of RHS operation, reactor coolant flow through the heat exchangers is manually limited to control the rate of heat removal. The total flow is automatically regulated by flow control valves in the heat exchanger bypass lines to maintain a constant total return flow. The heat removal rate is limited to both control the RCS cooldown rate to 100°F/hr, based on equipment stress considerations, and to limit component cooling water temperature to a maximum of 145°F. During this initial phase of RHS operation, one or two reactor coolant pumps are maintained in operation. This results in a slight RHS return flow imbalance between the four RCS cold legs due to their different operating pressures. In the data presented, reactor coolant pump Number 2 is assumed operating. Mode B Initiation of Second Residual Heat Removal Loop This mode presents the process flow conditions once the reactor coolant temperature has been reduced to < 260°F. The second RHS loop is aligned to take suction from its respective RCS hot leg, discharging through the heat exchanger with return flow routed to the RCS cold legs. Mode C End Conditions of Normal Cooldown 140°F This mode presents the process flow conditions for the completion of RHS operation, refer to Section 5.4.7.2.3.4 for normal cooldown time details. The flow distribution of this mode, maintains RCS core cooling by controlling reactor coolant flow through the heat exchangers with bypass flow adjustments. Reactor coolant pump operation has also been terminated at this time, with all RCS cold legs in equilibrium. Page 1 of 5 Rev. 21.3

MPS-3 FSAR NOTES TO FIGURE 5.4-6 MODE A INITIATION OF SINGLE TRAIN RESIDUAL HEAT REMOVAL SYSTEM OPERATION Flow Pressure Temperature Location 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 NOTES:

1. Miniflow continues until flow at location 3 is greater than 1542 gpm. The miniflow is then closed.

Page 2 of 5 Rev. 21.3

MPS-3 FSAR NOTES TO FIGURE 5.4-6

2. 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 Location 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 Page 3 of 5 Rev. 21.3

MPS-3 FSAR NOTES TO FIGURE 5.4-6 MODE C END CONDITIONS OF NORMAL COOLDOWN 140°F Flow Pressure Temperature Location 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 NOTES:

1. RCS is assumed depressurized with the water level drained to the centerline of reactor coolant piping.

2. Conservative design assumptions presume that the bypass line is isolated; during normal cooldown operations, the bypass line is typically open.

Page 4 of 5 Rev. 21.3

MPS-3 FSAR NOTES TO FIGURE 5.4-6 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 NOTES: O = Open C = Closed P = Partially open

• Valve disc partially closed by means of a permanent "Travel Limiter" on valve actuator.

Page 5 of 5 Rev. 21.3

MPS-3 FSAR FIGURE 5.4-7 PRESSURIZER RELIEF TANK DISCHARGE LINE CONNECTION SPRAY WATER INLET VENT CONNECTION SAFETY HEADS f-r-~~~==o t--------

                                                         ---{?-------~~

I

                                                   !      \.- INTERNAL SPRAY II II III                         II                      I II       I,'                                      'I I

I I I. II  : 1\ 'T--- t--------H------li-  : ,I ': i , __ J _ _ _ _ --------i+------~1.\- I: I, -~~1~=W VESSEL SUPPORT DRAIN CONNECTIO,," t vESSEL SUPPORT Rev. 20.2

MPS-3 FSAR FIGURE 5.4-8 PRESSURIZER __________ SPRAY NOZZLE RELIEF NOZZLE _ - - - - SAFETY NOZZLE _ --MANWAY

                                   ------------- UP PER H EA0 INSTRUMENTATION NOZZLE
                                    ~LIFTING TRUNNION

____ SHELL LOWER HEAD HEATER SUPPORT PLATE INSTRUMENTATION NOZZLE ELECTRICAL HEATER SUPPORT SKIRT NOZZLE Rev. 20.2

MPS-3 FSAR FIGURE 5.4-9 RPV SUPPORT SYSTEM NOZZLE SUPPORT(TYP) TANGENTIAL MOMENT VERTICAL MOMENT SHEAR RADIAL MOMENT CENTER LINE OF NOZZLE EIGHT PLACES SECTION A-A

                                                                ~VERTICAL LOAD                         AT
                                                           ./                   R. P V. SUPPORT REACTOR PRESSURE VESSEL EL 24'-6"                                                                 ~SEE          FIGURE
                                                                                 ~             5.4.14-2

.t,'.

                                                           -¥-....-..- - -~ OF NOZZLES EL 17'-6"
                                                  ...              ==1. --HORZ.
                                                     ---+-~-.-.....,

A p s. w. FORCE AT OVERTURNING MOMENT PRIMARY SHIELD WALL AT PS.W, NEUTRON SHIELD TANK BASE TORQUE BASE OVERTURNING MOMENT BRIDGING BAR BASE SHEAR EL 27'-3"

     ,-----~--L_L...6:2=;:=;====F=~::t::;:;:;;=i=::::!!I::====::i!~----___r
      , .                                                                                           (TOP OF MAT)
      . .. f                                                                                 "

MAT

',=,. :

                                                                           , ,(

t"" ~ .._- 8ASE VERTICA L LOAD Rev. 20.2

GIB KEY VERTICLE RESTRAINT PAD LEVELING UNIT _--~--.:>...:--.......,.e..-_~:s...".....e LUB RITE PLATE -----~~.....----....::...,j-~ REACTOR VESSEL SUPPORT PAD _ _------J FIGURE 5 .4-10 LEVELING DEVICE (TYPICAL) RPV 3UPPORT SYSTEM MILLSTONE NUCLEAR POWER STATION UNIT 3 FINAL SAFETY ANALYSIS REPORT

MPS-3 FSAR FIGURE 5.4-11 VERTICAL SUPPORTS (TYPICAL) REACTOR COOLANT PUMPS AND STEAM GENERATOR STEAM GENERATOR R.C. PUMP COLD HOT LEG LEG S-8 S-5 S-6 S-7 Rev. 20.2

MPS-3 FSAR FIGURE 5.4-12 LATERAL SUPPORTS (TYPICAL) STEAM GENERATOR

                                                 .....- - SNUBBER 5-2 SNUBBER 5-1 COLUMN 5-5 CROSSOVER LEG COLUMN S-7 V<lII......- SNUBBER S-3 Rev. 20.2

MPS-3 FSAR FIGURE 5.4-13 LATERAL SUPPORT (TYPICAL) REACTOR COOLANT PUMP 1 1 1 SN U BB ER p -l 1 1 1 1 1 1 1 1 1 1 1 1 C O LU M N p -4 1 1 1 1 1 1 1 1 COLO LEG 1 1 1 1 1 1 1 1 COLUMN 1 p -5 1 SNUBBER p -3 1 1 1 1 1 1 1 1 COLUMN p -6 1 CROSSOVER LE.G 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 Rev. 20.2

r 2 ~I O k" DIA~REF EL 5j'-4 "REF! -l 1 ; -- \ I * {; - - - I ~ I

                                                   ------I I FLOOR OPENING I II 91-OT DIA. REF----                                          I
                                                         ~

I 1-4"REF. EL 51 EL 25'-7 ~ "PRESSURIZER SKIRT A RING GIRDER INTERFACE LATERAL SUPPORT (SEE SHEET 2 OF 2 FOR DETAI LS)

                                     ,             FIGURE    5.4 - 14 (SHEET 1 OF 2)

FRONT V I EW PRESSURIZER SUPPORT VERTICAL SUPPORTS MILLSTONE NUCLEAR POWER PLANT UNIT 3 FINAL SAF ETY ANALYS IS REPORT

41 '. a" (f. CONTAIN ME NT TOP VIEW FIGURE 5.4 - 15 (SHEET 1 OF 2) PRESSURIZER SAFETY VALVE SUPPORT SYSTEM MILLSTONE NUCLEAR POWER STATION UNIT 3 FINAL SAFETY ANALYSIS REPORT}}