ML18053A727

Duke Energy Wsl III Units 1 & 2 COL (Updated Final Safety Analysis Report) Rev.1 - UFSAR Chapter 05 - Reactor Coolant System and Connected Systems

ML18053A727
Person / Time
Site:	Lee
Issue date:	12/19/2017
From:	Donahue J Duke Energy Carolinas
To:	Office of New Reactors
Hughes B
References
DUKE, DUKE.SUBMISSION.15, LEE.NP, LEE.NP.1
Download: ML18053A727 (197)

Text

UFSAR Table of Contents 1 Introduction and General Description of the Plant 2 Site Characteristics 3 Design of Structures, Components, Equipment and Systems 4 Reactor 5 Reactor Coolant System and Connected Systems 6 Engineered Safety Features 7 Instrumentation and Controls 8 Electric Power 9 Auxiliary Systems 10 Steam and Power Conversion 11 Radioactive Waste Management 12 Radiation Protection 13 Conduct of Operation 14 Initial Test Program 15 Accident Analyses 16 Technical Specifications 17 Quality Assurance 18 Human Factors Engineering 19 Probabilistic Risk Assessment UFSAR Formatting Legend Description Original Westinghouse AP1000 DCD Revision 19 content Departures from AP1000 DCD Revision 19 content Standard FSAR content Site-specific FSAR content Linked cross-references (chapters, appendices, sections, subsections, tables, figures, and references)

5.1 Summary Description .................................................................................... 5.1-1 5.1.1 Design Bases ............................................................................... 5.1-1 5.1.2 Design Description ....................................................................... 5.1-2 5.1.3 System Components .................................................................... 5.1-3 5.1.3.1 Reactor Vessel .......................................................... 5.1-3 5.1.3.2 AP1000 Steam Generator ......................................... 5.1-4 5.1.3.3 Reactor Coolant Pumps ............................................. 5.1-4 5.1.3.4 Primary Coolant Piping .............................................. 5.1-5 5.1.3.5 Pressurizer ................................................................. 5.1-5 5.1.3.6 Pressurizer Safety Valves .......................................... 5.1-5 5.1.3.7 Reactor Coolant System Automatic Depressurization Valves ........................................................................ 5.1-6 5.1.4 System Performance Characteristics ........................................... 5.1-6 5.1.4.1 Best-Estimate Flow .................................................... 5.1-6 5.1.4.2 Minimum Measured Flow ........................................... 5.1-6 5.1.4.3 Thermal Design Flow ................................................. 5.1-7 5.1.4.4 Mechanical Design Flow ............................................ 5.1-7 5.1.5 Combined License Information ..................................................... 5.1-7 5.2 Integrity of Reactor Coolant Pressure Boundary ........................................... 5.2-1 5.2.1 Compliance with Codes and Code Cases .................................... 5.2-1 5.2.1.1 Compliance with 10 CFR 50.55a ............................... 5.2-1 5.2.1.2 Applicable Code Cases ............................................. 5.2-3 5.2.1.3 Alternate Classification .............................................. 5.2-3 5.2.2 Overpressure Protection ............................................................... 5.2-4 5.2.2.1 Design Bases ............................................................. 5.2-4 5.2.2.2 Design Evaluation ...................................................... 5.2-6 5.2.2.3 Piping and Instrumentation Diagrams ........................ 5.2-6 5.2.2.4 Equipment and Component Description .................... 5.2-6 5.2.2.5 Mounting of Pressure Relief Devices ......................... 5.2-7 5.2.2.6 Applicable Codes and Classification .......................... 5.2-7 5.2.2.7 Material Specifications ............................................... 5.2-7 5.2.2.8 Process Instrumentation ............................................ 5.2-7 5.2.2.9 System Reliability ...................................................... 5.2-7 5.2.2.10 Testing and Inspection ............................................... 5.2-8 5.2.3 Reactor Coolant Pressure Boundary Materials ............................ 5.2-8 5.2.3.1 Materials Specifications ............................................. 5.2-8 5.2.3.2 Compatibility with Reactor Coolant ............................ 5.2-9 5.2.3.3 Fabrication and Processing of Ferritic Materials ...... 5.2-11 5.2.3.4 Fabrication and Processing of Austenitic Stainless Steel ......................................................................... 5.2-12 5.2.3.5 Threaded Fastener Lubricants ................................. 5.2-16 5.2.4 Inservice Inspection and Testing of Class 1 Components .......... 5.2-17 5.2.4.1 System Boundary Subject to Inspection .................. 5.2-17 5.2.4.2 Arrangement and Inspectability ............................... 5.2-19 5.2.4.3 Examination Techniques and Procedures ............... 5.2-20 5.2.4.4 Inspection Intervals .................................................. 5.2-22 5.2.4.5 Examination Categories and Requirements ............ 5.2-22 5-i Revision 1

5.2.4.7 System Leakage and Hydrostatic Pressure Tests.... 5.2-22 5.2.4.8 Relief Requests ....................................................... 5.2-22 5.2.4.9 Preservice Inspection of Class 1 Components ........ 5.2-23 5.2.4.10 Program Implementation ......................................... 5.2-23 5.2.5 Detection of Leakage Through Reactor Coolant Pressure Boundary .................................................................................... 5.2-23 5.2.5.1 Collection and Monitoring of Identified Leakage ...... 5.2-23 5.2.5.2 Intersystem Leakage Detection ............................... 5.2-24 5.2.5.3 Collection and Monitoring of Unidentified Leakage .................................................................... 5.2-26 5.2.5.4 Safety Evaluation ..................................................... 5.2-30 5.2.5.5 Tests and Inspections .............................................. 5.2-30 5.2.5.6 Instrumentation Applications .................................... 5.2-30 5.2.5.7 Technical Specification ............................................ 5.2-31 5.2.6 Combined License Information Items ......................................... 5.2-31 5.2.6.1 ASME Code and Addenda ....................................... 5.2-31 5.2.6.2 Plant-Specific Inspection Program ........................... 5.2-31 5.2.6.3 Response to Unidentified Reactor Coolant System Leakage Inside Containment ................................... 5.2-32 5.2.7 References ................................................................................. 5.2-32 5.3 Reactor Vessel .............................................................................................. 5.3-1 5.3.1 Reactor Vessel Design ................................................................. 5.3-1 5.3.1.1 Safety Design Bases ................................................. 5.3-1 5.3.1.2 Safety Description ...................................................... 5.3-1 5.3.1.3 System Safety Evaluation .......................................... 5.3-3 5.3.1.4 Inservice Inspection/Inservice Testing ....................... 5.3-3 5.3.2 Reactor Vessel Materials .............................................................. 5.3-3 5.3.2.1 Material Specifications ............................................... 5.3-3 5.3.2.2 Special Processes Used for Manufacturing and Fabrication ................................................................. 5.3-3 5.3.2.3 Special Methods for Nondestructive Examination ..... 5.3-4 5.3.2.4 Special Controls for Ferritic and Austenitic Stainless Steels ......................................................................... 5.3-5 5.3.2.5 Fracture Toughness ................................................... 5.3-5 5.3.2.6 Material Surveillance ................................................. 5.3-5 5.3.2.7 Reactor Vessel Fasteners ....................................... 5.3-13 5.3.3 Pressure-Temperature Limits ..................................................... 5.3-13 5.3.3.1 Limit Curves ............................................................. 5.3-13 5.3.3.2 Operating Procedures .............................................. 5.3-14 5.3.4 Reactor Vessel Integrity ............................................................. 5.3-14 5.3.4.1 Design ...................................................................... 5.3-14 5.3.4.2 Materials of Construction ......................................... 5.3-16 5.3.4.3 Fabrication Methods ................................................ 5.3-16 5.3.4.4 Inspection Requirements ......................................... 5.3-16 5.3.4.5 Shipment and Installation ........................................ 5.3-16 5.3.4.6 Operating Conditions ............................................... 5.3-17 5.3.4.7 Inservice Surveillance .............................................. 5.3-17 5-ii Revision 1

5.3.5.1 Reactor Vessel Insulation Design Bases ................. 5.3-19 5.3.5.2 Description of Insulation .......................................... 5.3-20 5.3.5.3 Description of External Vessel Cooling Flooded Compartments ......................................................... 5.3-20 5.3.5.4 Determination of Forces on Insulation and Support System ..................................................................... 5.3-21 5.3.5.5 Design Evaluation .................................................... 5.3-21 5.3.6 Combined License Information ................................................... 5.3-22 5.3.6.1 Pressure-Temperature Limit Curves ........................ 5.3-22 5.3.6.2 Reactor Vessel Materials Surveillance Program ..... 5.3-22 5.3.6.3 Surveillance Capsule Lead Factor and Azimuthal Location Confirmation .............................................. 5.3-22 5.3.6.4 Reactor Vessel Materials Properties Verification ..... 5.3-22 5.3.6.5 Reactor Vessel Insulation ........................................ 5.3-22 5.3.6.6 Inservice Inspection of Reactor Vessel Head Weld Buildup ..................................................................... 5.3-22 5.3.7 References ................................................................................. 5.3-22 5.4 Component and Subsystem Design .............................................................. 5.4-1 5.4.1 Reactor Coolant Pump Assembly ................................................. 5.4-1 5.4.1.1 Design Bases ............................................................. 5.4-1 5.4.1.2 Pump Assembly Description ...................................... 5.4-1 5.4.1.3 Design Evaluation ...................................................... 5.4-3 5.4.1.4 Tests and Inspections ................................................ 5.4-8 5.4.2 Steam Generators ........................................................................ 5.4-8 5.4.2.1 Design Bases ............................................................. 5.4-8 5.4.2.2 Design Description ..................................................... 5.4-9 5.4.2.3 Design Evaluation .................................................... 5.4-11 5.4.2.4 Steam Generator Materials ...................................... 5.4-14 5.4.2.5 Steam Generator Inservice Inspection .................... 5.4-17 5.4.2.6 Quality Assurance .................................................... 5.4-18 5.4.3 Reactor Coolant System Piping .................................................. 5.4-19 5.4.3.1 Design Bases ........................................................... 5.4-19 5.4.3.2 Design Description ................................................... 5.4-20 5.4.3.3 Design Evaluation .................................................... 5.4-22 5.4.3.4 Material Corrosion/Erosion Evaluation .................... 5.4-22 5.4.3.5 Test and Inspections ................................................ 5.4-23 5.4.4 Main Steam Line Flow Restriction .............................................. 5.4-23 5.4.4.1 Design Bases ........................................................... 5.4-23 5.4.4.2 Design Description ................................................... 5.4-24 5.4.4.3 Design Evaluation .................................................... 5.4-24 5.4.4.4 Inspections ............................................................... 5.4-24 5.4.5 Pressurizer ................................................................................. 5.4-24 5.4.5.1 Design Bases ........................................................... 5.4-24 5.4.5.2 Design Description ................................................... 5.4-25 5.4.5.3 Design Evaluation .................................................... 5.4-28 5.4.5.4 Tests and Inspections .............................................. 5.4-30 5-iii Revision 1

5.4.6.1 Design Bases ........................................................... 5.4-31 5.4.6.2 Design Description ................................................... 5.4-31 5.4.6.3 Design Verification ................................................... 5.4-32 5.4.6.4 Inspection and Testing Requirements ..................... 5.4-32 5.4.7 Normal Residual Heat Removal System .................................... 5.4-32 5.4.7.1 Design Bases ........................................................... 5.4-33 5.4.7.2 System Description .................................................. 5.4-36 5.4.7.3 Component Description ........................................... 5.4-39 5.4.7.4 System Operation and Performance ....................... 5.4-41 5.4.7.5 Design Evaluation .................................................... 5.4-43 5.4.7.6 Inspection and Testing Requirements ..................... 5.4-44 5.4.7.7 Instrumentation Requirements ................................. 5.4-44 5.4.8 Valves ......................................................................................... 5.4-45 5.4.8.1 Design Bases ........................................................... 5.4-45 5.4.8.2 Design Description ................................................... 5.4-48 5.4.8.3 Design Evaluation .................................................... 5.4-49 5.4.8.4 Tests and Inspections .............................................. 5.4-49 5.4.8.5 Preoperational Testing ............................................. 5.4-50 5.4.9 Reactor Coolant System Pressure Relief Devices ..................... 5.4-52 5.4.9.1 Design Bases ........................................................... 5.4-53 5.4.9.2 Design Description ................................................... 5.4-53 5.4.9.3 Design Evaluation .................................................... 5.4-53 5.4.9.4 Tests and Inspections .............................................. 5.4-54 5.4.10 Component Supports .................................................................. 5.4-55 5.4.10.1 Design Bases ........................................................... 5.4-55 5.4.10.2 Design Description ................................................... 5.4-55 5.4.10.3 Design Evaluation .................................................... 5.4-57 5.4.10.4 Tests and Inspections .............................................. 5.4-57 5.4.11 Pressurizer Relief Discharge ...................................................... 5.4-57 5.4.11.1 Design Bases ........................................................... 5.4-58 5.4.11.2 System Description .................................................. 5.4-58 5.4.11.3 Safety Evaluation ..................................................... 5.4-58 5.4.11.4 Instrumentation Requirements ................................. 5.4-59 5.4.11.5 Inspection and Testing Requirements ..................... 5.4-59 5.4.12 Reactor Coolant System High Point Vents ................................. 5.4-59 5.4.12.1 Design Bases ........................................................... 5.4-60 5.4.12.2 System Description .................................................. 5.4-60 5.4.12.3 Safety Evaluation ..................................................... 5.4-61 5.4.12.4 Inspection and Testing Requirements ..................... 5.4-62 5.4.12.5 Instrumentation Requirements ................................. 5.4-62 5.4.13 Core Makeup Tank ..................................................................... 5.4-62 5.4.13.1 Design Bases ........................................................... 5.4-62 5.4.13.2 Design Description ................................................... 5.4-63 5.4.13.3 Design Evaluation .................................................... 5.4-63 5.4.13.4 Material Corrosion/Erosion Evaluation .................... 5.4-63 5.4.13.5 Test and Inspections ................................................ 5.4-64 5-iv Revision 1

5.4.14.1 Design Bases ........................................................... 5.4-64 5.4.14.2 Design Description ................................................... 5.4-65 5.4.14.3 Design Evaluation .................................................... 5.4-65 5.4.14.4 Material Corrosion/Erosion Evaluation .................... 5.4-66 5.4.14.5 Testing and Inspections ........................................... 5.4-66 5.4.15 Combined License Information ................................................... 5.4-66 5.4.16 References ................................................................................. 5.4-67 5-v Revision 1

2 Nominal System Design and Operating Parameters ..................................... 5.1-9 3 Thermal-Hydraulic Parameters ................................................................... 5.1-10 1 Reactor Coolant Pressure Boundary Materials Specifications .................... 5.2-33 2 Reactor Coolant Water Chemistry Specifications ....................................... 5.2-39 3 ASME Code Cases ..................................................................................... 5.2-40 1 Maximum Limits for Elements of the Reactor Vessel .................................. 5.3-24 2 Reactor Vessel Quality Assurance Program ............................................... 5.3-25 3 End-of-Life RTNDT and Upper Shelf Energy Projections ............................. 5.3-27 4 Reactor Vessel Material Surveillance Program ........................................... 5.3-28 5 Reactor Vessel Design Parameters ............................................................ 5.3-29 1 Reactor Coolant Pump Design Parameters ................................................ 5.4-68 2 Not Used. .................................................................................................... 5.4-69 3 Reactor Coolant Pump Quality Assurance Program ................................... 5.4-70 4 Steam Generator Design Requirements ..................................................... 5.4-71 5 Steam Generator Design Parameters (Nominal Values) ............................ 5.4-72 6 Steam Generator Quality Assurance Program ............................................ 5.4-73 7 Reactor Coolant System Piping Design ...................................................... 5.4-74 8 Reactor Coolant System Piping Quality Assurance Program ..................... 5.4-75 9 Pressurizer Design Data ............................................................................. 5.4-76 10 Pressurizer Heater Group Parameters ........................................................ 5.4-77 11 Reactor Coolant System Design Pressure Settings .................................... 5.4-78 12 Pressurizer Quality Assurance Program ..................................................... 5.4-79 13 Design Bases for Normal Residual Heat Removal System Operation ........ 5.4-80 14 Normal Residual Heat Removal System Component Data ......................... 5.4-81 15 Reactor Coolant System Valve Design Parameters .................................... 5.4-82 16 Reactor Coolant System Motor-operated Valves Design Opening and Closing Pressures ....................................................................................... 5.4-83 17 Pressurizer Safety Valves - Design Parameters ........................................ 5.4-84 18 Reactor Vessel Head Vent System Design Parameters ............................. 5.4-85 5-vi Revision 1

2 Reactor Coolant Loops - Isometric View .................................................... 5.1-12 3 Reactor Coolant System - Loop Layout ....................................................... 5.1-13 4 Reactor Coolant System - Elevation ........................................................... 5.1-14 5 Reactor Coolant System Piping and Instrumentation Diagram (Sheet 1 of 3) ................................................................................................ 5.1-15 5 Reactor Coolant System Piping and Instrumentation Diagram (Sheet 2 of 3) ................................................................................................ 5.1-16 5 Reactor Coolant System Piping and Instrumentation Diagram (Sheet 3 of 3) ............................................................................................... 5.1-17 1 Leak Detection Approach ............................................................................ 5.2-41 1 Reactor Vessel ............................................................................................ 5.3-30 2 AP1000 Reactor Coolant System Heatup Limitations (Heatup Rate Up to 50° and 100°F/hour) Representative for the First 54 EFPY (Without Margins for Instrumentation Errors) ............................................................. 5.3-31 3 AP1000 Reactor Coolant System Cooldown Limitations (Cooldown Rates up to 50° and 100°F/hour) Representative for the First 54 EFPY (Without Margins for Instrumentation Errors) ............................................................. 5.3-32 4 AP1000 Reactor Vessel Surveillance Capsules Locations ......................... 5.3-33 5 Reactor Vessel Key Dimensions Plan View ................................................ 5.3-34 6 Reactor Vessel Key Dimensions, Side View ............................................... 5.3-35 7 Schematic of Reactor Vessel Insulation ...................................................... 5.3-36 8 RCS Flooded Compartments During Ex-Vessel Cooling ............................ 5.3-37 9 Door Between RCDT Room and Reactor Cavity Compartment .................. 5.3-38 1 Reactor Coolant Pump ................................................................................ 5.4-86 2 Steam Generator ......................................................................................... 5.4-87 3 Support Plate Geometry (Trifoil Holes) ....................................................... 5.4-88 4 Surge Line ................................................................................................... 5.4-89 5 Pressurizer .................................................................................................. 5.4-90 6 Normal Residual Heat Removal System ..................................................... 5.4-91 7 Normal Residual Heat Removal System Piping and Instrument Diagram .... 5.4-92 8 Reactor Vessel Head Vent System ............................................................. 5.4-93 5-vii Revision 1

section describes the reactor coolant system (RCS) and includes a schematic flow diagram of reactor coolant system (Figure 5.1-1), an isometric view of the reactor coolant loops and major ponents (Figure 5.1-2), a sketch of the loop layout (Figure 5.1-3), and a sketch of the elevation of reactor coolant system (Figure 5.1-4). The piping and instrumentation diagram (Figure 5.1-5, ets 1, 2, and 3) shows additional details of the design of the reactor coolant system.

1 Design Bases performance and safety design bases of the reactor coolant system and its major components interrelated. These design bases are listed as follows:

The reactor coolant system transfers to the steam and power conversion system the heat produced during power operation as well as the heat produced when the reactor is subcritical, including the initial phase of plant cooldown.

The reactor coolant system transfers to the normal residual heat removal system the heat produced during the subsequent phase of plant cooldown and cold shutdown.

During power operation and normal operational transients (including the transition from forced to natural circulation), the reactor coolant system heat removal maintain fuel condition within the operating bounds permitted by the reactor control and protection systems.

The reactor coolant system provides the water used as the core neutron moderator and reflector conserving thermal neutrons and improving neutron economy. The reactor coolant system also provides the water used as a solvent for the neutron absorber used in chemical shim reactivity control.

The reactor coolant system maintains the homogeneity of the soluble neutron poison concentration and the rate of change of the coolant temperature so that uncontrolled reactivity changes do not occur.

The reactor coolant system pressure boundary accommodates the temperatures and pressures associated with operational transients.

The reactor vessel supports the reactor core and control rod drive mechanisms.

The pressurizer maintains the system pressure during operation and limits pressure transients. During the reduction or increase of plant load, the pressurizer accommodates volume changes in the reactor coolant.

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

The steam generators provide high-quality steam to the turbine. The tubes and tubesheet boundary prevent the transfer of radioactivity generated within the core to the secondary system.

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circulated at the flow rate and temperature consistent with achieving the reactor core thermal and hydraulic performance.

The reactor coolant system is monitored for loose parts, as described in Subsection 4.4.6.

Applicable industry standards and equipment classifications of reactor coolant system components are identified in Tables 3.2-1 and 3.2-3 of Subsection 3.2.2.

The reactor vessel head is equipped with suitable provisions for connecting the head vent system, which meets the requirements of 10 CFR 50.34 (f)(2)(vi) (TMI Action Item II.B.1).

(See Subsection 5.4.12.)

The pressurizer surge line and each loop spray line connected with the reactor coolant system are instrumented with resistance temperature detectors (RTDs) attached to the pipe to detect thermal stratification.

2 Design Description re 5.1-1 shows a schematic of the reactor coolant system. Table 5.1-1 provides the principal sures, temperatures, and flow rates of the system at the locations noted in Figure 5.1-1 under mal steady-state, full-power operating conditions. These parameters are based on the best-mate flow at the pump discharge. Table 5.1-2 contains a summary of nominal system design and rating parameters under normal steady-state, full-power operating conditions. These parameters based on the best-estimate conditions at nominal full power. The reactor coolant system volume er these conditions is also provided.

reactor coolant system consists of two heat transfer circuits, each with a steam generator, two tor coolant pumps, and a single hot leg and two cold legs for circulating reactor coolant. In ition, the system includes the pressurizer, interconnecting piping, valves, and instrumentation for rational control and safeguards actuation. All reactor coolant system equipment is located in the tor containment.

ing operation, the reactor coolant pumps circulate pressurized water through the reactor vessel the steam generators. The water, which serves as coolant, moderator, and solvent for boric acid mical shim control), is heated as it passes through the core. It is transported to the steam erators where the heat is transferred to the steam system. Then it is returned to the reactor sel by the pumps to repeat the process.

reactor coolant system pressure boundary provides a barrier against the release of radioactivity erated within the reactor and is designed to provide a high degree of integrity throughout ration of the plant.

reactor coolant system pressure is controlled by operation of the pressurizer, where water and m are maintained in equilibrium by the activation of electrical heaters or a water spray, or both.

am is formed by the heaters or condensed by the water spray to control pressure variations due to ansion and contraction of the reactor coolant.

ng-loaded safety valves are installed above and connected to the pressurizer to provide rpressure protection for the reactor coolant system. These valves discharge into the containment osphere. Three stages of reactor coolant system automatic depressurization valves are also nected to the pressurizer. These valves discharge steam and water through spargers to the 5.1-2 Revision 1

fourth-stage automatic depressurization valves are connected by two redundant paths to each tor coolant loop hot leg and discharge directly to the containment atmosphere.

reactor coolant system is also served by a number of auxiliary systems, including the chemical volume control system (CVS), the passive core cooling system (PXS), the normal residual heat oval system (RNS), the steam generator system (SGS), the primary sampling system (PSS), the d radwaste system (WLS), and the component cooling water system (CCS).

reactor coolant system includes the following:

The reactor vessel, including control rod drive mechanism housings.

The reactor coolant pumps, consisting of four sealless pumps that pump fluid through the entire reactor coolant and reactor systems. Two pumps are coupled with each steam generator.

The portion of the steam generators containing reactor coolant, including the channel head, tubesheet, and tubes.

The pressurizer which is attached by the surge line to one of the reactor coolant hot legs.

With a combined steam and water volume, the pressurizer maintains the reactor system within a narrow pressure range.

The safety and automatic depressurization system valves.

The reactor vessel head vent isolation valves.

The interconnecting piping and fittings between the preceding principal components.

The piping, fittings, and valves leading to connecting auxiliary or support systems.

piping and instrumentation diagram of the reactor coolant system (Figure 5.1-5) shows the nt of the systems located within the containment and the interface between the reactor coolant em and the secondary (heat utilization) system.

res 5.1-3 and 5.1-4 show the plan and section of the reactor coolant loops. These figures show tor coolant system components in relationship to supporting and surrounding steel and concrete ctures. The figures show the protection provided to the reactor coolant system by its physical ut.

3 System Components major components of the reactor coolant system are described in the following subsections.

itional details of the design and requirements of these components are found in other sections of safety analysis report.

3.1 Reactor Vessel reactor vessel is cylindrical, with a hemispherical bottom head and removable, flanged, ispherical upper head. The vessel contains the core, core support structures, control rods, and 5.1-3 Revision 1

design of the AP1000 reactor vessel closely matches the existing vessel designs of stinghouse three-loop plants. New features for the AP1000 have been incorporated without arting from the proven features of existing vessel designs.

vessel has inlet and outlet nozzles positioned in two horizontal planes between the upper head ge and the top of the core. The nozzles are located in this configuration to provide an acceptable s-flow velocity in the vessel outlet region and to facilitate optimum layout of the reactor coolant em equipment. The inlet and outlet nozzles are offset, with the inlet positioned above the outlet, llow mid-loop operation for removal of a main coolant pump without discharge of the core.

lant enters the vessel through the inlet nozzles and flows down the core barrel-vessel wall ulus, turns at the bottom, and flows up through the core to the outlet nozzles.

3.2 AP1000 Steam Generator AP1000 steam generator (SG) is a vertical shell and U-tube evaporator with integral moisture arating equipment. The basic steam generator design and features have been proven in tests in previous steam generators including replacement steam generator designs.

ign enhancements include nickel-chromium-iron Alloy 690 thermally treated tubes on a triangular h, improved antivibration bars, single-tier separators, enhanced maintenance features, and a ary-side channel head design that allows for easy access and maintenance by robotic tooling.

AP1000 steam generator employs tube supports utilizing a broached hole support plate design.

ubes in the steam generator are accessible for sleeving, if necessary. The design enhancements based on proven technology.

basic function of the AP1000 steam generator is to transfer heat from the single-phase reactor lant water through the U-shaped heat exchanger tubes to the boiling, two-phase steam mixture in secondary side of the steam generator. The steam generator separates dry, saturated steam the boiling mixture, and delivers the steam to a nozzle from which it is delivered to the turbine.

er from the feedwater system replenishes the steam generator water inventory by entering the m generator through a feedwater inlet nozzle and feedring.

ddition to its steady-state performance function, the steam generator secondary side provides a er inventory which is continuously available as a heat sink to absorb primary side high perature transients.

3.3 Reactor Coolant Pumps AP1000 reactor coolant pumps are high-inertia, high-reliability, low-maintenance, sealless ps of canned motor design that circulate the reactor coolant through the reactor vessel, loop ng, and steam generators. The pumps are integrated into the steam generator channel head.

integration of the pump suction into the bottom of the steam generator channel head eliminates cross-over leg of coolant loop piping; reduces the loop pressure drop; simplifies the foundation support system for the steam generator, pumps, and piping; and reduces the potential for overing of the core by eliminating the need to clear the loop seal during a small loss of coolant dent.

AP1000 design uses four pumps. Two pumps are coupled with each steam generator.

5.1-4 Revision 1

eller attaches to the rotor shaft of the driving motor, which is an electric induction motor. The or and rotor of the motor are both encased in corrosion-resistant cans constructed and supported ithstand full system pressure.

ary coolant circulates between the stator and rotor which obviates the need for a seal around the or shaft. Additionally, the motor bearings are lubricated by primary coolant. The motor is thus an gral part of the pump. The basic pump design has been proven by many years of service in other lications.

pump motor size is minimized through the use of a variable frequency drive to provide speed trol in order to reduce motor power requirements during pump startup from cold conditions. The able frequency drive is used only during heatup and cooldown when the reactor trip breakers are

n. During power operations, the drive is isolated and the pump is run at constant speed.

rovide the rotating inertia needed for flow coast-down, bi-metallic flywheel assemblies are ched to the pump shaft.

3.4 Primary Coolant Piping ctor coolant system piping is configured with two identical main coolant loops, each of which loys a single 31-inch inside diameter hot leg pipe to transport reactor coolant to a steam erator. The two reactor coolant pump suction nozzles are welded directly to the outlet nozzles on bottom of the steam generator channel head. Two 22-inch inside diameter cold leg pipes in each (one per pump) transport reactor coolant back to the reactor vessel to complete the circuit.

loop configuration and material have been selected such that pipe stresses are sufficiently low he primary loop and large auxiliary lines to meet the requirements to demonstrate "leak-before-ak." Thus, pipe rupture restraints are not required, and the loop is analyzed for pipe ruptures only mall auxiliary lines that do not meet the leak-before-break requirements.

3.5 Pressurizer AP1000 pressurizer is a principal component of the reactor coolant system pressure control em. It is a vertical, cylindrical vessel with hemispherical top and bottom heads, where liquid and or are maintained in equilibrium saturated conditions.

spray nozzle and two nozzles for connecting the safety and depressurization valve inlet headers located in the top head. Electrical heaters are installed through the bottom head. The heaters are ovable for replacement. The bottom head contains the nozzle for attaching the surge line. This connects the pressurizer to a hot leg, and provides for the flow of reactor coolant into and out of pressurizer during reactor coolant system thermal expansions and contractions.

3.6 Pressurizer Safety Valves pressurizer safety valves are spring loaded, self-actuated with back-pressure compensation.

ir set pressure and combined capacity is based on not exceeding the reactor coolant system imum pressure limit during the Level B service condition loss of load transient.

5.1-5 Revision 1

ressurization of the reactor coolant system. This is accomplished by the automatically actuated ressurization valves. The automatic depressurization valves connected to the pressurizer are nged in six parallel sets of two valves in series opening in three stages.

t of fourth-stage automatic depressurization valves is connected to each reactor coolant hot leg.

h set of valves consists of two parallel paths of two valves in series.

mitigate the consequences of the various accident scenarios, the controls are arranged to open valves in a prescribed sequence based on core makeup tank level and a timer as described in tion 6.3.

4 System Performance Characteristics le 5.1-3 lists the nominal thermal hydraulic parameters of the reactor coolant system. The system ormance parameters are also determined for an assumed 10 percent uniform steam generator plugging condition.

ctor coolant flow is established by a detailed design procedure supported by operating plant ormance data and component hydraulics experimental data. The procedure establishes a best-mate flow and conservatively high and low flows for the applicable mechanical and thermal ign considerations. In establishing the range of design flows, the procedure accounts for the ertainties in the component flow resistances and the pump head-flow capability, established by lysis of the available experimental data. The procedure also accounts for the uncertainties in the nique used to measure flow in the operating plant.

nitions of the four reactor coolant flows applied in various plant design considerations are ented in the following paragraphs.

4.1 Best-Estimate Flow best-estimate flow is the most likely value for the normal full-power operating condition. This flow ased on the best estimate of the fuel, reactor vessel, steam generator, and piping flow stances, and on the best estimate of the reactor coolant pump head and flow capability. The best-mate flow provides the basis for the other design flows required for the system and component ign. The best-estimate flow and head also define the performance requirement for the reactor lant pump. Table 5.1-1 lists system pressure losses based on best-estimate flow.

best-estimate flow analysis is based on extensive experimental data, including accurate flow and sure drop data from an operating plant, flow resistance measurements from several fuel embly hydraulics tests, and hydraulic performance measurements from several pump impeller el tests. Since operating plant flow measurements are in close agreement with the calculated t-estimate flows, the flows established with this design procedure can be applied to the plant ign with a high level of confidence.

ough the best-estimate flow is the most likely value to be expected in operation, more servative flow rates are applied in the thermal and mechanical designs.

4.2 Minimum Measured Flow minimum measured flow is specified in the technical specifications as the flow that must be firmed or exceeded by the flow measurements obtained during plant startup. This is the flow used 5.1-6 Revision 1

measured reactor coolant flow will most likely differ from the best-estimate flow because of ertainties in the hydraulics analysis and the inaccuracies in the instrumentation used to measure

. The measured flow is expected to fall within a range around the best-estimate flow. The nitude of the expected range is established by statistically combining the system hydraulics ertainty with the total flow rate within the expected range, less any excess flow margin that may rovided to account for future changes in the hydraulics of the reactor coolant system.

4.3 Thermal Design Flow thermal design flow is the conservatively low value used for thermal-hydraulic analyses where design and measurement uncertainties are not combined statistically, and additional flow margin t therefore be explicitly included. The thermal design flow is derived by subtracting the plant flow surement uncertainty from the minimum measured flow. The thermal design flow is roximately 4.5 percent less than the best-estimate flow. The thermal design flow is confirmed n the plant is placed in operation. Table 5.1-3 provides tabulations of important design ameters based on the thermal design flow.

4.4 Mechanical Design Flow hanical design flow is the conservatively high flow used as the basis for the mechanical design of reactor vessel internals, fuel assemblies, and other system components. Mechanical design flow stablished at 104 percent of best-estimate flow.

5 Combined License Information section contained no requirement for additional information.

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(Nominal Steady-State, Full Power Operating Conditions) ocation Pressure Nominal Flow(a) gure 5.1-1) Description Fluid (psig) Temp. (°F) (gpm) 1 Hot Leg 1 Reactor Coolant 2248 610 177,645 2 Hot Leg 2 Reactor Coolant 2248 610 177,645 3 Cold Leg 1A Reactor Coolant 2310 537.2 78,750 4 Cold Leg 1B Reactor Coolant 2310 537.2 78,750 5 Cold Leg 2A Reactor Coolant 2310 537.2 78,750 6 Cold Leg 2B Reactor Coolant 2310 537.2 78,750 7 Surge Line Inlet Reactor Coolant 2248 610 -

8 Pressurizer Inlet Reactor Coolant 2241 653.0 -

9 Pressurizer Liquid Reactor Coolant 2235 653.0 -

10 Pressurizer Steam Steam 2235 653.0 -

11 Pressurizer Spray 1A Reactor Coolant 2310 537.2 1-2 12 Pressurizer Spray 1B Reactor Coolant 2310 537.2 1-2 13 Common Spray Line Reactor Coolant 2310 537.2 2-4 14 ADS Valve Inlet Steam 2235 653.0 -

15 ADS Valve Inlet Steam 2235 653.0 -

At the conditions specified.

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General Plant design objective, years 60 NSSS power, MWt 3415 Reactor coolant pressure, psia 2250 Reactor coolant liquid volume at power conditions (including 1000 ft3 9600 pressurizer liquid), ft3 Loops Number of cold legs 4 Number of hot legs 2 Hot leg ID, in. 31 Cold leg ID, in. 22 Reactor Coolant Pumps Type of reactor coolant pumps Sealless Number of reactor coolant pumps 4 Estimated motor rating, hp 7300 Effective pump power to coolant, MWt 15 Pressurizer Number of units 1 3 2100 Total volume, ft 3 1000 Water volume, ft Spray capacity, gpm 700 Inside diameter, in. 100 Height, in. 503 Steam Generator Steam generator power, MWt/unit 1707.5 Type Vertical U-tube Feedring-type Number of units 2 Surface area, ft2/unit 123,540 Shell design pressure, psia 1200 Zero load temperature, °F 557 Feedwater temperature, °F 440 Exit steam pressure, psia 836 Steam flow, lb/hr per steam generator 7.49x106 Total steam flow, lb/hr 14.97x106 5.1-9 Revision 1

(Nominal) iled Thermal-Hydraulic Parameters Best-Estimate Flow (BEF) Without Plugging With 10% Tube Plugging ow rate, gpm/loop 157,500 155,500 eactor vessel outlet temperature, °F 610.0 610.4 eactor vessel inlet temperature, °F 537.2 536.8 Minimum Measured Flow (MMF) ow rate, gpm/loop 152,775 150,835 Thermal Design Flow (TDF) ow rate, gpm/loop 149,940 148,000 eactor vessel outlet temperature, °F 611.7 612.2 eactor vessel inlet temperature, °F 535.5 535.0 Mechanical Design Flow (MDF) ow rate, gpm/flow 163,800 t-Estimate Reactor Core and Vessel Thermal-Hydraulic Parameters Without Plugging S power, MWt 3415 ctor power, MWt 3400

-Estimate loop flow, gpm/loop 157,500

-Estimate vessel flow, lb/hr 120.4x106

-Estimate core flow, lb/hr 113.3x106 ctor coolant pressure, psia 2250 el/core inlet temperature, °F 537.2 el average temperature, °F 573.6 el outlet temperature, °F 610.0 age core outlet temperature, °F 614.0 l core bypass flow, (percent of total flow) 5.9 ore barrel nozzle flow 1.0 ead cooling flow 1.5 himble flow 1.9 ore shroud cooling flow 0.5 nallocated bypass flow 1.0 5.1-10 Revision 1

Figure 5.1-1 Reactor Coolant System Schematic Flow Diagram 5.1-11 Revision 1

Figure 5.1-2 Reactor Coolant Loops - Isometric View 5.1-12 Revision 1

WLS 1&2 - UFSAR Figure 5.1-3 Reactor Coolant System - Loop Layout 5.1-13 Revision 1

Figure 5.1-4 Reactor Coolant System - Elevation 5.1-14 Revision 1

WLS 1&2 - UFSAR Inside Reactor Containment Figure 5.1-5 (Sheet 1 of 3)

Reactor Coolant System Piping and Instrumentation Diagram 5.1-15 Revision 1

WLS 1&2 - UFSAR Inside Reactor Containment Figure 5.1-5 (Sheet 2 of 3)

Reactor Coolant System Piping and Instrumentation Diagram 5.1-16 Revision 1

WLS 1&2 - UFSAR Inside Reactor Containment Figure 5.1-5 (Sheet 3 of 3)

Reactor Coolant System Piping and Instrumentation Diagram 5.1-17 Revision 1

sure boundary (RCPB) during plant operation. Section 50.2 of 10 CFR 50 defines the reactor lant pressure boundary as vessels, piping, pumps, and valves that are part of the reactor coolant em (RCS), or that are connected to the reactor coolant system up to and including the following:

The outermost containment isolation valve in system piping that penetrates the containment The second of two valves closed during normal operation in system piping that does not penetrate containment The reactor coolant system overpressure protection valves design transients used in the design and fatigue analysis of ASME Code Class 1 and Class CS ponents, supports, and reactor internals are provided in Subsection 3.9.1. The loading ditions, loading combinations, evaluation methods, and stress limits for design and service ditions for components, core support structures, and component supports are discussed in section 3.9.3.

term reactor coolant system, as used in this section, is defined in Section 5.1. The AP1000 tor coolant pressure boundary is consistent with that of 10 CFR 50.2.

1 Compliance with Codes and Code Cases 1.1 Compliance with 10 CFR 50.55a ctor coolant pressure boundary components are designed and fabricated in accordance with the ME Boiler and Pressure Vessel Code,Section III. A portion of the chemical and volume control em inside containment that is defined as reactor coolant pressure boundary uses an alternate sification in conformance with the requirements of 10 CFR 50.55a(a)(3). Systems other than the tor coolant system connecting to the chemical and volume control system have required isolation are not classified as reactor coolant pressure boundary. The alternate classification is discussed ubsection 5.2.1.3. The quality group classification for the reactor coolant pressure boundary ponents is identified in Subsection 3.2.2. The quality group classification is used to determine the ropriate sections of the ASME Code or other standards to be applied to the components.

edition and addenda of the ASME Code applied in the design and manufacture of each ponent are the edition and addenda established by the requirements of the Design Certification.

use of editions and addenda issued subsequent to the Design Certification is permitted or uired based on the provisions in the Design Certification. If a later Code edition/addenda than the ign Certification Code edition/addenda is used by the material and/or component supplier, then a e reconciliation to determine acceptability is performed as required by the ASME Code, tion III, NCA-1140. The later Code edition/addenda must be authorized in 10 CFR 50.55a or in a cific authorization as provided in 50.55a(a)(3). Code Cases to be used in design and construction identified in this document; additional Code Cases for design and construction beyond those for design certification are not required.

rvice inspection of the reactor coolant pressure boundary is conducted in accordance with the licable edition and addenda of the ASME Boiler and Pressure Vessel Code Section XI, as cribed in Subsection 5.2.4. Inservice testing of the reactor coolant pressure boundary ponents is in accordance with the edition and addenda of the ASME OM Code as discussed in section 3.9.6 for pumps and valves, and as discussed in Subsection 3.9.3.4.4 for dynamic raints.

5.2-1 Revision 1

restriction on piping design is that the treatment of dynamic loads, including seismic loads, in stress analysis will satisfy the requirements of the ASME Code,Section III, articles NB-3210, NB-3220, NB-3620, NB-3650, NC-3620, NC-3650, ND-3620, and ND-3650 9 Edition, 1989 Addenda. The requirements shown below for fillet welds are also applicable.

criteria below are used in place of those in paragraph NB-3683.4(c)(1) and Footnote 11 to res NC/ND-3673.2(b)-1 of the 1989 Addenda to the 1989 Edition of ASME Code,Section III.

criteria is based on the criteria included in the 1989 Edition of the ASME Code,Section III.

girth fillet welds between the piping and socket welded fittings, valves and flanges, and slip on ges in ASME III Class 1, 2, and 3 piping, the primary stress indices and stress intensification ors are as follows:

mary Stress Indices B1 = 0.75 B2 = 1.5 ess Intensification Factor i = 2.1*(tn/Cx), but not less than 1.3 Cx = fillet weld leg length based on ASME III 1989 Edition, Figures NC/ND-4427-1, sketches (c-1), (c-2), and (c-3). For unequal leg length, use smaller leg length for Cx.]*

smic Integrity of the CVS System Inside Containment rovide for the seismic integrity and pressure boundary [integrity of the nonsafety-related (B31.1, ng Class D) CVS piping located inside containment, a seismic analysis will be performed and a S Seismic Analysis Report prepared with a faulted stress limit equal to the smaller of 4.5 Sh and Sy and based on the following additional criteria:

itional loading combinations and stress limits for nonsafety-related chemical and volume control em piping systems and components inside containment]*

ndition Loading Combination(3) [Equations (ND3650) Stress Limit el D PMAX(1) + DW + SSE + SSES 9 Smaller of 4.5 Sh or 3.0 Sy SSES FAM/AM(4) 1.0 Sh TNU + SSES i ( M1 + M2)/Z(2) 3.0 Sh es:

For earthquake loading, PMAX is equal to normal operating pressure at 100% power.

Where: M1 is range of moments for TNU, M2 is one half the range of SSES moments, M1 + M2 is larger of M1 plus one half the range of SSES, or full range of SSES.

See Table 3.9-3 for description of loads.

FAM is amplitude of axial force for SSES; AM is nominal pipe metal area.]*

Staff approval is required prior to implementing a change in this information.

5.2-2 Revision 1

em does not have to be maintained to insure structural integrity of the components.

brication, examination, inspection, and testing requirements as defined in Chapters IV, V, VI, VII of the ASME B31.1 Code are applicable and used for the B31.1 (Piping Class D) CVS piping ems, valves, and equipment inside containment.]*

1.2 Applicable Code Cases ME Code Cases used in the AP1000 are listed in Table 5.2-3.]* In addition, other ASME Code es found in Regulatory Guide 1.84, as discussed in Section 1.9 and Appendix 1A, in effect at the of the Design Certification may be used for pressure boundary components. Use of Code Cases roved in revisions of the Regulatory Guides issued subsequent to the Design Certification may be d as discussed in Subsection 5.2.6.1 by using the process outlined above for updating the ASME e edition and addenda. Use of any Code Case not approved in Regulatory Guide 1.84 on Class 1 ponents is authorized as provided in 50.55a(a)(3) and the requirements of the Design tification.

use of any Code Case conditionally approved in Regulatory Guide 1.84 used on Class 1 ponents meets the conditions established in the Regulatory Guide.

ME Code Cases required for Section XI inspections will be identified in Plant Owner provided ection Plans as referenced in Subsection 5.2.6.2. See Subsection 5.2.4, Inservice Inspection Testing of Class 1 Components, and Section 6.6, Inservice Inspection of Class 2, 3, and Components, for discussion of inservice examinations and procedures.

1.3 Alternate Classification Code of Federal Regulations, Section 10 CFR 50.55a requires the reactor coolant pressure ndary be class A (ASME Boiler and Pressure Vessel Code Section III, Class 1). Components ch are connected to the reactor coolant pressure boundary that can be isolated from the reactor lant system by two valves in series (both closed, both open, or one closed and the other open) automatic actuation to close can be classified as class C (ASME Section III, class 3) according 0.55a.

ortion of the chemical and volume control system inside containment is not classified as safety-ted. The classification of the AP1000 reactor coolant pressure boundary deviates from the uirement that the reactor coolant pressure boundary be classified as safety related and be structed using the ASME Code,Section III as provided in 10 CFR 50.55a. The safety-related sification of the AP1000 reactor coolant pressure boundary ends at the third isolation valve ween the reactor coolant system and the chemical and volume control system. The nonsafety-ted portion of the chemical and volume control system inside containment provides purification of reactor coolant and includes heat exchangers, demineralizers, filters and connecting piping. For a cription of the chemical and volume control system, refer to Subsection 9.3.6. The portion of the mical and volume control system between the inside and outside containment isolation valves is sified as Class B and is constructed using the ASME Code,Section III.

nonsafety-related portion of the chemical and volume control system is designed using SI B31.1 and ASME Code,Section VIII for the construction of the piping, valves, and components.

nonsafety-related portion of the CVS inside containment is analyzed seismically. The methods criteria used for the seismic analysis are similar to those used of seismic Category II pipe and Staff approval is required prior to implementing a change in this information.

5.2-3 Revision 1

alternate classification of the nonsafety-related purification subsystems satisfies the purpose of CFR 50.55a that structures, systems, and components of nuclear power plants which are ortant to safety be designed, fabricated, erected, and tested to quality standards that reflect the ortance of the safety functions to be performed.

AP1000 chemical and volume control system is not required to perform safety-related functions h as emergency boration or reactor coolant makeup. Safety-related core makeup tanks are able of providing sufficient reactor coolant makeup for shutdown and cooldown without makeup plied by the chemical and volume control system. Safe shutdown of the reactor does not require of the chemical and volume control system makeup. AP1000 safe shutdown is discussed in tion 7.4.

isolation valves between the reactor coolant system and the chemical and volume control em are active safety-related valves that are designed, qualified, inspected and tested for the ation requirements. The isolation valves between the reactor coolant system and chemical and me control system are designed and qualified for design conditions that include closing against down flow with full system differential pressure. These valves are qualified for adverse seismic environmental conditions. The valves are subject to inservice testing including operability testing.

potential for release of activity from a break or leak in the chemical and volume control system is imized by the location of the purification subsystem inside containment and the design and test of isolation valves. Chemical and volume control system leakage inside containment is detectable he reactor control leak detection function as potential reactor coolant pressure boundary leakage.

leakage must be identified before the reactor coolant leak limit is reached. The nonsafety-ted classification of the system does not impact the need to identify the source of a leak inside tainment.

2 Overpressure Protection ctor coolant system and steam system overpressure protection during power operation are ided by the pressurizer safety valves and the steam generator safety valves, in conjunction with action of the reactor protection system. Combinations of these systems provide compliance with overpressure protection requirements of the ASME Boiler and Pressure Vessel Code,Section III, agraphs NB-7300 and NC-7300, for pressurized water reactor systems.

temperature overpressure protection is provided by a relief valve in the suction line of the normal dual heat removal (RNS) system. The sizing and use of the relief valve for low temperature rpressure protection is consistent with the guidelines of Branch Technical Position RSB 5-2.

2.1 Design Bases rpressure protection during power operation is provided for the reactor coolant system by the surizer safety valves. This protection is afforded for the following events to envelop those ible events that could lead to overpressure of the reactor coolant system if adequate rpressure protection were not provided:

Loss of electrical load and/or turbine trip Uncontrolled rod withdrawal at power Loss of reactor coolant flow 5.2-4 Revision 1

sizing of the pressurizer safety valves is based on the analysis of a complete loss of steam flow e turbine, with the reactor operating at 102 percent of rated power. In this analysis, feedwater is also assumed to be lost. No credit is taken for operation of the pressurizer level control em, pressurizer spray system, rod control system, steam dump system, or steam line power-rated relief valves. The reactor is maintained at full power (no credit for direct reactor trip on ine trip and for reactivity feedback effects), and steam relief through the steam generator safety es is considered. The total pressurizer safety valve capacity is required to be at least as large as maximum surge rate into the pressurizer during this transient.

sizing procedure results in a safety valve capacity well in excess of the capacity required to ent exceeding 110 percent of system design pressure for the events previously listed. The harge of the safety valve is routed through a rupture disk to containment atmosphere. The ure disk is to contain leakage past the valve. The rupture disk pressure rating is substantially less the set pressure of the safety valve. See Subsection 5.4.11 for additional information on the ty valve discharge system. Subsection 5.4.5 describes the connection of the safety valves to the surizer.

inistrative controls and plant procedures aid in controlling reactor coolant system pressure ng low-temperature operation. Normal plant operating procedures maximize the use of a steam as bubble in the pressurizer during periods of low pressure, low-temperature operation. For those temperature modes of operation when operation with a water solid pressurizer is possible, a f valve in the residual heat removal system provides low-temperature overpressure protection for reactor coolant system. The valve is sized to prevent overpressure during the following credible nts with a water-solid pressurizer:

Makeup/letdown flow mismatch Inadvertent actuation of the pressurizer heaters Loss of residual heat removal with reactor coolant system heatup due to decay heat and pump heat Inadvertent start of one reactor coolant pump Inadvertent hydrogen addition hose events the makeup/letdown flow mismatch is the limiting mass input condition. Inadvertent t of an inactive reactor coolant pump is the limiting heat input condition to size the relief valve.

flow rate postulated for mass input condition is based on the flow from two makeup pumps at the pressure of the relief valve. The heat input condition is based on a 50-degree temperature rence between the reactor coolant system and the steam generator secondary side.

set pressure for the normal residual heat removal system relief valve is established based on the er value of the normal residual heat removal system design pressure and the low-temperature sure limit for the reactor vessel based on ASME Code,Section III, Appendix G, analyses. The sure-temperature limits for the reactor vessel, based on expected material properties and the sel design, are discussed in Subsection 5.3.3.

capacity of the residual heat removal relief valve can maintain the pressure in the reactor coolant em and the residual heat removal system to a pressure less than the lesser of 110 percent of the 5.2-5 Revision 1

rpressure protection for the steam system is provided by steam generator safety valves. The acity of the steam system safety valves limits steam system pressure to less than 110 percent of steam generator shell side design pressure. See Section 10.3 for details.

tion 10.3 discusses the steam generator relief valves and connecting piping.

2.2 Design Evaluation relief capacities of the pressurizer safety valves, steam generator safety valves, and the normal dual heat removal system relief valve are determined from the postulated overpressure transient ditions in conjunction with the action of the reactor protection system. An overpressure protection ort is prepared according to Article NB-7300 of Section III of the ASME Code. WCAP-7907 ference 1) describes the analytical model used in the analysis of the overpressure protection em and the basis for its validity.

pter 15 includes a design description of certain initiating events and describes assumptions e, method of analysis, conclusions, and the predicted response of the AP1000 to those events.

performance characteristics of the pressurizer safety valves are included in the analysis of the onse. The incidents evaluated include postulated accidents not included in the compilation of ible events used for valve sizing purposes.

section 5.4.9 discusses the capacities of the pressurizer safety valves and residual heat removal em relief valve used for low temperature overpressure protection. The setpoints and reactor trip als which occur during operational overpressure transients are discussed in Subsection 5.4.5.

h the current AP1000 pressure-temperature limits (Subsection 5.3.3), the set pressure for the f valve in the normal residual heat removal system is based on a sizing analysis performed to ent the reactor coolant system pressure from exceeding the applicable low temperature pressure for the reactor vessel based on ASME Code,Section III, Appendix G. The limiting mass and rgy input transients are assumed for the sizing analysis.

2.3 Piping and Instrumentation Diagrams connection of the pressurizer safety valves to the pressurizer is incorporated into the pressurizer ty and relief valve module and is discussed in Subsection 5.4.9. The pressurizer safety and relief e module configuration appears in the piping and instrumentation drawing for the reactor coolant em (Figure 5.1-5). The normal residual heat removal system (Subsection 5.4.7) incorporates the f valve for low-temperature overpressure protection. The valves which isolate the normal residual t removal system from the reactor coolant system do not have an autoclosure interlock.

re 5.4-6 shows a simplified sketch of the normal residual heat removal system. Figure 5.4-7 ws the piping and instrumentation drawing for the residual heat removal system.

tion 10.3 discusses the safety valves for the main steam system. Figure 10.3.2-1 shows the ng and instrumentation drawing for the main steam system.

2.4 Equipment and Component Description section 5.4.9 discusses the design and design parameters for the safety valves providing rating and low-temperature overpressure protection. The pressurizer safety valves are ASME er and Pressure Vessel Code Class 1 components. These valves are tested and analyzed using design transients, loading conditions, seismic considerations, and stress limits for Class 1 ponents as described in Subsections 3.9.1, 3.9.2, and 3.9.3.

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ndary function, the relief valve is an ASME Code Class 2 component and is analyzed to the ropriate requirements.

ddition to the testing and analysis required for ASME Code requirements, the pressurizer safety es are of a type which has been verified to operate during normal operation, anticipated sients, and postulated accident conditions. The verification program (Reference 2) was blished by the Electric Power Research Institute to address the requirements of CFR 50.34 (f)(2)(x). These requirements do not apply to relief valves of the size and type esented by the relief valve on the normal residual heat removal system.

tion 10.3 discusses the equipment and components that provide the main steam system rpressure protection.

2.5 Mounting of Pressure Relief Devices section 5.4.9 describes the design and installation of the pressure relief devices for the reactor lant system. Section 3.9 describes the design basis for the assumed loads for the primary- and ondary-side pressure relief devices. Subsection 10.3.2, discusses the main steam safety valves the power-operated atmospheric steam relief valves.

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

ng, valves, and associated equipment used for overpressure protection are classified according e classification system discussed in Subsection 3.2.2. These safety-class designations are neated in Table 3.2-3.

2.7 Material Specifications Subsection 5.2.3 for the material specifications for the pressurizer safety valves. The piping in pressurizer safety and relief valve module up to the safety valve is considered reactor coolant em. See Subsection 5.2.3 for material specifications. The discharge piping is austenitic stainless

l. Subsection 5.4.7 specifies the materials used in the normal residual heat removal system.

2.8 Process Instrumentation h pressurizer safety valve discharge line incorporates a main control room temperature indicator alarm to notify the operator of steam discharge due to either leakage or actual valve operation.

2.9 System Reliability ME Code safety valves and relief valves have demonstrated a high degree of reliability over many rs of service. The in-service inspection and testing required of safety valves and relief valves bsections 3.9.6 and 5.2.4 and Section 6.6) provides assurance of continued reliability and formance to setpoints. The assessment of reliability, availability, and maintainability which is done valuate the estimated availability for the AP1000 includes estimates for the contribution of safety es and relief valves to unavailability. These estimates were based on experience for operating s.

5.2-7 Revision 1

ection required for the safety valves and relief valves. The testing and inspection requirements in conformance with industry standards, including Section XI of the ASME Code.

3 Reactor Coolant Pressure Boundary Materials 3.1 Materials Specifications le 5.2-1 lists material specifications used for the principal pressure-retaining applications in ss 1 primary components and reactor coolant system piping. Material specifications with grades, ses or types are included for the reactor vessel components, steam generator components, tor coolant pump, pressurizer, core makeup tank, and the passive residual heat removal heat hanger. Table 5.2-1 lists the application of nickel-chromium-iron alloys in the reactor coolant sure boundary. The use of nickel-chromium-iron alloy in the reactor coolant pressure boundary is ed to Alloy 690, or its associated weld metals Alloys 52, 52M, and 152, and similar alloys eloped for improved weldability as allowed by ASME Boiler and Pressure Vessel Code rules.

am generator tubes use Alloy 690 in the thermally treated form. Nickel-chromium-iron alloys are d where corrosion resistance of the alloy is an important consideration and where the use of el-chromium-iron alloy is the choice because of the coefficient of thermal expansion.

section 5.4.3 defines reactor coolant piping. See Subsection 4.5.2 for material specifications d for the core support structures and reactor internals. See appropriate sections for internals of r components. Engineered safeguards features materials are included in Subsection 6.1.1. The safety-related portion of the chemical and volume control system inside containment in contact reactor coolant is constructed of or clad with corrosion resistant material such as Type 304 or e 316 stainless steel or material with equivalent corrosion resistance. The materials are patible with the reactor coolant. The nonsafety-related portion of the chemical and volume trol system is not required to conform to the process requirements outlined below.

le 5.2-1 material specifications are the materials used in the AP1000 reactor coolant pressure ndary. The materials used in the reactor coolant pressure boundary conform to the applicable ME Code rules. Cast austenitic stainless steel does not exceed a ferrite content of 20 FN.

culation of ferrite content is based on Hulls equivalent factors.

welding materials used for joining the ferritic base materials of the reactor coolant pressure ndary conform to or are equivalent to ASME Material Specifications SFA 5.1, 5.5, 5.17, 5.18,

, 5.23, 5.28, 5.29, and 5.30. They are qualified to the requirements of the ASME Code, tion III.

welding materials used for joining the austenitic stainless steel base materials of the reactor lant pressure boundary conform to ASME Material Specifications SFA 5.4, 5.9, 5.22, and 5.30.

y are qualified to the requirements of the 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, or are similar welding alloys to those in SFA-5.11 or

-5.14 developed for improved weldability as allowed by the ASME Boiler and Pressure Vessel e rules. They are qualified to the requirements of the ASME Code,Section III.

fabrication and installation specifications for partial penetration welds with Alloy 52/52M/152, in the ASME Class 1 reactor coolant pressure boundary, require successive dye penetrant minations after the first pass and after every 1/4-inch of weld metal. The specifications for oove welds, which join ASME Class 1 reactor coolant pressure boundary penetrations require 5.2-8 Revision 1

ions of the reactor vessel (Section 5.3), the reactor coolant pumps (Subsection 5.4.1), the steam erators (Subsection 5.4.2), the reactor coolant system piping (Subsection 5.4.3), the pressurizer bsection 5.4.5), the core makeup tanks (Subsection 5.4.13), and the passive residual heat oval heat exchanger (Subsection 5.4.14).

3.2 Compatibility with Reactor Coolant 3.2.1 Chemistry of Reactor Coolant reactor coolant system chemistry specifications conform to the recommendation of Regulatory de 1.44 and are shown in Table 5.2-2.

reactor coolant system water chemistry is selected to minimize corrosion. Routinely scheduled lyses of the coolant chemical composition are performed to verify that the reactor coolant mistry meets the specifications. Other additions, such as those to reduce activity transport and osition, may be added to the system.

chemical and volume control system (CVS) provides a means for adding chemicals to the tor coolant system. The chemicals perform the following functions:

Control the pH of the coolant during prestartup testing and subsequent operation Scavenge oxygen from the coolant during heatup Control radiolysis reactions involving hydrogen, oxygen, and nitrogen during power operations following startup le 5.2-2 shows the normal limits for chemical additives and reactor coolant impurities for power ration.

pH control chemical is lithium hydroxide monohydrate, enriched in the lithium-7 isotope to percent. This chemical is chosen for its compatibility with the materials and water chemistry of ated water/stainless steel/zirconium/nickel-chromium-iron systems. In addition, lithium-7 is duced in solution from the neutron irradiation of the dissolved boron in the coolant. The lithium-7 roxide is introduced into the reactor coolant system via the charging flow. The concentration of um-7 hydroxide in the reactor coolant system is maintained in the range specified for pH control.

ing reactor startup from the cold condition, hydrazine is used as an oxygen-scavenging agent.

hydrazine solution is introduced into the reactor coolant system in the same manner as cribed for the pH control agent.

reactor coolant is treated with dissolved hydrogen to control the net decomposition of water by olysis in the core region. The hydrogen reacts with oxygen introduced into the reactor coolant em by the radiolysis effect of radiation on molecules. Hydrogen makeup is supplied to the reactor lant system by direct injection of high pressure gaseous hydrogen, which can be adjusted to ide the correct equilibrium hydrogen concentration. Subsection 1.9.1 indicates the degree of formance with Regulatory Guide 1.44, "Control of the Use of Sensitized Stainless Steel."

on, in the chemical form of boric acid, is added to the reactor coolant system for long-term tivity control of the core.

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water chemistry program is based on industry guidelines as described in EPRI TR-1002884, ssurized Water Reactor Primary Water Chemistry (Reference 201). The program includes odic monitoring and control of chemical additives and reactor coolant impurities listed in le 5.2-2. Detailed procedures implement the program requirements for sampling and analysis uencies, and corrective actions for control of reactor water chemistry.

frequency of sampling water chemistry varies (e.g. continuous, daily, weekly, or as needed) ed on plant operating conditions and the EPRI water chemistry guidelines. Whenever corrective ons are taken to address an abnormal chemistry condition, increased sampling is utilized to verify effectiveness of these actions. When measured water chemistry parameters are outside the cified range, corrective actions are taken to bring the parameter back within the acceptable range within the time period specified in the EPRI water chemistry guidelines. Following corrective ons, additional samples are taken and analyzed to verify that the corrective actions were effective turning the concentrations of contaminants to within the specified range.

mistry procedures will provide guidance for the sampling and monitoring of primary coolant perties.

3.2.2 Compatibility of Construction Materials with Reactor Coolant itic low-alloy and carbon steels used in principal pressure-retaining applications have corrosion-stant cladding on surfaces exposed to the reactor coolant. The corrosion resistance of the ding material is at least equivalent to the corrosion resistance of Types 304 and 316 austenitic nless steel alloys or nickel-chromium-iron alloy, martensitic stainless steel, and precipitation-dened stainless steel. These clad materials may be subjected to the ASME Code-required tweld heat treatment for ferritic base materials.

itic low-alloy and carbon steel nozzles have safe ends of stainless steel-wrought materials ded to nickel-chromium-iron alloy-weld metal F-number 43 buttering. The safe end is welded to F 43 buttering after completion of postweld heat treatment of the buttering when the nozzle is er than a 4-inch nominal inside diameter and/or the wall thickness is greater than 0.531 inch.

tenitic stainless steel and nickel-chromium-iron alloy base materials with primary pressure-ining applications are used in the solution-annealed or thermally treated conditions. These heat tments are as required by the material specifications.

ing later fabrications, these materials are not heated above 800°F other than locally by welding rations. The solution-annealed surge line material is subsequently formed by hot-bending wed by a resolution-annealing heat treatment.

ponents using stainless steel sensitized in the manner expected during component fabrication installation operate satisfactorily under normal plant chemistry conditions in pressurized water tor (PWR) systems because chlorides, fluorides, and oxygen are controlled to very low levels.

section 1.9.1 indicates the degree of conformance with Regulatory Guide 1.44, "Control of the of Sensitized Stainless Steel."

dfacing material in contact with reactor coolant is primarily a qualified low or zero cobalt alloy ivalent to Stellite-6. The use of cobalt base alloy is minimized. Low or zero cobalt alloys used for dfacing or other applications where cobalt alloys have been previously used are qualified using r and corrosion tests. The corrosion tests qualify the corrosion resistance of the alloy in reactor 5.2-10 Revision 1

3.2.3 Compatibility with External Insulation and Environmental Atmosphere eneral, materials that are used in principal pressure-retaining applications and are subject to ated temperature during system operation are in contact with thermal insulation that covers their r surfaces.

thermal insulation used on the reactor coolant pressure boundary is reflective stainless l-type.

compounded materials in the form of blocks, boards, cloths, tapes, adhesives, cements, etc., are ated to provide protection of austenitic stainless steels against stress corrosion that may result accidental wetting of the insulation by spillage, minor leakage, or other contamination from the ironmental atmosphere. Subsection 1.9.1 indicates the degree of conformance with Regulatory de 1.36, "Nonmetallic Thermal Insulation for Austenitic Stainless Steel."

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

ere minor leakage is considered possible based on service experience (such as valve packing, p seals, etc.), only materials compatible with the coolant are used. Table 5.2-1 shows examples.

itic materials exposed to coolant leakage can be readily observed as part of the inservice visual

/or nondestructive inspection program to confirm 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 reactor coolant pressure boundary components meet the uirements of the ASME Code,Section III, Subarticle NB-2300. Those portions of the reactor lant pressure boundary that meet the requirements of ASME Code,Section III, Class 2 per the ria of 10 CFR 50.55a, meet the fracture toughness requirements of the ASME Code,Section III, article NC-2300. The fracture toughness properties of the reactor coolant pressure boundary ponents also meet the requirements of Appendix G of 10 CFR 50.

fracture toughness properties of the reactor vessel materials are discussed in Section 5.3.

iting steam generator and pressurizer reference temperatures for a nil ductility transition (RTNDT) peratures are guaranteed at 10°F for the base materials and the weldments.

se materials meet the 50-foot-pound absorbed energy and 35-mils lateral expansion uirements of the ASME Code,Section III, at 70°F. The actual results of these tests are provided in ASME material data reports which are supplied for each component and submitted to the owner e time of shipment of the component.

perature instruments and Charpy impact test machines are calibrated to meet the requirements e ASME Code,Section III, Paragraph NB-2360.

stinghouse has conducted a test program to determine the fracture toughness of low-alloy ferritic erials with specified minimum yield strengths greater than 50,000 psi to demonstrate compliance Appendix G of the ASME Code,Section III. In this program, fracture toughness properties were rmined and shown to be adequate for base metal plates and forgings, weld metal, and 5.2-11 Revision 1

3.3.2 Control of Welding ding is conducted using procedures qualified according to the rules of Sections III and IX of the ME Code. Control of welding variables (as well as examination and testing) during procedure lification and production welding is performed according to ASME Code requirements.

practices for storing and handling welding electrodes and fluxes comply with ASME Code, tion III, Paragraphs NB-2400 and NB-4400.

section 1.9.1 indicates the degree of conformance of the ferritic materials components of the tor coolant pressure boundary with Regulatory Guides 1.31, "Control of Ferrite Content in nless Steel Welds"; 1.34, "Control of Electroslag Weld Properties"; 1.43, "Control of Stainless el Weld Cladding of Low-Alloy Steel Components"; 1.50, "Control of Preheat Temperature for ding of Low-Alloy Steel"; and 1.71, "Welder Qualification for Areas of Limited Accessibility."

3.4 Fabrication and Processing of Austenitic Stainless Steel sections 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 to avoid sensitization and to ent intergranular attack (IGA) of austenitic stainless steel components. Also, Subsection 1.9.1 cates the degree of conformance with Regulatory Guide 1.44.

3.4.1 Cleaning and Contamination Protection Procedures tenitic stainless steel materials used in the fabrication, installation, and testing of nuclear steam ply components and systems are handled, protected, stored, and cleaned according to gnized, accepted methods designed to minimize contamination that could lead to stress osion cracking. The procedures covering these controls are stipulated in process specifications.

ls used in abrasive work operations on austenitic stainless steel, such as grinding or wire hing, do not contain and are not contaminated with ferritic carbon steel or other materials that ld contribute to intergranular cracking or stress-corrosion cracking.

se process specifications supplement the equipment specifications and purchase order uirements of every individual austenitic stainless steel component or system procured for the 000, regardless of the ASME Code classification.

process specifications define these requirements and follow the guidance of ASME NQA-1.

section 1.9.1 indicates the degree of conformance of the austenitic stainless steel components of reactor coolant pressure boundary with Regulatory Guide 1.37, "Quality Assurance uirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear er Plants."

3.4.2 Solution Heat Treatment Requirements austenitic stainless steels listed in Table 5.2-1 are used in the final heat-treated condition uired by the respective ASME Code,Section II, materials specification for the particular type or de of alloy.

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ided that the solution heat treatment is followed by water quenching. Simple shapes are defined lates, sheets, bars, pipe, and tubes, as well as forgings, fittings, and other shaped products that ot have inaccessible cavities or chambers that would preclude rapid cooling when water-nched. This characterization of cavities or chambers as inaccessible is in relation to the entry of er during quenching and is not a determination of the component accessibility for inservice ection.

en testing is required, the tests are performed according to a process specification following the elines of ASTM A 262, Practice A or E.

3.4.4 Prevention of Intergranular Attack of Unstabilized Austenitic Stainless Steels tabilized stainless steels can be subject to intergranular attack if the steels are sensitized, if ain species are present, such as chlorides and oxygen, and if they are exposed to a stressed dition. In the reactor coolant system, reliance is placed on the elimination or avoidance of these ditions. This is accomplished by the following:

Control of primary water chemistry to provide a benign environment Use of materials in the final heat-treated condition and the prohibition of subsequent heat treatments from 800°F to 1500°F Control of welding processes and procedures to avoid heat-affected zone sensitization Confirmation that the welding procedures used for the manufacture of components in the primary pressure boundary and the reactor internals do not result in the sensitization of heat-affected zones her information on each of these steps is provided in the following paragraphs.

water chemistry in the reactor coolant system is controlled to prevent the intrusion of aggressive ments. In particular, the maximum permissible oxygen and chloride concentrations are 0.005 ppm 0.15 ppm, respectively. Table 5.2-2 lists the recommended reactor coolant water chemistry cifications.

precautions taken to prevent the intrusion of chlorides into the system during fabrication, ping, and storage are stipulated in the appropriate process specifications. The use of hydrogen rpressure precludes the presence of oxygen during operation.

effectiveness of these controls has been demonstrated by both laboratory tests and operating erience. The long-term exposure of severely sensitized stainless steels to reactor coolant ironments in early Westinghouse pressurized water reactors has not resulted in any sign of rgranular attack. WCAP-7477 (Reference 4) describes the laboratory experimental findings and tor operating experience. The additional years of operations since Reference 4 was issued have ided further confirmation of the earlier conclusions that severely sensitized stainless steels do undergo any intergranular attack in Westinghouse pressurized water reactor coolant ironments.

ough there is no evidence that pressurized water reactor coolant water attacks sensitized nless steels, it is good metallurgical practice to avoid the use of sensitized stainless steels in the tor coolant system components.

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Solution-annealed and water-quenched Solution-annealed and cooled through the sensitization temperature range within less than about 5 minutes stinghouse has verified that these practices will prevent sensitization by performing corrosion s on wrought material as it was received.

heat-affected zones of welded components must, of necessity, be heated into the sensitization perature range (800°F to 1500°F). However, severe sensitization (that is, continuous grain ndary precipitates of chromium carbide, with adjacent chromium depletion) can be avoided by trolling welding parameters and welding processes. The heat input and associated cooling rate ugh the carbide precipitation range are of primary importance. Westinghouse has demonstrated by corrosion-testing a number of weldments.

heat input in austenitic pressure boundary weldments is controlled by the following:

Limiting the maximum interpass temperature to 350°F Exercising approval rights on welding procedures Requiring qualification of processes 3.4.5 Retesting Unstabilized Austenitic Stainless Steels Exposed to Sensitization Temperatures ring the course of fabrication, steel is inadvertently exposed to the sensitization temperature ge, the material may be tested according to a process specification, following the guidelines of M A 262, to verify that it is not susceptible to intergranular attack. Testing is not required for the wing:

Cast metal or weld metal with a ferrite content of 5 percent or more Material with a carbon content of 0.03 percent or less Material exposed to special processing, provided the following:

- Processing is properly controlled to develop a uniform product

- Adequate documentation exists of service experience and/or test data to demonstrate that the processing will not result in increased susceptibility to intergranular attack ch material is not verified to be not susceptible to intergranular attack, the material is resolution-ealed and water-quenched or rejected.

3.4.6 Control of Welding following paragraphs address Regulatory Guide 1.31, "Control of Ferrite Content in Stainless el Weld Metal." They present the methods used, and the verification of these methods, for tenitic stainless steel welding.

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, it has been well documented that delta ferrite is one of the mechanisms for reducing the ceptibility of stainless steel welds to hot cracking. The minimum delta ferrite level below which the erial will be prone to hot cracking lies between 0 and 3 percent delta ferrite.

following paragraphs discuss welding processes used to join stainless steel parts in components igned, fabricated, or stamped according to the ASME Code,Section III, Classes 1 and 2, and support components. Delta ferrite control is appropriate for the preceding welding requirements, ept where no filler metal is used or where such control is not applicable, such as the following:

tron beam welding; autogenous gas shielded tungsten arc welding; explosive welding; welding g fully austenitic welding materials.

fabrication and installation specifications require welding procedures and welder qualification ording to Section III of the ASME Code. They also include the delta ferrite determinations for the tenitic stainless steel welding materials used for welding qualification testing and for production essing.

cifically, the undiluted weld deposits of the "starting" welding materials must contain at least rcent delta ferrite. (The equivalent ferrite number may be substituted for percent delta ferrite.)

is determined by chemical analysis and calculation using the appropriate weld metal constitution rams in Section III of the ASME Code or magnetic measurement by calibrated instruments.

en new welding procedure qualification tests are evaluated for these applications, including repair ding of raw materials, they are performed according to the requirements of Sections III and IX of ASME Code.

results of the destructive and nondestructive tests are recorded in the procedure qualification rd, in addition to the information required by Section III of the ASME Code.

welding materials used for fabrication and installation welds of austenitic stainless steel erials and components meet the requirements of Section III of the ASME Code. For applications g austenitic stainless steel welding material, the material conforms to ASME weld metal lysis A-8, Type 308, 308L, 309, 309L, 316, or 316L.

a ferrite determinations of austenitic stainless steel weld filler materials to be used with gas sten arc welding (GTAW) and plasma arc welding (PAW) processes and any other welding erial to be used with any GTAW, PAW, or gas metal arc welding (GMAW) process, including sumable insert material, shall be made using a magnetic measuring instrument and weld deposits e in accordance with ASME Code,Section III, NB-2432.1(c) or (d) or, alternatively, the delta te determinations for welding materials may be performed by the use of chemical analysis ormed either on the filler metal or on an undiluted weld deposit made in accordance with 2432. The allowable delta ferrite range shall be 5 FN to 20 FN for the weld material with low ybdenum content, and 5 FN to 16 FN for weld materials with higher molybdenum content such as es 316/316L, which contain 2.0 to 3.0% molybdenum.

a ferrite determinations of austenitic stainless steel weld filler materials to be used with flux ding processes, such as shielded metal arc welding (SMAW), submerged arc welding (SAW) or lectro-slag weld (ESW) deposited cladding and other welding material to be used with other than GTAW, PAW, or GMAW process shall be made using a magnetic measuring instrument and weld osits made in accordance with ASME Code,Section III, B-2432.1(c) or (d) or, alternatively, the a ferrite determinations may be performed by the use of chemical analysis of the undiluted weld osit of NB-2432 in conjunction with Figure NB-2433.1-1. The allowable delta ferrite range shall be 5.2-15 Revision 1

ding materials are tested using the welding energy inputs employed in production welding.

binations of approved heats and lots of welding materials are used for welding processes. The ding quality assurance program includes identification and control of welding material by lots and ts as appropriate. Weld processing is monitored according to approved inspection programs that ude review of materials, qualification records, and welding parameters. Welding systems are also ject to the following:

Quality assurance audit, including calibration of gauges and instruments Identification of welding materials Welder and procedure qualifications Availability and use of approved welding and heat-treating procedures Documentary evidence of compliance with materials, welding parameters, and inspection requirements rication and installation welds are inspected using nondestructive examination methods ording to Section III of the ASME Code rules.

erify the reliability of these controls, Westinghouse has completed a delta ferrite verification gram, described in WCAP-8324-A (Reference 5). This program 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 regulatory staff's eptance letter and topical report evaluation were received on December 30, 1974. The program lts, which support the hypothesis presented in WCAP-8324-A (Reference 5), are summarized in AP-8693 (Reference 6).

section 1.9.1 indicates the degree of conformance of the austenitic stainless steel components of reactor coolant pressure boundary with Regulatory Guides 1.34, "Control of Electroslag Weld perties," and 1.71, "Welder Qualification for Areas of Limited Accessibility."

3.4.7 Control of Cold Work in Austenitic Stainless Steels use of cold worked austenitic stainless steels is limited to small parts including pins and eners where proven alternatives are not available and where cold worked material has been used cessfully in similar applications. Cold work control of austenitic stainless steels in pressure ndary applications is provided by limiting the hardness of austenitic stainless steel raw material controlling the hardness during fabrication by process control of bending, cold forming, ightening or other similar operation. Grinding of material in contact with reactor coolant is trolled by procedures. Ground surfaces are finished with successively finer grit sizes to remove bulk of cold worked material.

3.5 Threaded Fastener Lubricants lubricants to be used on threaded fasteners which maintain pressure boundary integrity in the tor coolant and related systems and in the steam, feed, and condensate systems; threaded eners used inside those systems; and threaded fasteners used in component structural support 5.2-16 Revision 1

hreaded fasteners or can be in contact with the fastener in service, their selection is based on sfactory experience or test data. Selection considers possible adverse interaction between lants and lubricants. Lubricants containing molybdenum sulphide are prohibited.

4 Inservice Inspection and Testing of Class 1 Components service and inservice inspection and testing of ASME Code Class 1 pressure-retaining ponents (including vessels, piping, pumps, valves, bolting, and supports) within the reactor lant pressure boundary are performed in accordance with Section XI of the ASME Code including enda according to 10 CFR 50.55a(g). This includes all ASME Code Section XI mandatory endices.

initial inservice inspection program incorporates the latest edition and addenda of the ASME er and Pressure Vessel Code approved in 10 CFR 50.55a(b) on the date 12 months before initial load. Inservice examination of components and system pressure tests conducted during cessive 120-month inspection intervals must comply with the requirements of the latest edition addenda of the Code incorporated by reference in 10 CFR 50.55a(b) 12 months before the start e 120-month inspection interval (or the optional ASME Code cases listed in NRC Regulatory de 1.147, that are incorporated by reference in 10 CFR 50.55a(b)), subject to the limitations and ifications listed in 10 CFR 50.55a(b).

specific edition and addenda of the Code used to determine the requirements for the inspection testing plan for the initial and subsequent inspection intervals is to be delineated in the inspection gram. The Code includes requirements for system pressure tests and functional tests for active ponents. The requirements for system pressure tests are defined in Section XI, IWA-5000 and

-5000. These tests verify the pressure boundary integrity in conjunction with inservice inspection.

tion 6.6 discusses Classes 2 and 3 component examinations.

section 3.9.6 discusses the in-service functional testing of valves for operational readiness. Since e of the pumps in the AP1000 are required to perform an active safety function, the operational diness test program for pumps is controlled administratively.

onformance with ASME Code and NRC requirements, the preparation of inspection and testing grams is discussed in Subsection 5.2.6. A preservice inspection program (nondestructive mination) for the AP1000 will be developed and submitted to the NRC. The in-service inspection gram will be submitted to the NRC as discussed in Subsection 5.2.6. These programs will comply applicable in-service inspection provisions of 10 CFR 50.55a(b)(2).

preservice program provides details of areas subject to examination, as well as the method and nt of preservice examinations. The in-service program details the areas subject to examination the method, extent, and frequency of examinations. Additionally, component supports and mination requirements are included in the inspection programs.

4.1 System Boundary Subject to Inspection ME Code Class 1 components (including vessels, piping, pumps, valves, bolting, and supports) designated AP1000 equipment Class A (see Subsection 3.2.2). Class 1 pressure-retaining ponents and their specific boundaries are included in the equipment designation list and the line ignation list. Both of these lists are contained in the inspection programs.

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de 1.26, the Class 1 boundary includes the following:

Reactor pressure vessel; Portions of the Reactor System (RXS);

Portions of the Chemical and Volume Control System (CVS);

Portions of the Incore Instrumentation System (IIS);

Portions of the Passive Core Cooling System (PXS);

Portions of the Reactor Coolant System (RCS); and Portions of the Normal Residual Heat Removal System (RNS).

se portions of the above systems within the Class 1 boundary are those items that are part of the tor coolant pressure boundary as defined in Section 5.2.

lusions ions of the systems within the reactor coolant pressure boundary (RCPB), as defined above, that excluded from the Class 1 boundary in accordance with 10 CFR Part 50, Section 50.55a, are as ws:

Those components where, in the event of postulated failure of the component during normal reactor operation, the reactor can be shut down and cooled down in an orderly manner, assuming makeup is provided by the reactor coolant makeup system only; or Components that are or can be isolated from the reactor coolant system by two valves in series (both closed, both open, or one closed and the other open). Each open valve is capable of automatic actuation and, assuming the other valve is open, its closure time is such that, in the event of postulated failure of the component during normal reactor operation, each valve remains operable and the reactor can be shut down and cooled down in an orderly manner, assuming makeup is provided by the reactor coolant makeup system only.

description of portions of systems excluded from the RCPB does not address Class 1 ponents exempt from inservice examinations under ASME Code Section XI rules. The Class 1 ponents exempt from inservice examinations are defined by ASME Section XI, IWB-1220, ept as modified by 10 CFR 50.55a.

inservice inspection program is augmented for reactor vessel top head inspections by use of the ME Code Case N-729-1, Alternative Examination Requirements for Pressurized-Water Reactor R) Vessel Upper Heads With Nozzles Having Pressure-Retaining Partial-Penetration Welds, as ified by the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D).

c acid corrosion control procedures require inspection of the reactor coolant pressure boundary ject to leakage that can cause boric acid corrosion of the reactor coolant pressure boundary erials. The procedures determine the principal locations where leaks can cause degradation of primary pressure boundary by boric acid corrosion. Potential paths of the leaking coolant are blished. The boric acid corrosion control procedures also contain methods for conducting 5.2-18 Revision 1

boric acid corrosion control procedures consist of:

1. Visual inspections of component surfaces that are potentially exposed to borated water leakage.

2. Discovery of leak path and removal of boric acid residue.

3. Assessment of the corrosion.

4. Follow-up inspection for adequacy of corrective actions, as appropriate.

inservice inspection program, along with the boric acid corrosion control procedures, provides ance for inspecting the integrity of bolting and threaded fasteners.

in-service inspection program is augmented to include the performance of a 100 percent metric examination of the weld build-up on the reactor vessel head for the instrumentation etrations (Quickloc) conducted once during each 120-month inspection interval in accordance the ASME Code,Section XI. The weld build-up acceptance standards are those provided in ME Code,Section XI, IWB-3514. Personnel performing examinations and the ultrasonic mination systems are qualified in accordance with ASME Code,Section XI, Appendix VIII.

rnatively, an alternative inspection may be developed in conjunction with the voluntary consensus dards bodies (i.e., ASME) and submitted to the NRC for approval.

4.2 Arrangement and Inspectability ME Code Class 1 components are designed so that access is provided in the installed condition isual, surface, and volumetric examinations specified by the ASME Code Section XI 98 Edition) and mandatory appendices. Design provisions, in accordance with Section XI, cle IWA-1500, are incorporated in the design processes for Class 1 components.

AP1000 design activity includes a design for inspectability program. The goal of this program is rovide for the inspectability access and conformance of component design with available ection equipment and techniques. Factors such as examination requirements, examination niques, accessibility, component geometry and material selection are used in evaluating ponent designs. Examination requirements and examination techniques are defined by inservice ection personnel. Inservice inspection review as part of the design process provides component igns that conform to inspection requirements and establishes recommendations for enhanced ections.

siderable experience is utilized in designing, locating, and supporting pressure-retaining ponents to permit preservice and in-service inspection required by Section XI of the ASME Code.

tors such as examination requirements, examination techniques, accessibility, component metry, and material selections aid in establishing the designs. The inspection design goals are to inate uninspectable components, reduce occupational radiation exposure, reduce inspections s, allow state-of-the-art inspection system, and enhance flaw detection and the reliability of flaw racterization.

one example of component geometry that reduces inspection requirements, the reactor pressure sel has no longitudinal welds requiring in-service inspection. No Quality Group A (ASME Code ss 1) components require in-service inspection during reactor operation.

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ection and servicing of pumps and valves. Permanent or temporary working platforms, folding, and ladders facilitate access to piping and component welds. The components and welds uiring in-service inspection allow for the application of the required in-service inspection methods.

h design features include sufficient clearances for personnel and equipment, maximized mination surface distances, two-sided access, favorable materials, weld-joint simplicity, ination of geometrical interferences, and proper weld surface preparation.

e of the ASME Class 1 components are included in modules fabricated offsite and shipped to the (See Subsection 3.9.1.5.) The modules are designed and engineered to provide access for ervice inspection and maintenance activities. The attention to detail engineered into the modules re construction provides the accessibility for inspection and maintenance. Relief from Section XI uirements should not be required for Class 1 pressure retaining components in the AP1000.

ure unanticipated changes in the ASME Code,Section XI requirements could, however, essitate relief requests. Relief from the inspection requirements of ASME Code,Section XI will be uested when full compliance is not practical according to the requirements of CFR 50.55a(g)(5)(iv). In such cases, specific information will be provided which identifies the licable Code requirements, justification for the relief request, and the inspection method to be d as an alternative.

ce is provided to handle and store insulation, structural members, shielding, and other materials ted to the inspection. Suitable hoists and other handling equipment, lighting, and sources of er for inspection equipment are installed. The integrated head package provides for access to ect the reactor vessel head and the weld of the control rod drive mechanisms to the reactor sel head. Closure studs, nuts, and washers are removed to a dry location for direct inspection.

4.3 Examination Techniques and Procedures visual, surface, and volumetric examination techniques and procedures agree with the uirements of Subarticle IWA-2200 and Table IWB-2500-1 of the ASME Code,Section XI.

lification of the ultrasonic inspection equipment, personnel and procedures is in compliance with endix VII of the ASME Code,Section XI. Approved Code Cases listed in Regulatory Guide 1.147 applied as the need arises during the pre-service inspection. Approved Code Cases determined ecessary to accomplish pre-service inspection activities are used. The liquid penetrant method or magnetic particle method is used for surface examinations. Radiography, ultrasonic, or eddy ent techniques (manual or remote) are used for volumetric examinations.

reactor vessel is designed so that the reactor pressure vessel (RPV) inspections can be ormed primarily from the vessel internal surfaces. These inspections can be done remotely using ting inspection tool designs to minimize occupational radiation exposure and to facilitate the ections. Access is also available for the application of inspection techniques from the outside of complete reactor pressure vessel. Reactor pressure vessel welds are examined to meet the uirements of Appendix VIII of ASME Code,Section XI, which has been incorporated into the ance of Regulatory Guide 1.150, as defined in Subsection 1.9.1.

4.3.1 Examination Methods asonic Examination of the Reactor Vessel asonic examination for the RPV is conducted in accordance with the ASME Code,Section XI.

design of the RPV considered the requirements of the ASME Code Section XI with regard to ormance of preservice inspection. For the required preservice examinations, the reactor vessel ts the acceptance standards of Section XI, IWB-3510. The RPV shell welds are designed for 5.2-20 Revision 1

ervice inspection but might have limited areas that may not be accessible from the outer surface nservice examination techniques. If accessibility is limited, an inservice inspection program relief uest is prepared and submitted for review approval by the NRC.

r radius examinations are performed from the outside of the nozzle using several compound le transducer wedges to obtain complete coverage of the required examination volume.

rnatively, nozzle inner radius examinations may be performed using enhanced visual techniques, llowed by 10 CFR 50.55a(b)(2)(xxi).

ual Examination al examination methods VT-1, VT-2 and VT-3 are conducted in accordance with ASME tion XI, IWA-2210. In addition, VT-2 examinations meet the requirements of IWA-5240.

ere direct visual VT-1 examinations are conducted without the use of mirrors or with other viewing

, clearance is provided where feasible for the head and shoulders of a man within a working

's length of the surface to be examined.

face Examination netic particle and liquid penetrant examination techniques are performed in accordance with ME Section XI, IWA-2221 and IWA-2222, respectively. Direct examination access for magnetic icle (MT) and liquid penetrant (PT) examination is the same as that required for direct visual

-1) examination (see Visual Examination), except that additional access is provided as necessary nable physical contact with the item in order to perform the examination. Remote MT and PT erally are not appropriate as a standard examination process; however, boroscopes and mirrors be used at close range to improve the angle of vision.

umetric Ultrasonic Direct Examination metric ultrasonic direct examination is performed in accordance with ASME Section XI,

-2232, which references mandatory Appendix I.

rnative Examination Techniques provided by ASME Section XI, IWA-2240, alternative examination methods, a combination of hods, or newly developed techniques may be substituted for the methods specified for a given in this section, provided that they are demonstrated to be equivalent or superior to the specified hod. This provision allows for the use of newly developed examination methods, techniques, etc.,

ch may result in improvements in examination reliability and reductions in personnel exposure. In ordance with 10 CFR 50.55a(b)(2)(xix), IWA-2240 as written in the 1997 Addenda of ASME tion XI must be used when applying these provisions.

4.3.2 Qualification of Personnel and Examination Systems for Ultrasonic Examination sonnel performing examinations shall be qualified in accordance with ASME Section XI, endix VII. Ultrasonic examination systems shall be qualified in accordance with industry accepted grams for implementation of ASME Section XI, Appendix VIII. Qualification to ASME Section XI, endix VIII, is in compliance with the provisions of 10 CFR 50.55a.

5.2-21 Revision 1

e,Section XI. The interval may be extended by as much as one year so that inspections are current with plant outages. Because 10 CFR 50.55a(g)(4) requires 120-month inspection rvals, Inspection Program B of IWB-2400 must be chosen. The inspection interval is divided into e periods. Period one comprises the first three years of the interval, period two comprises the t four years of the interval, and period three comprises the remaining three years of the inspection rval. Each period can be extended for up to one year to enable an inspection to coincide with a t outage. The adjustment of period end dates shall not alter the rules and requirements for eduling inspection intervals. It is intended that in-service examinations be performed during mal plant outages such as refueling shutdowns or maintenance shutdowns occurring during the ection interval.

4.5 Examination Categories and Requirements examination categories and requirements are established according to Subarticle IWB-2500 and le IWB-2500-1 of the ASME Code,Section XI. Class 1 piping supports will be examined in ordance with ASME Section XI, IWF-2500. Preservice examinations required by design cification and preservice documentation are in accordance with ASME Section III, NB-5280.

ponents exempt from preservice examination are described in ASME Section III, NB-5283.

preservice examinations comply with IWB-2200. The preservice examination is performed once ccordance with ASME XI, IWB-2200, on all of the items selected for inservice examination, with exception of the examinations specifically excluded by ASME Section XI from preservice uirements, such as VT-3 examination of valve body and pump casing internal surfaces (B-L-2 and

-2 examination categories, respectively) and the visual VT-2 examinations for category B-P.

4.6 Evaluation of Examination Results mination results are evaluated according to IWA-3000 and IWB-3000, with flaw indications ording to IWB-3400 and Table IWA-3410-1. Repair procedures, if required, are according to

-4000 of the ASME Code,Section XI.

ponents containing flaws or relevant conditions and accepted for continued service in ordance with the requirements of IWB-3132.4 or IWB-3142.4 are subjected to successive period minations in accordance with the requirements of IWB-2420. Examinations that reveal flaws or vant conditions exceeding Table IWB-3410-1 acceptance standards are extended to include itional examinations in accordance with the requirements of IWB-2430.

4.7 System Leakage and Hydrostatic Pressure Tests tem pressure tests comply with IWA-5000 and IWB-5000 of the ASME Code,Section XI. These em pressure tests are included in the design transients defined in Subsection 3.9.1. This section discusses the transients included in the evaluation of fatigue of Class 1 components due yclic loads.

4.8 Relief Requests specific areas where the applicable ASME Code requirements cannot be met are identified after initial examinations are performed. Should relief requests be required, they will be developed ugh the regulatory process and submitted to the NRC for approval in accordance with CFR 50.55a(a)(3) or 50.55a(g)(5). The relief requests include appropriate justifications and posed alternative inspection methods.

5.2-22 Revision 1

ordance with ASME Section III, NB-5281. Volumetric and surface examinations are performed as cified in ASME Section III, NB-5282. Components described in ASME Section III, NB-5283 are mpt from preservice examination.

4.10 Program Implementation milestones for preservice and inservice inspection program implementation are identified in le 13.4-201.

5 Detection of Leakage Through Reactor Coolant Pressure Boundary reactor coolant pressure boundary (RCPB) leakage detection monitoring provides a means of cting and to the extent practical, identifying the source and quantifying the reactor coolant age. The detection monitors perform the detection and monitoring function in conformance with requirements of General Design Criteria 2 and 30 and the recommendations of Regulatory de 1.45. Leakage detection monitoring is also maintained in support of the use of leak-before-ak criteria for high-energy pipe in containment. See Subsection 3.6.3 for the application of leak-re-break criteria.

kage detection monitoring is accomplished using instrumentation and other components of eral systems. Diverse measurement methods including level, flow, and radioactivity surements are used for leak detection. The equipment classification for each of the systems and ponents used for leak detection is generally determined by the requirements and functions of the em in which it is located. There is no requirement that leak detection and monitoring components afety-related. See Figure 5.2-1 for the leak detection approach. The descriptions of the rumentation and components used for leak detection and monitoring include information on the em.

atisfy position 1 of Regulatory Guide 1.45, reactor coolant pressure boundary leakage is sified as either identified or unidentified leakage. Identified leakage includes:

Leakage from closed systems such as reactor vessel seal or valve leaks that are captured and conducted to a collecting tank Leakage into auxiliary systems and secondary systems (intersystem leakage) (This leakage is considered to be part of the 10 gpm limit identified leakage in the bases of the technical specification 3.4.8. This additional leakage must be considered in the evaluation of the reactor coolant inventory balance.)

er leakage is unidentified leakage.

5.1 Collection and Monitoring of Identified Leakage tified leakage other than intersystem leakage is collected in the reactor coolant drain tank. The tor coolant drain tank is a closed tank located in the reactor cavity in the containment. The tank t is piped to the gaseous radwaste system to prevent release of radioactive gas to the tainment atmosphere. For positions 1 and 7 of Regulatory Guide 1.45, the liquid level in the tor coolant drain tank and total flow pumped out of the reactor coolant drain tank are used to ulate the identified leakage rate. The identified leakage rate is automatically calculated by the t computer. A leak as small as 0.1 gpm can be detected in one hour. The design leak of 10 gpm be detected in less than a minute. These parameters are available in the main control room. The 5.2-23 Revision 1

5.1.1 Valve Stem Leakoff Collection e stem leakoff connections are not provided in the AP1000.

5.1.2 Reactor Head Seal reactor vessel flange and head flange are sealed by two concentric seals. Seal leakage is cted by two leak-off connections: one between the inner and outer seal, and one outside the r seal. These lines are combined in a header before being routed to the reactor coolant drain

. An isolation valve is installed in the common line. During normal plant operation, the leak-off es are aligned so that leakage across the inner seal drains to the reactor coolant drain tank.

rface-mounted resistance temperature detector installed on the bottom of the common reactor sel seal leak pipe provides an indication and high temperature alarm signal in the main control m indicating the possibility of a reactor pressure vessel head seal leak. The temperature detector drain line downstream of the isolation valve are part of the liquid radwaste system.

reactor coolant pump closure flange is sealed with a welded canopy seal and does not require

-off collection provisions.

kage from other flanges is discussed in Subsection 5.2.5.3, Collection and Monitoring of dentified Leakage.

5.1.3 Pressurizer Safety Relief and Automatic Depressurization Valves perature is sensed downstream of each pressurizer safety relief valve and each automatic ressurization valve mounted on the pressurizer by a resistance temperature detector on the harge piping just downstream of each globe valve. High temperature indications (alarms in the n control room) identify a reduction of coolant inventory as a result of seat leakage through one of valves. These detectors are part of the reactor coolant system. This leakage is drained to the tor coolant drain tank during normal plant operation and vented to containment atmosphere or in-containment refueling water storage tank during accident conditions. This identified leakage is sured by the change in level of the reactor coolant drain tank.

5.1.4 Other Leakage Sources e course of plant operation, various minor leaks of the reactor coolant pressure boundary may be cted by operating personnel. If these leaks can be subsequently observed, quantified, and ed to the containment sump, this leakage will be considered identified leakage.

5.2 Intersystem Leakage Detection stantial intersystem leakage from the reactor coolant pressure boundary to other systems is not ected. However, possible leakage points across passive barriers or valves and their detection hods are considered. In accordance with position 4 of Regulatory Guide 1.45, auxiliary systems nected to the reactor coolant pressure boundary incorporate design and administrative provisions limit leakage. Leakage is detected by increasing auxiliary system level, temperature, flow, or sure, by lifting the relief valves or increasing the values of monitored radiation in the auxiliary em.

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sections 5.4.7 and 9.3.6 and the intersystem LOCA discussion in Subsection 1.9.5.1.

5.2.1 Steam Generator Tubes mportant potential identified leakage path for reactor coolant is through the steam generator s into the secondary side of the steam generator. Identified leakage from the steam generator ary side is detected by one, or a combination, of the following:

High condenser air removal discharge radioactivity, as monitored and alarmed by the turbine island vent discharge radiation monitor Steam generator secondary side radioactivity, as monitored and alarmed by the steam generator blowdown radiation monitor Secondary side radioactivity, as monitored and alarmed by the main steam line radiation monitors Radioactivity, boric acid, or conductivity in condensate as indicated by laboratory analysis ails on the radiation monitors are provided in Section 11.5, Radiation Monitoring.

5.2.2 Component Cooling Water System kage from the reactor coolant system to the component cooling water system is detected by high ponent cooling water system radiation, by increasing surge tank level, by high flow downstream elected components, by a high temperature condition at reactor coolant pump bearing water perature RTDs, or by some combination of the preceding. Refer to Section 11.5, Radiation itoring, and Subsection 9.2.2, Component Cooling Water System.

5.2.3 Passive Residual Heat Removal Heat Exchanger Tubes otential identified leakage path for reactor coolant is through the passive residual heat removal t exchanger into the in-containment refueling water storage tank. Identified leakage from the sive residual heat removal heat exchanger tubes is detected as follows:

High temperature in the passive residual heat removal heat exchanger, as monitored and alarmed by temperature detectors in the heat exchanger inlet and outlet piping, alerts the operators to potential leakage. The location of these instruments is selected to provide early indication of leakage considering the potential for thermal stratification. The alarm setpoint is selected to provide early indication of leakage.

The operator then closes the passive residual heat removal heat exchanger inlet isolation valve and observes the pressure indication inside the passive residual heat removal heat exchanger. If pressure remains at reactor coolant system pressure, then tube leakage is not present, and the high passive residual heat removal heat exchanger temperature is indicative of leakage through the outlet isolation valves.

If the operator observes a reduction in pressure, then passive residual heat removal heat exchanger tube leakage is present. The operator then observes the change in the reactor coolant system inventory balance when the passive residual heat removal heat exchanger 5.2-25 Revision 1

5.3 Collection and Monitoring of Unidentified Leakage ition 3 of Regulator Guide 1.45 identifies three diverse methods of detecting unidentified leakage.

000 use two of these three and adds a third method. To detect unidentified leakage inside tainment, the following diverse methods may be utilized to quantify and assist in locating the age:

Containment Sump Level Reactor Coolant System Inventory Balance Containment Atmosphere Radiation er methods that can be employed to supplement the above methods include:

Containment Atmosphere Pressure, Temperature, and Humidity Containment Water Level Visual Inspection reactor coolant system is an all-welded system, except for the connections on the pressurizer ty valves, reactor vessel head, explosively actuated fourth stage automatic depressurization em valves, pressurizer and steam generator manways, and reactor vessel head vent, which are ged. During normal operation, variations in airborne radioactivity, containment pressure, perature, or specific humidity above the normal level signify a possible increase in unidentified age rates and alert the plant operators that corrective action may be required. Similarly, eases in containment sump level signify an increase in unidentified leakage. The following ions outline the methods used to collect and monitor unidentified leakage.

se methods also allow for identification of main steam line leakage inside containment. The ary method of identifying steam line leakage is redundant containment sump level monitoring. A rse backup method is provided by containment water level monitoring. The safety-related s 1E containment water level sensors use a different measuring process than the containment p level sensors.

5.3.1 Containment Sump Level Monitor onformance with position 2 of Regulatory Guide 1.45, leakage from the reactor coolant pressure ndary and other components not otherwise identified inside the containment will condense and by gravity via the floor drains and other drains to the containment sump.

ak in the primary system would result in reactor coolant flowing into the containment sump.

kage is indicated by an increase in the sump level. The containment sump level is monitored by e seismic Category I level sensors. Position 6 of Regulatory Guide 1.45 requires two sensors.

third sensor is provided for redundancy in detecting main steam line leakage. The level sensors powered from a safety-related Class 1E electrical source. These sensors remain functional when jected to a safe shutdown earthquake in conformance with the guidance in Regulatory de 1.45. The containment sump level and sump total flow sensors located on the discharge of the p pump are part of the liquid radwaste system.

5.2-26 Revision 1

any given measurement period exceeds 0.5 gpm for unidentified leakage. The minimum ctable leak is 0.03 gpm. Unidentified leakage is the total leakage minus the identified leakage.

leakage rate algorithm subtracts the identified leakage directed to the sump.

atisfy positions 2 and 5 of Regulatory Guide 1.45, the measurement interval must be long ugh to permit the measurement loop to adequately detect the increase in level that would espond to 0.5 gpm leak rate, and yet short enough to ensure that such a leak rate is detected in an hour. The measurement interval is less than or equal to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

en the sump level increases to the high level setpoint, one of the sump pumps automatically starts ump the accumulated liquid to the waste holdup tanks in the liquid radwaste system. The sump harge flow is integrated and available for display in the control room, in accordance with ition 7 of Regulatory Guide 1.45.

cedures to identify the leakage source upon a change in the unidentified leakage rate into the p include the following:

Check for changes in containment atmosphere radiation monitor indications, Check for changes in containment humidity, pressure, and temperature, Check makeup rate to the reactor coolant system for abnormal increases, Perform an RCS inventory balance, Check for changes in water levels and other parameters in systems which could leak water into the containment, and Review records for maintenance operations which may have discharged water into the containment.

procedure allows identification of main steam line leakage as well as RCS leakage.

5.3.2 Reactor Coolant System Inventory Balance ctor coolant system inventory monitoring provides an indication of system leakage. Net level nge in the pressurizer is indicative of system leakage. Monitoring net makeup from the chemical volume control system and net collected leakage provides an important method of obtaining rmation to establish a water inventory balance. An abnormal increase in makeup water uirements or a significant change in the water inventory balance can indicate increased system age.

reactor coolant system inventory balance is a quantitative inventory or mass balance calculation.

approach allows determination of both the type and magnitude of leakage. Steady-state ration is required to perform a proper inventory balance calculation. Steady-state is defined as le reactor coolant system pressure, temperature, power level, pressurizer level, and reactor lant drain tank and in-containment refueling water storage tank levels. The reactor coolant ntory balance is done on a periodic basis and when other indication and detection methods cate a change in the leak rate. The minimum detectable leak is 0.13 gpm.

5.2-27 Revision 1

pressurizer. Compensation is provided for changes in plant conditions which affect water density.

change in the inventory determines the total reactor coolant system leak rate. Identified leakages monitored (using the reactor coolant drain tank) to calculate a leakage rate and by monitoring the rsystem leakage. The unidentified leakage rate is then calculated by subtracting the identified age rate from the total reactor coolant system leakage rate.

e the pressurizer inventory is controlled during normal plant operation through the level control em, the level in the pressurizer will be reasonably constant even if leakage exists. The mass tained in the pressurizer may fluctuate sufficiently, however, to have a significant effect on the ulated leak rate. The pressurizer mass calculation includes both the steam and water mass tributions.

nges in the reactor coolant system mass inventory are a result of changes in liquid density. Liquid sity is a strong function of temperature and a lesser function of pressure. A range of temperatures ts throughout the reactor coolant system all of which may vary over time. A simplified, but eptably accurate, model for determining mass changes is to assume all of the reactor coolant em is at TAverage.

inventory balance calculation is done by the data display and processing system with additional t from sensors in the protection and safety monitoring system, chemical and volume control em, and liquid radwaste system. The use of components and sensors in systems required for t operation provides conformance with the regulatory guidance of position 6 in Regulatory de 1.45 that leak detection should be provided following seismic events that do not require plant tdown.

5.3.3 Containment Atmosphere Radioactivity Monitor kage from the reactor coolant pressure boundary will result in an increase in the radioactivity ls inside containment. The containment atmosphere is continuously monitored for airborne iculate radioactivity. Air flow through the monitor is provided by the suction created by a vacuum

p. An F18 particulate concentration monitor indicates radiation concentrations in the containment osphere.

particulate is a neutron activated product, which is proportional to power levels. An increase in vity inside containment would, therefore, indicate a leakage from the reactor coolant pressure ndary. Based on the concentration of F18 in particulate form and the power level, reactor coolant sure boundary leakage can be estimated.

F18 particulate monitor is seismic Category I. Conformance with the position 6 guidance of ulatory Guide 1.45 that leak detection should be provided following seismic events that do not uire plant shutdown is provided by the seismic Category I classification. Safety-related Class 1E er is not required since loss of power to the radiation monitor is not consistent with continuing ration following an earthquake.

F18 particulate monitor is operable when the plant is above 20-percent power, and can detect a gpm leak within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> when the plant is at full power.

ioactivity concentration indication and alarms for loss of sample flow, high radiation, and loss of cation are provided. Sample collection connections permit sample collection for laboratory lysis. The radiation monitor can be calibrated during power operation.

5.2-28 Revision 1

idity, values available to the operator through the plant control system.

ncrease in containment pressure is an indication of increased leakage or a high energy line ak. Containment pressure is monitored by redundant Class 1E pressure transmitters. For itional discussion see Subsection 6.2.2, Passive Containment Cooling System.

containment average temperature is monitored using temperature instrumentation at the inlet to containment fan cooler as an indication of increased leakage or a high energy line break. This rumentation as well as temperature instruments within specific areas, including steam generator as, pressurizer area, and containment compartments, are part of the containment recirculation ling system.

ncrease in the containment average temperature combined with an increase in containment sure indicate increased leakage or a high energy line break. The individual compartment area peratures can assist in identifying the location of the leak.

tainment humidity is monitored using temperature-compensated humidity detectors which rmine the water-vapor content of the containment atmosphere. An increase in the containment osphere humidity indicates release of water vapor within the containment. The containment idity monitors are part of the containment leak rate test system.

humidity monitors supplement the containment sump level monitors and are most sensitive er conditions when there is no condensation. A rapid increase of humidity over the ambient value more than 10 percent is indication of a probable leak.

tainment pressure, temperature and humidity can assist in identifying and locating a leak. They not relied on to quantify a leak.

5.3.5 Response to Reactor Coolant System Leakage rating procedures specify operator actions in response to prolonged low level unidentified reactor lant leakage conditions that exist above normal leakage rates and below the Technical cification (TS) limits to provide operators sufficient time to take action before the TS limit is hed. The procedures include identifying, monitoring, trending, and addressing prolonged low l leakage. The procedures for effective management of leakage, including low level leakage, are eloped including the following operations related activities:

Trends in the unidentified leakage rates are periodically analyzed. When the leakage rate increases noticeably from the baseline leakage rate, the safety significance of the leak is evaluated. The rate of increase in the leakage is determined to verify that plant actions can be taken before the plant exceeds TS limits.

Procedures are established for responding to leakage. These procedures address the following considerations to prevent adverse safety consequence results from the leakage:

- Plant procedures specify operator actions in response to leakage rates less than the limits set forth in the Technical Specifications. The procedures include actions for confirming the existence of a leak, identifying its source, increasing the frequency of monitoring, verifying the leakage rate (through a water inventory balance), responding to trends in the leakage rate, performing a walkdown outside containment, planning a 5.2-29 Revision 1

- Plant procedures specify the amount of time the leakage detection and monitoring instruments (other than those required by Technical Specifications) may be out of service to effectively monitor the leakage rate during plant operation (i.e., hot shutdown, hot standby, startup, transients, and power operation).

The output and alarms from leakage monitoring systems are provided in the main control room. Procedures are readily available to the operators for converting the instrument output to a common leakage rate. (Alternatively, these procedures may be part of a computer program so that the operators have a real-time indication of the leakage rate as determined from the output of these monitors.) Periodic calibration and testing of leakage monitoring systems are conducted. The alarm(s), and associated setpoint(s), provide operators an early warning signal so that they can take corrective actions, as discussed above, i.e., before the plant exceeds TS limits.

During maintenance and refueling outages, actions are taken to identify the source of any unidentified leakage that was detected during plant operation. In addition, corrective action is taken to eliminate the condition resulting in the leakage.

procedures described above will be available prior to fuel load.

5.4 Safety Evaluation k detection monitoring has no safety-related function. Therefore, the single failure criterion does apply and there is no requirement for a nuclear safety evaluation. The containment sump level itors and the containment atmosphere monitor are seismic Category I. The components used to ulate reactor coolant system inventory balance are both safety-related and nonsafety-related ponents. The containment sump level monitors are powered from the Class 1E dc and UPS em (IDS). Measurement signals are processed by the data display and processing system and plant control system (PLS).

5.5 Tests and Inspections atisfy position 8 of Regulatory Guide 1.45, periodic testing of leakage detection monitors verifies operability and sensitivity of detector equipment. These tests include installation calibrations and nments, periodic channel calibrations, functional tests, and channel checks in conformance with ulatory guidance.

5.6 Instrumentation Applications parameters tabulated below satisfy position 7 of Regulatory Guide 1.45 and are provided in the n control room to allow operating personnel to monitor for indications of reactor coolant pressure ndary leakage. The containment sump level, containment atmosphere radioactivity, reactor lant system inventory balance, and the flow measurements are provided as gallon per minute age equivalent.

5.2-30 Revision 1

actor coolant drain tank level and drain tank total flow WLS Both ntainment atmosphere radioactivity PSS Both actor coolant system inventory balance parameters CVS, PCS, PXS, Both RCS, WLS ntainment humidity VUS Indication ntainment atmospheric pressure PCS Both ntainment atmosphere temperature VCS Both ntainment water level PXS Both(1) actor vessel head seal leak temperature WLS Both ssurizer safety relief valve leakage temperature RCS Both actor coolant pump bearing water RTDs RCS Both am generator blowdown radiation BDS Both bine island vent discharge radiation TDS Both mponent cooling water radiation CCS Both in steam line radiation SGS Both mponent cooling water surge tank level CCS Both e:

The containment water level instruments provide indication and alarm for identification of a 0.5 gpm leak within 3.5 days.

5.7 Technical Specification its which satisfy position 9 of Regulatory Guide 1.45 for identified and unidentified reactor coolant age are identified in the technical specifications, Chapter 16. LCO 3.4.7 addresses RCS leakage

s. LCO 3.7.8 addresses main steam line leakage limits. LCO 3.4.9 addresses leak detection rument requirements.

6 Combined License Information Items 6.1 ASME Code and Addenda ASME Code editions and addenda to be used are addressed in Subsection 5.2.1.1.

6.2 Plant-Specific Inspection Program plant-specific preservice inspection and inservice inspection program is addressed in sections 5.2.4, 5.2.4.1, 5.2.4.3.1, 5.2.4.3.2, 5.2.4.4, 5.2.4.5, 5.2.4.6, 5.2.4.8, 5.2.4.9, and 4.10.

5.2-31 Revision 1

onged low-level unidentified reactor coolant leakage inside containment is addressed in section 5.2.5.3.5.

7 References Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary),

and WCAP-7907-A (Nonproprietary), April 1984.

EPRI PWR Safety and Relief Valve Test Program, Safety and Relief Valve Test Report, Interim Report, April 1982.

Logsdon, W. A., Begley, J. A., and Gottshall, C. L., "Dynamic Fracture Toughness of ASME SA-508 Class 2a and ASME SA-533 Grade A Class 2 Base and Heat-Affected Zone Material and Applicable Weld Metals," WCAP-9292, March 1978.

Golik, M. A., "Sensitized Stainless Steel in Westinghouse PWR Nuclear Steam Supply Systems," WCAP-7477-L (Proprietary), March 1970, and WCAP-7735 (Nonproprietary),

August 1971.

Enrietto, J. F., "Control of Delta Ferrite in Austenitic Stainless Steel Weldments,"

WCAP-8324-A, June 1975.

Enrietto, J. F., "Delta Ferrite in Production Austenitic Stainless Steel Weldments,"

WCAP-8693, January 1976.

. EPRI, Pressurized Water Reactor Primary Water Chemistry Guidelines, EPRI TR-1002884, Revision 5, October 2003.

5.2-32 Revision 1

Component Material Class, Grade, or Type actor Vessel Components ad plates (other than core region) SA-533 Type B, CL 1 or or SA-508 GR 3 CL 1 ell courses SA-508 GR 3 CL 1 ell, flange, and nozzle forgings SA-508 GR 3 CL 1 zzle safe ends SA-182 F316, F316L, F316LN purtenances to the control rod drive SB-167 N06690 chanism (CRDM)

SB-166 N06690 or or SA-182 F304, F304L, F304LN, F316, F316L, F316LN trumentation nozzles, upper head SB-167 N06690 SB-166 N06690 and and SA-182, F304, F304L, F304LN, F316, F316L, F316LN or SA-479 304, 304L, 304LN 316, 316L, 316LN, S21800 sure studs SA-540 GR B23 CL 3 or GR B24 CL 3 nitor tubes SA-312(1) TP304, TP304L, TP304LN, TP316, TP316L, TP316LN or SA-376 TP304, TP304LN, TP316, TP316LN or SA-182 F304, F304L, F304LN, F316, F316L, F316LN 5.2-33 Revision 1

Component Material Class, Grade, or Type nt pipe SB-166 N06690 SB-167 N06690 or SA-312(1) TP304, TP304L, TP304LN, TP316, TP316L, TP316LN SA-376 TP304, TP304LN, TP316, TP316LN am Generator Components ssure plates SA-533 Type B, CL 1 or CL 2 ssure forgings (including primary side nozzles SA-508 GR 3, CL 2 d tube sheet) zzle safe ends SA-182 F316, F316L, F316LN SA-336 F316LN or SB-564 N06690 annel heads SA-508 GR 3, CL 2 bes SB-163 N06690 nway studs/ SA-193 GR B7 ts SA-194 GR 7 ssurizer Components ssure plates SA-533 Type B, CL 1 ssure forgings SA-508 GR 3, CL 2 zzle safe ends SA-182 F316, F316L, F316LN SA-336 F316, F316L, F316LN or SB-163 N06690 nway studs/ SA-193 GR B7 ts SA-194 GR 7 5.2-34 Revision 1

Component Material Class, Grade, or Type actor Coolant Pump ssure forgings SA-182 F304, F304L, F304LN, F316, F316L, F316LN SA-508 GR1(4) or SA-336 F304, F304L, F304LN, F316, F316L, F316LN ssure casting SA-351 CF3A or CF8A be and pipe SA-213 TP304, TP304L, TP304LN, TP316, TP316L, TP316LN SA-376 TP304, TP304LN, TP316, TP316LN or SA-312(1) TP304, TP304L, TP304LN, TP316, TP316L, TP316LN ssure plates SA-240 304, 304L, 304LN, 316, 316L, 316LN sure bolting SA-193 GR B7 or or SA-540 GR B24, CL 2 & CL 4, or GR B23, CL2, CL 3 & 4 actor Coolant Piping actor coolant pipe SA-376 TP304, TP304LN, TP316, TP316LN SA-182(2) F304, F304L, F304LN, F316, F316L, F316LN actor coolant fittings, branch nozzles SA-376 TP304, TP304LN, TP316, TP316LN SA-182 F304, F304L, 304LN, F316, F316L, F316LN rge line SA-376 TP304, TP304LN, TP316, TP316LN or SA-312(1) TP304, TP304L, TP304LN, TP316, TP316L, TP316LN 5.2-35 Revision 1

Component Material Class, Grade, or Type P piping other than loop and surge line SA-312(1) TP304, TP304L, TP304LN, TP316, TP316L, TP316LN and SA-376 TP304, TP304L, TP304LN, TP316, TP316L, TP316LN DM ch housing SA-336 F304, F304L, F304LN, F316, F316L, F316LN d travel housing SA-336 F304, F304L, F304LN, F316, F316L, F316LN lves dies SA-182 F304, F304L, F304LN, F316, F316L, F316LN or or SA-351 CF3A, CF3M, CF8 nnets SA-182 F304, F304L, F304LN, F316, F316L, F316LN, SA-240 304, 304L, 304LN, 316, 316L, 316LN or or SA-351 CF3A, CF3M, CF8 cs SA-182 F304, F304L, F304LN, F316, F316L, F316LN SA-564 Type 630 (H1100 or H1150),

or or SA-351 CF3A, CF3M, CF8 ms SA-479 316, 316LN or XM-19 SA-564 Type 630 (H1100 or H1150) or SB-637 Alloy N07718 ssure retaining bolting SA-453 GR 660 SA-564 Type 630 (H1100)

SA-193 GR B8 5.2-36 Revision 1

Component Material Class, Grade, or Type ssure retaining nuts SA-453 GR 660 or or SA-194 GR 6 or 8 re Makeup Tank ssure plates SA-533 Type B, CL 1 or or SA-240 304, 304L, 304LN, 316, 316L, 316LN ssure forgings SA-508 GR 3 CL 1 or or SA-182 F304, F304L, F316, F316L SA-336 F304, F304L, F316, F316L ssive Residual Heat Removal Heat Exchanger ssure plates SA-533 Type B CL1 or or SA-240 304, 304L, 304LN ssure forgings SA-508 GR 3 CL 2 or or SA-336 F304, F304L, F304LN bing SB-163 N06690 lding Consumables stenitic stainless steel corrosion-resistant SFA 5.4 E308, E308L, E309, E309L, E316, dding, buttering, and welds(5) E316L SFA 5.9(6) ER308, ER308L, ER309, ER309L, ER316, ER316L, EQ308L, EQ309L SFA 5.22(3) E308LTX-Y, E308TX-Y, E309LTX-Y, E309TX-Y, E316LTX-Y, E316TX-Y SFA 5.30 IN308, IN308L, IN316, IN316L 5.2-37 Revision 1

Component Material Class, Grade, or Type Cr-Fe corrosion-resistant cladding, buttering, and SFA 5.11 ENiCrFe-7 lds(7)

SFA 5.14 ERNiCrFe-7, ERNiCrFe-7A, EQNiCrFe-7, EQNiCrFe-7A rbon steel pressure boundary welds(8)(4) SFA 5.1, 5.17, 5.18, To be compatible with base 5.20, 5.30 material w alloy pressure boundary welds(8) SFA 5.5, 5.23, 5.28, To be compatible with base 5.29 material es:

Limited to seamless form only.

Subject to manufacturing sequence and final finish condition review.

Only gas-shielded electrodes for use with the FCAW process are permitted. These electrodes shall not be used for root passes except for joints welded from two sides where the root is back-gouged to sound metal as evidenced by magnetic particle or liquid penetrant testing.

X=Position, acceptable values 0 (flat and horizontal) and 1 (all positions)

Y=Shield Gas, acceptable values 1 (100% CO2) and 4 (75-80% Argon, remainder CO2)

GR1 material (carbon steel) and associated filler material is used only for reactor coolant pump components that are not exposed to the reactor coolant. These components are limited to the stator main flange, stator shell, and external heat exchanger supports.

Austenitic stainless steel filler metals that are exposed to temperatures within the 800°F to 1500°F temperature range after welding, and are not subsequently solution annealed, do not contain more than 0.03% or 0.04% carbon by weight (depending on the maximum carbon content of the corresponding low-carbon classification in the SFA specification), or have demonstrated nonsensitization per Regulatory Guide 1.44.

In addition to ER, EC (composite) rod/electrodes may also be used.

These materials are UNS N06052, N06054, and W86152, where F43 grouping is allowed by codes cases 2143-1 and 2142-2. Note that UNS N06054 is only in ASME Section II part C 2004 with 2006 addenda and later. Similar welding alloys developed for improved weldability may be used as allowed by ASME Boiler and Pressure Vessel Code rules.

These weld metals are compatible with the base metal mechanical requirements and meet applicable ASME Section III, Section II part C, and Section IX requirements. Their use is limited to applications in which the welds are not exposed to reactor coolant. These weld metals used with a flux bearing welding process are also not used for root passes of single-sided welds.

5.2-38 Revision 1

trical conductivity Determined by the concentration of boric acid and alkali present.

Expected range is <1 to 40 mhos/cm at 25°C.

tion pH Determined by the concentration of boric acid and alkali present.

Expected values range between 4.2 (high boric acid concentration) and 10.5 (low boric acid concentration) at 25°C. Values will be 5.0 or greater at normal operating temperatures.

gen(1) 0.1 ppm, maximum ride(2) 0.15 ppm, maximum ride(2) 0.15 ppm, maximum rogen(3) 25 to 50 cm3 (STP)/kg H2O pended solids(4) 0.2 ppm, maximum ontrol agent (Li7OH)(5) Lithium is coordinated with boron per fuel warranty contract.

c acid Variable from 0 to 4000 ppm as boron a(6) 1.0 ppm, maximum inum(6) 0.05 ppm, maximum ium(6) + magnesium 0.05 ppm, maximum nesium(6) 0.025 ppm, maximum (7) 0.04 ppm, maximum s:

Oxygen concentration must be controlled to less than 0.1 ppm in the reactor coolant by scavenging with hydrazine prior to plant operation above 200°F. During power operation with the specified hydrogen concentration maintained in the coolant, the residual oxygen concentration will not exceed 0.005 ppm.

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

Hydrogen must be maintained in the reactor coolant for plant operations with nuclear power above 1 MW. The normal operating range should be 30-40 cm3 (STP) H2/kg H2O.

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

The specified lithium concentrations must be established for startup testing prior to heatup beyond 150°F. During cold hydrostatic testing and hot functional testing in the absence of boric acid, the reactor coolant limits for lithium hydroxide must be maintained to inhibit halogen stress corrosion cracking.

These limits are included in the table of reactor coolant specifications as recommended standards for monitoring coolant purity.

Establishing coolant purity within the limits shown for these species is judged desirable with the current data base to minimize fuel clad crud deposition, which affects the corrosion resistance and heat transfer of the clad.

Specification is applicable during power operation when zinc is being injected. The zinc concentration is maintained at the lower of 0.04 ppm or that specified in the reload safety analyses.

5.2-39 Revision 1

Code Case Number Title 4-11 Special Type 403 Modified Forgings or Bars,Section III, Division 1, Class 1 and Class CS 20-4 SB-163 Nickel-Chromium-Iron Tubing (Alloys 600 and 690) and Nickel-Iron-Chromium Alloy 800 at a Specified Minimum Yield Strength of 40.0 ksi and Cold Worked Alloy 800 at Yield Strength of 47.0 ksi,Section III, Division 1, Class 1 60-5 Material for Core Support Structures,Section III, Division 1(a) 71-18 Additional Material for Subsection NF, Class 1, 2, 3 and MC Component Supports Fabricated by Welding,Section III Division 1

-122-2 Stress Indices for integral Structural AttachmentsSection III, Division 1, Class 1]*

249-14 Additional Materials for Subsection NF, Class 1, 2, 3, and MC Supports Fabricated Without Welding,Section III, Division 1(b)

-284-1 Metal Containment Shell Buckling Design Methods,Section III, Division 1 Class MC]*

-318-5 Procedure for Evaluation of the Design of Rectangular Cross Section Attachments on Class 2 or 3 Piping Section III, Division]*

-319-3 Alternate Procedure for Evaluation of Stresses in Butt Welding Elbows in Class 1 Piping Section III, Division 1]*

-391-2 Procedure for Evaluation of the Design of Hollow Circular Cross Section Welded Attachments on Class 1 Piping Section III, Division 1]*

-392-3 Procedure for Valuation of the Design of Hollow Circular Cross Section Welded Attachments on Class 2 and 3 Piping Section III, Division 1(c) ]*

474-2 Design Stress Intensities and Yield Strength Values for UNS06690 With a Minimum Yield Strength of 35 ksi, Class 1 Components,Section III, Division 1 42-2 F-Number Grouping for Ni-Cr-Fe Filler Metals,Section IX (Applicable to all Sections, including Section III, Division 1, and Section XI) 43-1 F-Number Grouping for Ni-Cr-Fe, Classification UNS W86152 Welding Electrode,Section IX 655-1 Use of SA-738, Grade B, for Metal Containment Vessels, Class MC,Section III, Division 1 757-1 Alternative Rules for Acceptability for Class 2 and 3 Valves, NPS 1 (DN25) and Smaller with Welded and Nonwelded End Connections other than Flanges,Section III, Division 1(d) 759-2 Alternative Rules for Determining Allowable External Pressure and Compressive Stresses for Cylinders, Cones, Spheres, and Formed Heads, Class 1, 2, and 3,Section III, Division 1 782 Use of Code Editions, Addenda, and CasesSection III, Division 1 tes:

Use of this code case will meet the conditions for Code Case N-60-4 in Reg. Guide 1.85 Revision 30.

Use of this code case will meet the conditions for Code Case N-249-10 in Reg. Guide 1.85 Revision 30.

Use of this code case will meet the conditions for Code Case N-392-1 in Reg. Guide 1.84 Revision 30.

Use of this code case is subject to the condition that the design provisions of ASME Code,Section III, Division I, Appendix XIII not be used for the design of Code Class 3 (ND) valves.

Staff approval is required prior to implementing a change in this information.

5.2-40 Revision 1

Figure 5.2-1 Leak Detection Approach 5.2-41 Revision 1

1.1 Safety Design Bases reactor vessel, as an integral part of the reactor coolant pressure boundary will be designed, icated, erected and tested to quality standards commensurate with the requirements set forth in CFR 50, 50.55a and General Design Criterion 1. Design and fabrication of the reactor vessel is ied out in accordance with ASME Code,Section III, Class 1 requirements. Subsections 5.2.3 5.3.2 provide further details.

performance and safety design bases of the reactor vessel follow:

The reactor vessel provides a high integrity pressure boundary to contain the reactor coolant, heat generating reactor core, and fuel fission products. The reactor vessel is the primary pressure boundary for the reactor coolant and the secondary barrier against the release of radioactive fission products.

The reactor vessel provides support for the reactor internals, flow skirt, and core to ensure that the core remains in a coolable configuration.

The reactor vessel directs main coolant flow through the core by close interface with the reactor internals and flow skirt.

The reactor vessel provides for core internals location and alignment.

The reactor vessel provides support and alignment for the control rod drive mechanisms and in-core instrumentation assemblies.

The reactor vessel provides support and alignment for the integrated head assembly.

The reactor vessel provides an effective seal between the refueling cavity and sump during refueling operations.

The reactor vessel supports and locates the main coolant loop piping.

The reactor vessel provides support for safety injection flow paths.

The reactor vessel serves as a heat exchanger during core meltdown scenario with water on the outside surface of the vessel.

1.2 Safety Description reactor vessel consists of a cylindrical section with a transition ring, hemispherical bottom head, a removable flanged hemispherical upper head (Figure 5.3-1). Key dimensions are shown in res 5.3-5 and 5.3-6. The cylindrical section consists of two shells, the upper shell and the lower ll. The upper and lower shells and the lower hemispherical head are fabricated from low alloy l and clad with austenitic stainless steel. The upper shell forging is welded to the lower shell ing, and the lower shell is welded to the transition ring, which is welded to the hemispherical om head. The removable flanged hemispherical upper head consists of a single forging, which udes the closure head flange and the closure head dome. The closure head is fabricated from a alloy steel forging and clad with austenitic stainless steel. Specifics of the processes used in base erials, clad material, and weld materials are discussed in Subsection 5.2.3. The removable 5.3-1 Revision 1

age past the o-rings. Details of the head gasket monitoring connections are included in section 5.2.5.2.1.

reactor vessel supports the internals. An internal ledge is machined into the top of the upper ll section. The core barrel flange rests on the ledge. A large circumferential spring is positioned on top surface of the core barrel flange. The upper support plate rests on the top surface of the ng. The spring is compressed by installation of the reactor vessel closure head and the upper and er core support assemblies are restrained from any axial movements.

r core support pads are located on the bottom hemispherical head just below the transition ring-wer shell circumferential weld. The core support pads function as a clevis. At assembly, as the er internals are lowered into the vessel, the keys at the bottom of the lower internals engage the is in the axial direction. With this design, the internals are provided with a lateral support at the hest extremity and may be viewed as a beam supported at the top and bottom.

interfaces between the reactor vessel and the lower internals core barrel are such that the main lant flow enters through the inlet nozzle and is directed down through the annulus between the tor vessel and core barrel and through the flow skirt and flows up through the core. The annulus esigned such that the core remains in a coolable configuration for all design conditions.

r to installation of the internals into the reactor vessel, guide studs are assembled into the upper ll. Dimensional relationships are established between the guide studs and the core support pads h that when the lower internals lifting rig engages the guide studs, the keys at the bottom of the er internals are in relative circumferential position to enter the core support pads.

re are 69 penetrations in the removable flanged hemispherical head (closure head) that are used rovide access for the control rod drive mechanisms. Each control rod drive mechanism is itioned in its opening and welded to the closure head penetration. In addition there are eight etrations in the closure head used to provide access for in-core and core exit instrumentation.

s are welded to the outside surface of the closure head along the outer periphery of the dome ion. The purpose of these lugs is to provide support and alignment for the integrated head kage.

ched to the top surface and along the outer periphery of the upper shell is a ring section. During assembly the ring is welded to the refueling cavity seal liner. This ring provides an effective er seal between the refueling cavity and sump during refueling operations.

pport pad is integral to each of the four inlet nozzles. The reactor vessel is supported by the

s. The pads rest on steel base pads atop a support structure, which is attached to the concrete dation wall. Thermal expansion and contraction of the vessel are accommodated by sliding aces between the support pads and the base plates. Side stops on these plates keep the vessel tered and resist lateral loads.

reactor vessel primary and direct vessel injection (DVI) nozzles are located in the upper shell.

se nozzles are either forged as part of the upper shell forging or are fabricated by set in struction such that the welding is through the vessel shell forging. A stainless steel safe end is p welded to each of the four inlet, two outlet and two DVI nozzles to facilitate field welding without t treatment to the stainless steel reactor coolant piping system. The primary coolant nozzles port one end of the primary coolant system. Reaction loads are transferred into the nozzles and 5.3-2 Revision 1

re are no penetrations in the reactor vessel below the core. This eliminates the possibility of a

-of-coolant accident by leakage from the reactor vessel that would allow the core to be overed.

1.3 System Safety Evaluation reactor vessel is part of the reactor coolant system. Load and stress evaluation for operating s and mechanical transients of safe shutdown earthquake (SSE), and pipe ruptures appear in section 3.9.3.

1.4 Inservice Inspection/Inservice Testing rvice surveillance is discussed in Subsection 5.3.4.7.

2 Reactor Vessel Materials 2.1 Material Specifications erial specifications are in accordance with the ASME Code requirements and are given in section 5.2.3. All ferritic reactor vessel materials comply with the fracture toughness uirements of Section 50.55a and Appendices G and H of 10 CFR 50.

ferritic materials of the reactor vessel beltline are restricted to the maximum limits shown in le 5.3-1. Copper, nickel, and phosphorus content is restricted to reduce sensitivity to irradiation rittlement in service.

2.2 Special Processes Used for Manufacturing and Fabrication reactor vessel is classified as AP1000 Class A. Design and fabrication of the reactor vessel is ied out in accordance with ASME Code,Section III, Class 1 requirements. The shell sections, ge, and nozzles are manufactured as forgings. The hemispherical heads are made from dished es or forgings. The reactor vessel parts are joined by welding, using the single or multiple wire merged arc and the shielded metal arc processes. Gas metal arc welding and plasma arc welding acceptable methods of applying buttering for dissimilar metal welds.

use of severely sensitized stainless steel as a pressure boundary material is prohibited and is inated by either a select choice of material or by programming the method of assembly.

cations in the reactor vessel where stainless steel and nickel-chromium-iron alloy are joined, the l joining beads are nickel-chromium-iron alloy weld metal in order to prevent cracking.

location of full penetration weld seams in the upper closure head and vessel bottom head are ricted to areas that permit accessibility during in-service inspection.

stainless steel clad surfaces are sampled to demonstrate that composition requirements are edom from underclad cracking is provided by special evaluation of the procedure qualification for ding applied on low-alloy steel (SA-508, GR 3 CL 1).

5.3-3 Revision 1

ld weld is made, after the reactor vessel has been set, to install the permanent reactor vessel ty seal ring. This stainless steel filler weld joins the seal ring to the reactor vessel seal ledge. A imum preheat is specified for this weld in compliance with the ASME Code requirements.

flow skirt is also welded to support lugs in the field after the reactor vessel/internals system is 2.3 Special Methods for Nondestructive Examination nondestructive examination (NDE) of the reactor vessel and its appurtenances is conducted in ordance with ASME Code,Section III requirements; also, numerous examinations are performed ddition to ASME Code,Section III requirements. The nondestructive examination of the vessel is ussed in the following paragraphs, and the reactor vessel quality assurance program is given in le 5.3-2.

2.3.1 Ultrasonic Examination ddition to the required ASME Code straight beam ultrasonic examination, angle beam inspection r 100 percent of one major surface of plate material is performed during fabrication to detect ontinuities that may be undetected by the straight beam examination.

ddition to the ASME Code,Section III nondestructive examination, full penetration ferritic sure boundary welds in the reactor vessel are ultrasonically examined during fabrication. This is performed upon completion of the welding and intermediate heat treatment but prior to the final tweld heat treatment.

r hydrotesting, full penetration ferritic pressure boundary welds in the reactor vessel, as well as nozzle to safe end welds, are ultrasonically examined. These inspections are performed in ition to the ASME Code,Section III nondestructive examination requirements.

2.3.2 Penetrant Examinations partial penetration welds for the control rod drive mechanism head adapters and the QuickLoc emblies are inspected by dye penetrant after the root pass, in addition to ASME code uirements. Core support block attachment welds are inspected by dye penetrant after the first r of weld metal and after each 0.5 inch of weld metal. Clad surfaces and other vessel and head rnal surfaces are inspected by dye penetrant after the hydrostatic test.

2.3.3 Magnetic Particle Examination netic particle examination requirements below are in addition to the magnetic particle mination requirements of Section III of the ASME Code. All magnetic particle examinations of erials and welds are performed in accordance with the following:

Prior to the final postweld heat treatment, only by the prod, coil, or direct contact method After the final postweld heat treatment, only by the yoke method following surfaces and welds are examined by magnetic particle methods. The acceptance dards are in accordance with Section III of the ASME Code.

5.3-4 Revision 1

Magnetic particle examination of exterior closure stud surfaces and all nut surfaces after final machining or rolling. Continuous circular and longitudinal magnetization is used.

Magnetic particle examination of inside diameter surfaces of carbon and low alloy steel products that have their properties enhanced by accelerated cooling. This inspection is performed after forming and machining and prior to cladding.

d Examination netic particle examination of the welds attaching the closure head lifting lugs and refueling seal e to the reactor vessel after the first layer and each 0.5 inch of weld metal is deposited. All sure boundary welds are examined after back-chipping or back-grinding operations.

2.4 Special Controls for Ferritic and Austenitic Stainless Steels ding of ferritic steels and austenitic stainless steels is discussed in Subsection 5.2.3.

section 5.2.3 includes discussions on the degree of conformance with Regulatory Guide 1.44.

tion 1.9 discusses the degree of conformance with Regulatory Guides, including 1.31 and 1.34 (if licable), as well as 1.37, 1.43, 1.50, 1.71, and 1.99.

2.5 Fracture Toughness 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 hness testing included in NB-2300 to Section III of the ASME Code and Appendix G of CFR 50.

initial Charpy V-notch minimum upper shelf fracture energy levels for the reactor vessel beltline e metal transverse direction and welds are 75 foot-pounds, as required by Appendix G of CFR 50. The vessel fracture toughness data are given in Table 5.3-3. The AP1000 end-of-life DT and upper shelf energy projections were estimated using Regulatory Guide 1.99 for the

-of-life neutron fluence at the 1/4-thickness (T) and ID reactor vessel locations.

2.6 Material Surveillance e surveillance program, the evaluation of radiation damage is based on pre-irradiation testing of rpy V-notch and tensile specimens and postirradiation testing of Charpy V-notch, tensile, and T compact tension (CT) fracture mechanics test specimens. The program is directed toward luation of the effect of radiation on the fracture toughness of reactor vessel steels based on the sition temperature approach and the fracture mechanics approach. The program conforms to M E-185 (Reference 1) and 10 CFR 50, Appendix H.

veillance test materials are prepared from the actual materials used in fabricating the beltline on of the reactor vessel. Records are maintained of the chemical analyses, fabrication history, hanical properties and other essential variables pertinent to the fabrication process of the shell ing and weld metal from which the surveillance test materials are prepared. The test materials processed so that they are representative of the material in the completed reactor vessel.

ee metallurgically different materials prepared from sections of reactor vessel shell forging are d for test specimens. These include base metal, weld metal and heat affected zone (HAZ) erial.

5.3-5 Revision 1

lf Energy (USE)), and the predicted effect of chemical composition (nickel and residual copper) neutron fluence on the toughness (RTNDT shift and decrease in USE) during reactor operation.

ring forging with the highest predicted adjusted RTNDT temperature (initial RTNDT plus DT shift) or that with USE predicted to approach close to the minimum limit of 50 ft-lb at end-of-nse (EOL) is selected as the surveillance base metal test material. The means for measuring al toughness and for predicting irradiation induced toughness changes is consistent with licable procedures in force at the time the material is being selected. The section of shell forging d for the base metal test block is adjacent to the test material used for fracture toughness tests.

d metal and HAZ test material is produced by welding together sections of the forgings from the line of the reactor vessel. The HAZ test material is manufactured from a section of the same shell rse forging used for base metal test material. The sections of shell course forging used for weld al and HAZ test material are adjacent to the test material used for fracture toughness tests. The t of wire or rod and lot of flux are from the same heat and lot used in making the beltline region ds. Welding parameters duplicate those used for the beltline region welds. The procedures for ection of the reactor vessel welds are followed for the inspection of the welds in test materials.

surveillance weld and HAZ material are heat-treated to metallurgical conditions which are esentative of the final metallurgical conditions of similar materials in the completed reactor sel.

Specimens are marked to identify the type of materials and the orientation with respect to the materials. Drawings specify the identification system to be used and include plant identification, of material, orientation of specimen and sequential number.

eline test specimens are provided for establishing the baseline (unirradiated) properties of the tor vessel materials. The data from tests of these specimens provides the basis for determining radiation induced property changes of the reactor vessel materials.

p weight test specimens of each of base metal, weld metal, and HAZ metal are provided for blishing the nil-ductility transition temperature (NDTT) of the unirradiated surveillance materials.

se data form the basis for RTNDT determination from which subsequent radiation induced nges are determined.

ndard Charpy impact test specimens each of base metal (longitudinal (tangential) and transverse al)), weld metal, and HAZ material are provided for developing a Charpy impact energy transition e from fully brittle to fully ductile behavior for defining specific index temperatures for these erials. These data, together with the drop weight NDTT, are used to establish an RTNDT for each erial.

sile test specimens each of base metal (longitudinal (tangential) and transverse (axial)), weld al, and HAZ metal are provided to permit a sufficient number of tests for accurately establishing tensile properties for these materials at a minimum of three test temperatures (e.g., ambient, rating and one intermediate temperature) to define the strength of the material.

above described test specimens are to be used for determining changes in the strength and hness of the surveillance materials resulting from neutron irradiation. Sufficient Charpy impact, pact tension and tensile test specimens are provided for establishing the changes in the perties of the surveillance materials over the lifetime of the reactor vessel. The type, quantity, and age conditions (e.g., surveillance capsules backfilled with inert gas) of test specimens meet or eed the minimum requirements of ASTM E-185.

5.3-6 Revision 1

reactor vessel surveillance program incorporates eight specimen capsules. The capsules are ted in guide baskets welded to the outside of the core barrel as shown in Figure 5.3-4 and itioned directly opposite the center portion of the core. The capsules can be removed when the sel head is removed. To meet the guidelines of ASTM E-185 (lead factors less than three), the cimen guide baskets are located azimuthally near the lowest fluence locations at 135, 225, and degrees. The 45 degree location is also a low fluence azimuthal location; however, there is a o-Lock insert for the internals lifting rig, which would prevent access for removal of the capsules the baskets. Therefore, there are no guide baskets at the 45 degree location. Eight specimen sules are provided by including three guide baskets at the 135 and 315 degree azimuthal tions and two baskets at the 225 degree location.

capsules contain reactor vessel weld metal, base metal, and heat-affected zone metal cimens. The base metal specimens are oriented both parallel and normal (longitudinal and sverse) to the principal rolling direction of the limiting base material located in the core region of reactor vessel. The 8 capsules contain 72 tensile specimens, 480 Charpy V-notch specimens, 48 compact tension specimens. Archive material sufficient for two additional capsules and heat-cted-zone (HAZ) materials is retained.

imeters, as described below, are placed in filler blocks drilled to contain them. The dosimeters mit evaluation of the flux seen by the specimens and the vessel wall. In addition, thermal monitors e of low melting point alloys are included to monitor the maximum temperature of the specimens.

specimens are enclosed in a tight-fitting stainless steel sheath to prevent corrosion and ensure d thermal conductivity. The complete capsule is helium leak tested. As part of the surveillance gram, a report of the residual elements in weight percent to the nearest 0.01 percent is made for eillance material and as deposited weld metal. Each of the eight capsules contains the cimens shown in Table 5.3-4.

following dosimeters and thermal monitors are included in each of the eight capsules:

Dosimeters

- Iron

- Copper

- Nickel

- Niobium-93 (cadmium shielded)

- Cobalt-aluminum (0.15-percent cobalt)

- Cobalt-aluminum (cadmium shielded)

Thermal Monitors

- 97.5-percent lead, 2.5-percent silver, (579°F melting point)

- 97.5-percent lead, 1.75-percent silver, 0.75-percent tin (590°F melting point) 5.3-7 Revision 1

sel, the transition temperature shift measurements are representative of the vessel at a later time

e. The lead factors for the eight specimen capsule locations based on the reference neutron flux ribution (flux distribution that results in the maximum fluence on the reactor vessel inner surface) between approximately 1.8 and 2.3. These lead factors will change over the life of the plant due hanges in core design and operating parameters. Data from CT fracture toughness specimens expected to provide additional information for use in determining allowable stresses for irradiated erial.

relations between the calculations and measurements of the irradiated samples in the capsules, uming the same neutron spectrum at the samples and the vessel inner wall, are described in section 5.3.2.6.1. The anticipated degree to which the specimens perturb the fast neutron flux energy distribution is considered in the evaluation of the surveillance specimen data. Verification possible readjustment of the calculated wall exposure is made by the use of data on capsules drawn. The recommended program schedule for removal of the capsules for post-irradiation ing includes five capsules to be withdrawn instead of four as specified in ASTM E-185 ference 1) and Appendix H of 10 CFR 50. The following is the recommended withdrawal edule of capsules for AP1000.

sule Withdrawal Time When the accumulated neutron fluence of the capsule is 5 x 1018 n/cm2.

When the accumulated neutron fluence of the capsule corresponds to the approximate end of life fluence at the reactor vessel 1/4T location.

When the accumulated neutron fluence of the capsule corresponds to the approximate end of life fluence at the reactor vessel inner wall location.

When the accumulated neutron fluence of the capsule corresponds to a fluence not less than once or greater than twice the peak end of vessel life fluence.

End of plant design objective of 60 years Standby Standby Standby 2.6.1 Measurement of Integrated Fast Neutron (E > 1.0 MeV) Flux at the Irradiation Samples use of passive neutron sensors such as those included in the internal surveillance capsule imetry sets does not yield a direct measure of the energy dependent neutron flux level at the surement location. Rather, the activation or fission process is a measure of the integrated effect the time and energy dependent neutron flux has on the target material over the course of the diation period. An accurate estimate of the average neutron flux level, and hence, time integrated osure (fluence) experienced by the sensors may be derived from the activation measurements if the parameters of the irradiation are well known. In particular, the following variables are of rest:

5.3-8 Revision 1

The operating history of the reactor The energy response of each sensor The neutron energy spectrum at the sensor location procedures used to determine sensor specific activities, to develop reaction rates for individual sors from the measured specific activities and the operating history of the reactor, and to derive fast neutron exposure parameters from the measured reaction rates are described below.

2.6.1.1 Determination of Sensor Reaction Rates specific activity of each of the radiometric sensors is determined using established ASTM edures. Following sample preparation and weighing, the specific activity of each sensor is rmined by means of a high purity germanium gamma spectrometer. In the case of the eillance capsule multiple foil sensor sets, these analyses are performed by direct counting of h of the individual wires or, as in the case of niobium monitors, by appropriate methods as cribed in ASTM E 1297.

irradiation history of the reactor over its operating lifetime is determined from plant power eration records. In particular, operating data are extracted on a monthly basis from reactor startup e end of the capsule irradiation period. For the sensor sets utilized in the surveillance capsule diations, the half-lives of the product isotopes are long enough that a monthly histogram cribing reactor operation has proven to be an adequate representation for use in radioactive ay corrections for the 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 from following equation:

A R=

Pj - t j N0 F Y j C j [1 - e ] e- t d Pref re:

= measured specific activity provided in terms of disintegrations per second per gram of target material (dps/gm).

= reaction rate averaged over the irradiation period and referenced to operation at a core power level of Pref expressed in terms of reactions per second per nucleus of target isotope (rps/nucleus).

= number of target element atoms per gram of sensor.

= weight fraction of the target isotope in the sensor material.

= number of product atoms produced per reaction.

5.3-9 Revision 1

= calculated ratio of (E > 1.0 MeV) during irradiation period j to the time weighted 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).

the summation is carried out over the total number of monthly intervals comprising the total diation period.

e above equation, the ratio Pj/Pref accounts for month-by-month variation of power level within a n fuel cycle. The ratio Cj is calculated for each fuel cycle and accounts for the change in sensor tion rates caused by variations in flux level due to changes in core power spatial distributions fuel cycle to fuel cycle. Since the neutron flux at the measurement locations within the eillance capsules is dominated by neutrons produced in the peripheral fuel assemblies, the nge in the relative power in these assemblies from fuel cycle to fuel cycle can have a significant act on the activation of neutron sensors. For a single-cycle irradiation, Cj = 1.0. However, for tiple-cycle irradiations, particularly those employing low leakage fuel management, the additional orrection must be utilized in order to provide accurate determinations of the decay corrected tion rates for the dosimeter sets contained in the surveillance capsules.

2.6.1.2 Least Squares Adjustment Procedure st squares adjustment methods provide the capability of combining the measurement data with neutron transport calculation resulting in a Best Estimate neutron energy spectrum with ociated uncertainties. Best Estimates for key exposure parameters such as neutron fluence 1.0 MeV) or iron atom displacements (dpa) along with their uncertainties are then easily ined from the adjusted spectrum. The use of measurements in combination with the analytical lts reduces the uncertainty in the calculated spectrum and acts to remove biases that may be ent in the analytical technique.

eneral, the least squares methods, as applied to pressure vessel fluence evaluations, act to ncile the measured sensor reaction rate data, dosimetry reaction cross-sections, and the ulated neutron energy spectrum within their respective uncertainties. For example, R i +/- Ri = (

g ig +/- ig )( g +/- g )

tes a set of measured reaction rates, Ri, to a single neutron spectrum, g, through the multigroup imeter reaction cross-section, ig, each with an uncertainty .

use of least squares adjustment methods in LWR dosimetry evaluations is not new. The erican Society for Testing and Materials (ASTM) has addressed the use of adjustment codes in M Standard E944, Application of Neutron Spectrum Adjustment Methods in Reactor veillance and many industry workshops have been held to discuss the various applications. For 5.3-10 Revision 1

primary objective of the least squares evaluation is to produce unbiased estimates of the neutron osure parameters at the location of the measurement. The analytical method alone may be cient because it inherently contains uncertainty due to the input assumptions to the calculation.

ically these assumptions include parameters such as the temperature of the water in the pheral fuel assemblies, by-pass region, and downcomer regions, component dimensions, and pheral core source. Industry consensus indicates that the use of calculation alone results in rall uncertainties in the neutron exposure parameters in the range of 15-20% (1).

application of the least squares methodology requires the following input:

The calculated neutron energy spectrum and associated uncertainties at the measurement location.

The measured reaction rate and associated uncertainty for each sensor contained in the multiple foil set.

The energy dependent dosimetry reaction cross-sections and associated uncertainties for each sensor contained in the multiple foil sensor set.

a given application, the calculated neutron spectrum is obtained from the results of plant specific tron transport calculations applicable to the irradiation period experienced by the dosimetry sor set. This calculation is performed using the benchmarked transport calculational methodology cribed in Subsection 5.3.2.6.2. The sensor reaction rates are derived from the measured specific vities obtained from the counting laboratory using the specific irradiation history of the sensor set erform the radioactive decay corrections. The dosimetry reaction cross-sections and ertainties that are utilized in LWR evaluations comply with ASTM Standard E1018, Application of M Evaluated Cross-Section Data File, Matrix E 706 (IIB).

uncertainties associated with the measured reaction rates, dosimetry cross-sections, and ulated neutron spectrum are input to the least squares procedure in the form of variances and ariances. The assignment of the input uncertainties also follows the guidance provided in ASTM ndard E 944.

2.6.2 Calculation of Integrated Fast Neutron (E > 1.0 MeV) Flux at the Irradiation Samples eneralized set of guidelines for performing fast neutron exposure calculations within the reactor figuration, and procedures for analyzing measured irradiation sample data that can be correlated ese calculations, has been promulgated by the Nuclear Regulatory Commission (NRC) in ulatory Guide 1.190, or RG-1.190, Calculational and Dosimetry Methods for Determining ssure Vessel Neutron Fluence [Reference 2]. Since different calculational models exist and are tinuously evolving along with the associated model inputs, e.g., cross-section data, it is thwhile summarizing the key models, inputs, and procedures that the NRC staff finds acceptable se in determining fast neutron exposures within the reactor geometry. This material is highlighted e subsection of material that is provided below.

2.6.2.1 Calculation and Dosimetry Measurement Procedures selection of a particular geometric model, the corresponding input data, and the overall hodology used to determine fast neutron exposures within the reactor geometry are based on the ds for accurately determining a solution to the problem that must be solved and the 5.3-11 Revision 1

knesses associated with a given calculational model and/or methodology. Based on these ditions, RG-1.190 does not recommend using a singular calculational technique to determine fast tron exposures. Instead, RG-1.190 suggests that one of the following neutron transport tools be d to perform this work.

Discrete Ordinates Transport Calculations

- Adjoint calculations benchmarked to a reference-forward calculation, or stand-alone forward calculations.

- Various geometrical models utilized with suitable mesh spacing in order to accurately represent the spatial distribution of the material compositions and source.

- In performing discrete ordinates transport calculations, RG-1.190 also suggests that a P3 angular decomposition of the scattering cross-sections be used, as a minimum.

- RG-1.190 also recommends that discrete ordinates transport calculations utilize S8 angular quadrature, as a minimum.

- RG-1.190 indicates that the latest version of the Evaluated Nuclear Data File, or ENDF/B, should be used for determining the nuclear cross-sections; however, cross-sections based on earlier or equivalent nuclear data sets that have been thoroughly benchmarked are also acceptable.

Monte Carlo Transport Calculations A complete description of the Westinghouse pressure vessel neutron fluence methodology, which is based on discrete ordinates transport calculations, is provided in Reference 3. The Westinghouse methodology adheres to the guidelines set forth in Regulatory Guide 1.190.

2.6.2.2 Plant-Specific Calculations location, selection, and evaluation of neutron dosimetry and the associated radiometric monitors, ell as fast (E > 1.0 MeV) neutron fluence assessments of the AP1000 reactor pressure vessel, conducted in accordance with the guidelines that are specified in Regulatory Guide 1.190.

2.6.3 Report of Test Results mmary technical report for each capsule withdrawn with the test results is submitted, as cified in 10 CFR 50.4, within one year of the date of capsule withdrawal unless an extension is nted by the Director, Office of Nuclear Reactor Regulation.

report includes the data required by ASTM E185-82, as specified in paragraph III.B.1 of CFR Part 50, Appendix H, and includes the results of the fracture toughness tests conducted on beltline materials in the irradiated and unirradiated conditions.

e test results indicate a change in the Technical Specifications is required, either in the pressure-perature limits or in the operating procedures required to meet the limits, the expected date for mittal of the revised Technical Specification is provided with the report.

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requirements of the ASME Code,Section III. The closure studs are fabricated of SA-540. The ure stud material meets the fracture toughness requirements of the ASME Code,Section III, and CFR 50, Appendix G. Conformance with Regulatory Guide 1.65, Materials and Inspections for ctor Vessel Closure Studs, is discussed in Section 1.9. Nondestructive examinations are ormed in accordance with the ASME Code,Section III. See Subsection 5.2.3 for restrictions on icants.

ueling procedures require that the reactor vessel closure studs, nuts, and washers are lifted out of r respective holes and a stud support collar be put in place prior to the lift of the integrated head embly during preparation for refueling. In this way the studs are lifted with and stored on the head.

alternative method is to remove the reactor vessel closure studs, nuts, and washers from the tor closure and place them in storage racks during preparation for refueling. In this method, the age racks are removed from the refueling cavity and stored at convenient locations on the tainment operating deck prior to removal of the reactor closure head and refueling cavity flooding.

ither case, the reactor closure studs are not exposed to the borated refueling cavity water.

itional protection against the possibility of incurring corrosion effects is provided by the use of a ganese base phosphate surfacing treatment.

stud holes in the reactor flange are sealed with special plugs before removing the reactor ure, thus preventing leakage of the borated refueling water into the stud holes.

3 Pressure-Temperature Limits 3.1 Limit Curves tup and cooldown pressure-temperature limit curves are required as a means of protecting the tor vessel during startup and shut down to minimize the possibility of fast fracture. The methods ined in Appendix G of Section III of the ASME Code are employed in the analysis of protection inst nonductile failure. Beltline material properties degrade with radiation exposure, and this radation is measured in terms of the adjusted reference nil ductility temperature, which includes a rence nil ductility temperature shift (RTNDT), initial RTNDT and margin. The extent of the DT shift is enhanced by certain chemical elements (such as copper and nickel).

dicted RTNDT values are derived considering the effect of fluence and copper and nickel content he reactor vessel steels exposed to 550°F temperature. U.S. NRC Regulatory Guide 1.99 is used alculating adjusted reference temperature. Since the AP1000 cold leg temperature exceeds

°F (minimum steady-state temperature is 535°F at 100% power, thermal design flow, and 10%

plugging), the procedures of Regulatory Guide 1.99 for nominal embrittlement apply. The heatup cooldown curves are developed considering a sufficient magnitude of radiation embrittlement so no unirradiated ferritic materials in other components of the reactor coolant system will be ing in the analysis.

pressure-temperature curves are developed considering a radiation embrittlement of up to ffective full power years (EFPY) consistent with the plant design objective of 60 years with ercent availability. Copper, nickel contents and initial RTNDT for materials in the reactor vessel line region and the reactor vessel flange and the closure head flange region are shown in les 5.3-1 and 5.3-3. The operating curves are developed with the methodology given in erence 6, which is in accordance with 10 CFR 50, Appendix G with the following exceptions:

The fluence values used are calculated fluence values (i.e., comply with Regulatory Guide 1.190), not the best-estimate fluence values.

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The 1996 Version of Appendix G to Section XI is used rather than the 1989 version.

curves are applicable up to 54 effective full-power years. These curves, shown in Figures 5.3-2 5.3-3, are generic curves for the AP1000 reactor vessel design and they are limiting curves ed on copper and nickel material composition (Reference 9). These curves are applicable as long he following criteria are met:

10 CFR 50, Appendix G as related to pressure-temperature remains unchanged, Adjusted Reference Temperatures at 1/4T and 3/4T locations remain below the bases of Figures 5.3-2 and 5.3-3 results of the material surveillance program described in Subsection 5.3.2.6 will be used to verify validity of RTNDT used in the calculation for the development of heatup and cooldown curves.

projected fluence, copper, and nickel contents along with the RTNDT calculation will be adjusted cessary, from time to time using the surveillance capsule results. This may require the elopment of new heatup and cooldown curves.

her rates of temperature changes when the reactor coolant system pressure is at or above the rating pressure do not impact the determination of the proper curve to use. Figure 5.3-2 also udes a curve for the leak test limit at steady-state temperature and curves for the criticality limit for lear heatup.

perature limits for core operation, inservice leak and hydrotests are calculated in accordance the ASME Code,Section III, Appendix G.

3.2 Operating Procedures nt operating procedures are developed and maintained to prevent exceeding the pressure-perature limits identified in reactor coolant system pressure and temperature limits report, as uired by Technical Specification 5.6.6, during normal and abnormal operating conditions and em tests.

4 Reactor Vessel Integrity 4.1 Design reactor vessel is the high pressure containment boundary used to support and enclose the tor core. It provides flow direction with the reactor internals through the core and maintains a me of coolant around the core. The vessel is cylindrical, with a transition ring, hemispherical om head, and removable flanged hemispherical upper head. The vessel is fabricated by welding ther the lower head, the transition ring, the lower shell, and the upper shell. The upper shell tains the penetrations from the inlet and outlet nozzles and direct vessel injection nozzles. The ure head is fabricated with a head dome and bolting flange. The upper head has penetrations for control rod drive mechanisms, the incore instrumentation, head vent, and support lugs for the grated head package.

reactor vessel (including closure head) is approximately 40 feet long and has an inner diameter e core region of 159 inches. The total weight of the vessel (including closure head and CRDMs) pproximately 417 tons. Surfaces which can become wetted during operation and refueling are 5.3-14 Revision 1

sel life is radiation degradation of the lower shell.

a safety precaution, there are no penetrations below the top of the core. This eliminates the sibility of a loss of coolant accident by leakage from the reactor vessel which could allow the core e uncovered. The core is positioned as low as possible in the vessel to limit reflood time in an dent. The main radial support system of the lower end of the reactor internals is accomplished by and keyway joints to the vessel wall. At equally spaced points around the circumference, a clevis k is located on the reactor vessel inner diameter. A permanent cavity liner seal ring is attached to top of the vessel shell for welding to the refueling cavity liner. To decrease outage time during eling, access to the stud holes is provided to allow stud hole plugging with the head in place. By use of a ring forging with an integral flange, the number of welds is minimized to decrease rvice inspection time.

lower head has an approximate 6.5 feet inner spherical radius. The lower radial supports are ted on the head at the elevation of the lower internals lower core support plate. The transition ring elded to the lower shell course with the weld located outside the high fluence active core region.

lower shell is a ring forging about 8 inches thick with an inner diameter of 159 inches. The length e shell is greater than 168 inches to place the upper shell weld outside of the active fuel region.

upper shell is a large ring forging. Included in this forging are four 22-inch inner diameter inlet zles, two 31-inch inner diameter outlet nozzles and two 6.81-inch inner diameter direct vessel ction nozzles (8-inch schedule 160 pipe connections). These nozzles are forged into the ring or fabricated by set in construction. The inlet and outlet nozzles are offset axially in different planes 7.5 inches. The injection nozzles are 100 inches down from the main flange and the outlet zles are 80 inches down and the inlet nozzles are 62.5 inches below the mating surface.

closure head has a 77.5-inch inner spherical radius and a 188.0-inch O.D. outer flange. Cladding xtended across the bottom of the flange for refueling purposes. Forty-five, seven-inch diameter s attach the head to the lower vessel and two metal o-rings are used for sealing. The upper head sixty-nine 4-inch outer diameter penetrations for the control rod drive mechanism housings and t penetrations for the incore instrumentation tubes.

eight penetrations for the incore instrumentation tubes are Quickloc instrument nozzles, which welded to the reactor vessel head. Up to six instrument thimble assemblies pass through each ckloc instrument nozzle. The reactor vessel head penetration diameter is approximately inches to the cladding. The material of the pressure boundary parts of the Quickloc are 182 - Type F304, SA-479 - Type 304 and Type 316, and UNS S21800. The Quickloc instrument zle is welded to the Ni-Cr-Fe buttering on the weld buildup on the reactor vessel closure head.

Quickloc provides two pressure boundaries: 1) between the Quickloc plug and the incore rument thimble assemblies (this pressure boundary is disassembled only when the instrument ble is replaced) and 2) between the Quickloc plug and the instrument nozzle (this pressure ndary is disassembled when the reactor vessel closure head is removed). The Quickloc rument nozzle pressure boundary parts are designed and fabricated to the requirements of the ME Code,Section III Division 1, Subsection NB. The Quickloc internal, non-pressure boundary s are designed to Subsection NG. The Quickloc assembly is a proven design, which was first alled in an operating plant in 1995. Since then, it has been installed on four additional operating ts.

vessel is manufactured from low alloy steel plates and forgings to minimize size. The chemical tent of the core region base material is specifically controlled. A surveillance program is used to itor the radiation damage to the vessel material.

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ollect any leakage past the closure region o-rings.

reactor vessel is designed and fabricated in accordance with the quality standards set forth in CFR 50, General Design Criteria 1, 14, 30, and 31, and 50.55a; and the requirements of the erican Society of Mechanical Engineers (ASME) Code,Section III. Principal design parameters of reactor vessel are given in Table 5.3-5. The vessel design and construction enables inspection in ordance with the ASME Code,Section XI.

lic loads are introduced by normal power changes, reactor trips, and startup and shutdown rations. These design base cycles are selected for fatigue evaluation and constitute a servative design envelope for the design life. Thermal stratification during passive core cooling em operation and natural circulation cooldown is considered by performing a thermal/flow lysis using computational fluid dynamics techniques. This analysis includes thermally-induced buoyancy, heat transfer between the coolant and the metal of the vessel and internals and uses mal/flow boundary conditions based on an existing thermal/hydraulic transient analysis of the ary reactor coolant system. This analysis provides temperature maps that are used to evaluate mal stresses.

lysis proves that the vessel is in compliance with the fatigue and stress limits of the ASME Code, tion III. The loadings and transients specified for the analysis are based on the most severe ditions expected during service. The heatup and cooldown rates imposed by plant operating limits 100°F per hour for normal operations.

4.2 Materials of Construction materials used in the fabrication of the reactor vessel are discussed in Subsection 5.2.3.

4.3 Fabrication Methods fabrication methods used in the construction of the reactor vessel are discussed in section 5.3.2.2.

4.4 Inspection Requirements nondestructive examinations performed on the reactor vessel are described in section 5.3.2.3.

4.5 Shipment and Installation reactor vessel is shipped in a horizontal position on a shipping skid with a vessel-lifting truss embly. All vessel openings are sealed to prevent the entrance of moisture, and an adequate ntity of desiccant bags is placed inside the vessel. These are usually placed in a wire mesh ket attached to the vessel cover. All carbon steel surfaces are protected with a temporary ective covering before shipment.

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 are led to prevent the entrance of moisture, and an adequate quantity of desiccant bags is placed de the head. These are placed in a wire mesh basket attached to the head cover. All carbon steel aces are protected with a temporary protective covering before shipment.

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cifications.

ddition to the analysis of primary components discussed in Subsection 3.9.1.4, the reactor vessel rther qualified to ensure against unstable crack growth under faulted conditions. Safeguard ation following a loss-of-coolant, tube rupture or other similar emergency or faulted event duces relatively high thermal stresses in regions of the reactor vessel which come into contact water from the passive core cooling system. Primary consideration is given to these areas, uding the reactor vessel beltline region and the reactor vessel primary coolant nozzles, to ensure integrity of the reactor vessel under these severe postulated transients. TMI Action Item II.K.2.13, atisfied upon submittal of RTNDT values which are below the pressurized thermal shock (PTS) screening values. The results given in Table 5.3-3 show that the issue is resolved.

the beltline region, the NRC staff concluded that conservatively calculated screening criterion es of RTNDT less than 270°F for plate material and axial welds, and less than 300°F for umferential welds, present an acceptably low risk of vessel failure from pressurized thermal shock nts. These values were chosen as the screening criterion in the pressurized thermal shock rule 10 CFR 50.34 (new plants) and 10 CFR 50.61 (operating plants). The conservative methods sen by the NRC staff for the calculation of RTPTS for the purpose of comparison with the ening criterion is presented in paragraph (b)(2) of 10 CFR 50.61. Details of the analysis method the basis for the pressurized thermal shock rule can be found in SECY-82-465 (Reference 4).

revised pressurized thermal shock rule, (10 CFR 50.61), effective June 14, 1991 makes the edure for calculating RTPTS values consistent with the methods given in Regulatory Guide 1.99.

reactor vessel beltline materials are specified in Subsection 5.3.2. Evaluation of the AP1000 tor vessel material showed that even at the fluence level which results in the highest TS value, this value is well below the screening criteria of 270°F. RTPTS is RTNDT, the reference uctility transition temperature as calculated by the method chosen by the NRC staff as presented aragraph (b)(2) of 10 CFR 50.61, and the pressurized thermal shock rule. The pressurized mal shock rule states that this method of calculating RTPTS should be used in reporting values d to compare pressurized thermal shock to the above screening criterion set in the pressurized mal shock rule. The screening criteria will not be exceeded using the method of calculation cribed by the pressurized thermal shock rule for the vessel design objective. The material perties, and initial RTNDT and end-of-life RTPTS requirements and predictions are in Tables 5.3-1 5.3-3. The materials that are exposed to high fluence levels at the beltline region of the reactor sel are subject to the pressurized thermal shock rule. These materials are a subset of the reactor sel materials identified in Subsection 5.3.2.

principles and procedures of linear elastic fracture mechanics (LEFM) are used to evaluate mal effects in the regions of interest. The linear elastic fracture mechanics approach to the design inst failure is basically a stress intensity consideration in which criteria are established for fracture ability in the presence of a crack. Consequently, a basic assumption employed in linear elastic ture mechanics is that a crack or crack-like defect exists in the structure. The essence of the roach is to relate the stress field developed in the vicinity of the crack tip to the applied stress on structure, the material properties, and the size of defect necessary to cause failure.

4.7 Inservice Surveillance internal surfaces of the reactor vessel are accessible for periodic inspection. Visual and/or destructive techniques are used. During refueling, the vessel cladding is capable of being ected in certain areas of the upper shell above the primary coolant inlet nozzles, and if deemed 5.3-17 Revision 1

closure head is examined visually during each refueling. Optical devices permit a selective ection of the cladding, control rod drive mechanism nozzles, and the gasket seating surface.

ess to the top head surface is provided by 7 ports around the circumference of the integrated d package shroud and by multiple removable insulation panels, which interface with the head er the integrated head package shroud. Both the ports and the insulation panels provide access e bare vessel head, and CRDM and instrumentation penetrations for use of a remote, mobile al inspection manipulator to perform a 360° inspection around each penetration. The head lation is a stand-off design with a minimum offset from the head surface of 3 inches.

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

closure studs, nuts, washers, and the vessel flange seal surface, as well as the full-penetration ds in the following areas of the installed reactor vessel, are available for nondestructive mination:

Vessel shell, from the inside surface.

Primary coolant nozzles, from the inside surface. Only partial outside diameter coverage is provided.

Closure head, from the inside surface; bottom head, from the inside surface.

Field welds between the reactor vessel nozzle safe ends and the main coolant piping, from the inside surface.

design considerations which have been incorporated into the system design to permit the above ection are as follows:

Reactor internals are completely removable. The tools and storage space required to permit removal of the reactor internals are provided.

The closure head is stored on a stand on the reactor operating deck during refueling to facilitate direct visual inspection.

Reactor vessel studs, nuts, and washers can be removed to dry storage during refueling.

Access is provided to the reactor vessel nozzle safe ends. The insulation covering the nozzle-to-pipe welds may be removed.

ause radiation levels and remote underwater accessibility limits access to the reactor vessel, eral steps have been incorporated into the design and manufacturing procedures in preparation he periodic nondestructive tests which are required by the ASME Code inservice inspection uirements. These are as follows:

Shop ultrasonic examinations are performed on internally clad surfaces to an acceptance and repair standard to provide an adequate cladding bond to allow later ultrasonic testing of the base metal from the inside surface. The size of cladding bond defect allowed is 0.25 inch by 0.75 inch with the greater direction parallel to the weld in the region bounded by 2T (T = wall 5.3-18 Revision 1

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

The weld-deposited clad surface on both sides of the welds to be inspected is specifically prepared to ensure meaningful ultrasonic examinations.

During fabrication, full-penetration ferritic pressure boundary welds are ultrasonically examined in addition to code examinations.

After the shop hydrostatic testing, full-penetration ferritic pressure boundary welds (with the exception of the closure head welds), as well as the nozzles to safe end welds, are ultrasonically examined from both the inside and outside diameters in addition to ASME Code,Section III requirements.

Preservice examinations for the closure head will include a baseline top-of-the head visual examination; ultrasonic examinations of the inside diameter surface of each vessel head penetration; eddy current examinations of the surface of head penetration welds, the outside diameter surface of the vessel penetrations, and the inside diameter surface of the penetrations; and post-hydro liquid penetrant examinations of accessible surfaces that have undergone preservice inspection eddy current examinations.

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

5 Reactor Vessel Insulation 5.1 Reactor Vessel Insulation Design Bases ctor vessel insulation is provided to minimize heat losses from the primary system. Nonsafety-ted reflective insulation similar to that in use in current pressurized water reactors is utilized. The 000 reactor vessel insulation contains design features to promote in-vessel retention following ere accidents. In the unlikely event of a beyond design basis accident, the reactor cavity is ded with water, and the reactor vessel insulation allows heat removal from core debris via boiling he outside surface of the reactor vessel. The reactor vessel insulation permits a water layer next e reactor vessel to promote heat transfer from the reactor vessel. This is accomplished by iding:

A means of allowing water free access to the region between the reactor vessel and insulation.

A means to allow steam generated by water contact with the reactor vessel to escape from the region surrounding the reactor vessel.

The insulation support frame and the insulation panels form a structurally reliable flowpath for the water and steam.

reactor vessel insulation and its supports are designed to withstand bounding pressure rentials across the reactor vessel insulation panels during the period that the reactor vessel is rnally flooded with water and the core heat is removed from the vessel wall by water and erated steam is vented. This is accomplished by providing steam vents with a minimum flow area 2 ft2 from the vessel insulation annular space. The flow path from the reactor loop compartment to 5.3-19 Revision 1

5.2 Description of Insulation hematic of the reactor vessel, the vessel insulation and the reactor cavity is shown in re 5.3-7. The insulation is mounted on a structural frame that is supported from the wall and floor e reactor cavity. The insulation panels are designed to have a minimum gap between the lation and reactor vessel not less than 2 inches when subjected to the dynamic loads in the ction towards the vessel that result during ex-vessel cooling.

bottom portion of the vessel insulation is constructed to provide a flow channel conducive for t removal.

structural frame supporting the insulation is designed to withstand the bounding severe accident s while maintaining the flow path. The fasteners holding the insulation panels to the frame are designed for these loads.

he bottom of the insulation are water inlet assemblies. Each water inlet assembly is normally ed to prevent an air circulation path through the vessel insulation. The inlet assemblies are self-ating passive devices. The inlet assemblies open when the cavity is filled with water. This permits ess of water during a severe accident, while preventing excessive heat loss during normal ration.

total flow area of the water inlet assemblies has sufficient margin to preclude significant pressure p during ex-vessel cooling during a severe accident. The minimum total flow area for the water s assemblies is 6 ft2. Due to the relatively low approach velocities in the flow paths leading to the tor cavity, the grating over the vertical access tunnel, the design of the doorway between the tor coolant drain tank compartment and the reactor cavity, the low flow velocities approaching water inlet assemblies, and the relatively large minimum flow area through each water inlet embly, at least 7 in2, the water inlet assemblies and the steam flow path are not susceptible to ging from debris inside containment.

tiple steam vents in the nozzle gallery provide a flow path for the steam/water within the reactor sel/insulation annular space to flow back to the containment flood-up region. The steam vents ide 12 ft2 minimum flow area for steam/water to exit the annular space. Each of the steam vents a door that will be opened by the steam/water flow generated under the insulation with the cavity d with water, but which remains in place when only normal air cooling flow is operating.

ensive maintenance of the vessel insulation is not normally required. Periodic verification of the sel insulation moving parts can be performed during refueling outages.

5.3 Description of External Vessel Cooling Flooded Compartments vessel cooling during a severe accident is provided by flooding the reactor coolant system loop partment including the vertical access tunnel, the reactor coolant drain tank room, and the tor cavity. Water from these compartments replenishes the water that comes in contact with the tor vessel and is boiled and vented to containment. The opening between the vertical access el and the reactor coolant drain tank room is approximately 100 ft2. Removable steel grating is ided over the inlet to the vertical access tunnel to restrict access to the lower compartments. This ing precludes large debris from being transported into the reactor cavity during ex-vessel cooling narios. Figure 5.3-8 depicts the flooded compartments that provide the water for ex-vessel ling. The doorway between the reactor cavity compartment and the reactor coolant drain tank 5.3-20 Revision 1

partment, but opens to permit flooding of the reactor cavity from the reactor coolant drain tank partment. The damper opening has a minimum flow area of 8 ft2 and is not susceptible to ging from debris that can pass through the grating over the inlet to the vertical access tunnel. It is structed of light-weight material to minimize the force necessary to open the damper and permit ding and continued water flow through the opening during ex-vessel cooling. The damper ides an acceptable pressure drop through the opening during ex-vessel cooling.

section 6.3.2.1.3 discusses post-accident operation of the passive core cooling system, which rates to flood the reactor cavity following an accident. Subsection 9.1.3 discusses the nections from the refueling cavity to the steam generator compartment that facilitate flooding of reactor cavity following an accident.

5.4 Determination of Forces on Insulation and Support System forces that may be expected in the reactor cavity region of the AP1000 plant during a core age accident in which the core has relocated to the lower head and the reactor cavity is oded can be based on test results from the ULPU test program (Reference 5). The particular figuration (Configuration V) reviewed closely models the full-scale AP1000 geometry of water in region near the reactor vessel, between the reactor vessel and the reactor vessel insulation. The U tests provide data on the pressure generated in the region between the reactor vessel and tor vessel insulation. These data, along with observations and conclusions from heat transfer ies, are used to develop the functional requirements with respect to in-vessel retention for the tor vessel insulation and support system. Interpretation of data collected from ULPU figuration V experiments in conjunction with the static head of water that would be present in the 000 is used to estimate forces acting on the rigid sections of insulation. The ULPU V test results cate that the pressure variations in the flow channel between the vessel and the insulation are on order of plus/minus 0.5 meters of water. Fast Fourier Transform analysis of the ULPU V pressure is also included in the ULPU V test report. This analysis shows that the dominant frequency of pressure variations is less than about 2 Hz. The natural frequency of the insulation structure is ected to be well above 2 Hz.

5.5 Design Evaluation ructural analysis of the AP1000 reactor cavity insulation system was performed that onstrates that it meets the functional requirements discussed above. The analysis encompasses insulation and support system and includes a determination of the stresses in support members, s, insulation panels and welds, as well as deflection of support members and insulation panels.

ds on the insulation and the support structure include hydrostatic loads and dynamic loads from ng. These loads are of the same order as those analyzed for AP600, and the results of the 000 analysis show that the insulation is able to meet its functional requirements. The reactor sel insulation provides an engineered pathway for water-cooling the vessel and for venting steam the reactor cavity. These results were also compared to the available test data.

reactor vessel insulation is purchased equipment. The purchase specification for the reactor sel insulation design required confirmatory static load analyses.

5.3-21 Revision 1

pressure-temperature curves shown in Figures 5.3-2 and 5.3-3 are generic curves for AP1000 tor vessel design, and they are the limiting curves based on copper and nickel material position. Plant-specific curves will be developed based on material composition of copper and el. Use of plant-specific curves will be addressed during procurement and fabrication of the tor vessel. As noted in the bases to Technical Specification 3.4.14, use of plant-specific curves uires evaluation of the LTOP system. This includes an evaluation of the setpoint pressure for the S relief valve to determine if the setpoint pressure needs to be changed based on the plant-cific pressure-temperature curves. The development of the plant-specific curves and evaluation e setpoint pressure are required prior to fuel load.

6.2 Reactor Vessel Materials Surveillance Program reactor vessel reactor material surveillance program is addressed in Subsections 5.3.2.6 and 2.6.3.

6.3 Surveillance Capsule Lead Factor and Azimuthal Location Confirmation surveillance capsule lead factors and azimuthal locations are addressed in APP-GW-GLR-023 ference 7).

6.4 Reactor Vessel Materials Properties Verification 6.4.1 The verification of plant-specific belt line material properties consistent with the requirements in Subsection 5.3.3.1 and Tables 5.3-1 and 5.3-3 will be completed prior to fuel load. The verification will include a pressurized thermal shock evaluation based on as procured reactor vessel material data and the projected neutron fluence for the plant design objective of 60 years. This evaluation report will be submitted for NRC staff review.

6.4.2 The structural analysis of the AP1000 reactor vessel insulation and support structure is addressed in APP-GW-GLR-060 (Reference 8).

6.5 Reactor Vessel Insulation verification that the reactor vessel insulation is consistent with the design bases established for essel retention is addressed in Reference 8 (APP-GW-GLR-060).

6.6 Inservice Inspection of Reactor Vessel Head Weld Buildup inservice inspection program of the weld buildup on the reactor vessel head for the rumentation penetrations (Quickloc) is addressed in Subsection 5.2.4.1.

7 References ASTM E-185-82, Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power Reactor Vessels.

5.3-22 Revision 1

WCAP-15557, Qualification of the Westinghouse Pressure Vessel Neutron Fluence Evaluation Methodology, S. L. Anderson, August 2000.

NRC Policy Issue, Pressurized Thermal Shock, SECY-82-465, November 23, 1982.

Theofanous, T.G., et al., Limits of Coolability in the AP1000-Related ULPU-2400 Configuration V Facility, CRSS-03/06, June 2003.

WCAP-14040-NP-A, Revision 2, Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves, J. D. Andrachek, et al., January 1996.

APP-GW-GLR-023, Surveillance Capsule Lead Factor and Azimuthal Location Confirmation, Westinghouse Electric Company LLC.

APP-GW-GLR-060, Reactor Vessel Insulation System - Verification of In-Vessel Retention Design Bases, Westinghouse Electric Company LLC.

APP-RXS-Z0R-001, Revision 2, AP1000 Generic Pressure Temperature Limits Report, F. C. Gift, September 2008.

5.3-23 Revision 1

Beltline Forging As Deposited Weld Metal Element (percent) (percent)

Copper 0.06 0.06 Phosphorus 0.01 0.01 Vanadium 0.05 0.05 Sulfur 0.01 0.01 Nickel 0.85 0.85 5.3-24 Revision 1

RT(a) UT(a) PT(a) MT(a) rgings anges Yes Yes uds and nuts Yes Yes RDM head adapter tube Yes Yes strumentation tube Yes Yes ain nozzles Yes Yes ozzle safe ends Yes Yes hell sections Yes Yes eads Yes Yes ates Yes Yes eldments ead and shell Yes Yes Yes RDM head adapter to closure head connection Yes strumentation tube to closure head connection Yes ain nozzle Yes Yes Yes adding Yes Yes ozzle to safe ends Yes Yes Yes RDM head adapter flange to CRDM head adapter Yes Yes be l full-penetration ferritic pressure boundary welds Yes Yes cessible after hydrotest ll-penetration nonferritic pressure boundary welds cessible after hydrotest

a. Nozzle to safe ends Yes Yes eal ledge Yes ead lift lugs Yes ore pad welds Yes ow skirt support lugs weld buildup Yes Yes 5.3-25 Revision 1

MT - Magnetic particle metal weld repairs as a result of UT, MT, RT, and/or PT indications are cleared by the same nondestructive ination technique/procedure by which the indications were found. The repairs meet applicable Section III irements.

dition, UT examination in accordance with the in process/posthydro UT requirements is performed on base metal irs in the core region and base metal repairs in the inservice inspection zone (1/2 T).

5.3-26 Revision 1

Unirradiated End-of-life (54 EFPY)

RTNDT USE USE (ft-lb) RTPTS

(°F) (ft-lb) 1/4T (°F) tline Forging -10 > 75 > 50 < 270(2) ad 10 N/A N/A N/A nge 10 N/A N/A N/A ld 10 N/A N/A N/A tline Weld -20 > 75 > 50 < 300(2) s:

The minimum unirradiated upper shelf energy for beltline base metal is for the transverse direction.

End-of-Life RTPTS requirements shown. End-of-Life RTPTS (also equals RTNDT) will be determined for as-built material. The preliminary RTPTS for the AP1000 reactor vessel beltline forging and beltline weld are 94°F and 148°F, respectively.

5.3-27 Revision 1

Capsules S, T, U, V, W, X, Y, and Z Material Charpy Specimens Tensile Specimens 1/2T-CT Specimens ging (tangential) 15 3 2 ging (axial) 15 3 2 ld Metal 15 3 2 at Affected Zone (HAZ) 15 - -

5.3-28 Revision 1

(approximate values) esign pressure (psig) 2485 esign temperature (°F) 650 verall height of vessel and closure head, bottom head outside diameter to top of 45-9 ntrol rod mechanism (ft-in.)

umber of reactor closure head studs 45 ameter of reactor closure head/studs, (in.) 7 utside diameter of closure head flange (in.) 188 side diameter of flange (in.) 148.81 utside diameter at shell (in.) 176 side diameter at shell (in.) 159 et nozzle inside diameter (in.) 22 utlet nozzle inside diameter (in.) 31 ad thickness, nominal (in.) 0.22 wer head thickness, minimum (in.) 6 ssel beltline thickness, minimum (in.) 8 osure head thickness (in.) 6.25 5.3-29 Revision 1

Figure 5.3-1 Reactor Vessel 5.3-30 Revision 1

Figure 5.3-2 AP1000 Reactor Coolant System Heatup Limitations (Heatup Rate Up to 50° and 100°F/hour) Representative for the First 54 EFPY (Without Margins for Instrumentation Errors) 5.3-31 Revision 1

Figure 5.3-3 AP1000 Reactor Coolant System Cooldown Limitations (Cooldown Rates up to 50° and 100°F/hour) Representative for the First 54 EFPY (Without Margins for Instrumentation Errors) 5.3-32 Revision 1

Figure 5.3-4 AP1000 Reactor Vessel Surveillance Capsules Locations 5.3-33 Revision 1

Figure 5.3-5 Reactor Vessel Key Dimensions Plan View 5.3-34 Revision 1

Figure 5.3-6 Reactor Vessel Key Dimensions, Side View 5.3-35 Revision 1

Figure 5.3-7 Schematic of Reactor Vessel Insulation 5.3-36 Revision 1

Figure 5.3-8 RCS Flooded Compartments During Ex-Vessel Cooling 5.3-37 Revision 1

Figure 5.3-9 Door Between RCDT Room and Reactor Cavity Compartment 5.3-38 Revision 1

1.1 Design Bases reactor coolant pump (RCP) is an integral part of the reactor coolant pressure boundary. It is igned, fabricated, erected, and tested to quality standards consistent with the requirements set h in 10 CFR 50, 50.55a and General Design Criterion 1. The reactor coolant pump casing and or shell provide a barrier to the release of reactor coolant and other radioactive materials to the tainment atmosphere.

reactor coolant pump provides an adequate core cooling flow rate for sufficient heat transfer to ntain a departure from nucleate boiling ratio (DNBR) greater than the limit established in the ty analysis. Pump assembly rotational inertia is provided by a flywheel (inside the pump pressure ndary) motor rotor, and other rotating parts. This rotational inertia provides flow during coastdown ditions. This forced flow following an assumed loss of electrical power and the subsequent natural ulation effect in the reactor coolant system (RCS) adequately cools the core. The net positive ion head (NPSH) required for operation is by conservative pump design always less than that ilable by system design and operation.

reactor coolant pump pressure boundary shields the balance of the reactor coolant pressure ndary from theoretical worst-case flywheel failures. The reactor coolant pump pressure boundary nalyzed to demonstrate that a fractured flywheel cannot breach the reactor coolant system ndary (impacted pressure boundary components are stator closure, stator main flange, and lower or flange) and impair the operation of safety-related systems or components. This meets the uirements of General Design Criteria 4. The reactor coolant pump flywheel is designed, ufactured, and inspected to minimize the potential for the generation of high-energy fragments siles) under any anticipated operating or accident condition consistent with the intent of the elines set forth in Standard Review Plan Subsection 5.4.1.1 and Regulatory Guide 1.14. Each heel is tested at an overspeed condition to verify the flywheel design and construction.

1.2 Pump Assembly Description 1.2.1 Design Description e reactor coolant pump is a single-stage, hermetically sealed, high-inertia, centrifugal sealless p of canned motor design.]* It pumps large volumes of reactor coolant at high pressures and perature. Figure 5.4-1 shows a reactor coolant pump. Table 5.4-1 gives the design parameters.

actor coolant pump is directly connected to each of two outlet nozzles on the steam generator nnel head. The two pumps on a steam generator turn in the same direction.

alless pump contains the motor and all rotating components inside a pressure vessel. The sure vessel consists of the pump casing, stator closure, stator main flange, stator shell, stator er flange, and stator cap, which are designed for full reactor coolant system pressure. In a canned or pump, the stator and rotor are encased in corrosion-resistant cans that prevent contact of the r bars and stator windings by the reactor coolant. Because the shaft for the impeller and rotor is tained within the pressure boundary, seals are not required to restrict leakage out of the pump containment. The connection between the pump casing and the stator closure is provided with a ded canopy type seal assembly, which provides definitive leak protection for the pump closure.

ess to the internals of the pump and motor is by severing the canopy seal weld. When the pump assembled, a canopy seal is rewelded. Canned motor reactor coolant pumps have a long history afe, reliable performance in military and commercial nuclear plant service.

Staff approval is required prior to implementing a change in this information.

5.4-1 Revision 1

trolled portion of the reactor coolant circulating inside the motor and bearing cavity. The can on rotor isolates the copper rotor bars from the system and minimizes the potential for the copper to e out in other areas.

motor is cooled by primary reactor coolant system coolant circulating through the motor cavity by component cooling water circulating through a cooling jacket on the outside of the motor sing. Primary coolant used to cool the motor enters the lower end of the rotor and passes axially ugh the motor cavity to remove heat from the rotor and stator. An auxiliary impeller provides the ive force for circulating the coolant. Heat from the primary coolant is transferred to component lant water in an external heat exchanger.

h pump motor is driven by a variable speed drive, which is used for pump startup and operation n the reactor trip breakers are open. When the reactor trip breakers are closed, the variable uency drives are bypassed and the pumps run at constant speed.

heel assemblies provide rotating inertia that increases the coastdown time for the pump. Each heel assembly is of bi-metallic design consisting of a tungsten heavy metal alloy for mass with e 403 stainless steel and 18Mn-18Cr alloy steel structural components. The upper flywheel embly is located between the motor and pump impeller. The lower assembly is located below the ned motor, with the thrust bearing. Surrounding the flywheel assemblies are the heavy walls of stator closure, casing, thermal barrier, or stator lower flange.

materials in contact with the reactor coolant and cooling water (with the exception of the bearing erial) are austenitic stainless steel, nickel-chromium-iron alloy, or equivalent corrosion-resistant erial.

re are two journal bearings, one at the bottom of the rotor shaft and the other between the upper heel assembly and the motor. The bearings are a hydrodynamic film-riding design. During rotor tion, a thin film of water forms between the journal and pads, providing lubrication.

thrust bearing assembly is at the bottom of the rotor shaft. The pivoted pad hydrodynamic ring provides positive axial location of the rotating assembly regardless of operating conditions.

reactor coolant pump is equipped with a vibration monitoring system that continuously monitors p structure (frame) vibrations. Five vibration monitors provide pump vibration information. The dout equipment includes warning alarms and high-vibration level alarms, as well as output for lytical instruments.

r resistance temperature detectors (RTDs) monitor motor cooling circuit water temperature.

se detectors provide indication of anomalous bearing or motor operation, as well as leakage ugh the pump labyrinth seal into the stator cavity as a result of a leak in the pump external heat hanger. They also provide a system for automatic shutdown in the event of a prolonged loss of ponent cooling water or a large tube leak from the external heat exchanger into the CCS.

eed sensor monitors rotor rpms. Additionally, voltage and current sensors provide information on or load and electrical input.

1.2.2 Description of Operation ctor coolant is pumped by the main impeller. It is drawn through the eye of the impeller and harged via the diffuser out through the radial discharge nozzle in the side of the casing. Once the 5.4-2 Revision 1

auxiliary impeller at the lower part of the rotor shaft circulates a controlled volume of the primary lant through the motor cavity and external heat exchanger. The coolant is cooled to about 150°F omponent cooling water circulating on the shell side of the external heat exchanger. The cooled tor coolant then passes through the motor cavity, where it removes heat from the rotor and stator lubricates the motors hydrodynamic bearings.

variable frequency drives enable the startup of the reactor coolant pumps at slow speeds to rease the power required from the pump motor during operation at cold conditions. The variable uency drive provides operational flexibility during pump startup and reactor coolant system tup. During a plant startup, the general startup procedure for the pumps is for the operator to start pumps at a low speed. During reactor coolant system heatup, the pumps are run at the highest ed that is within the allowable motor current limits. As the reactor coolant temperature increases, allowable pump speed also increases. Before the reactor trip breakers are closed, the variable uency controllers are bypassed and the pumps run at constant speed.

ing all power operations (Modes 1 and 2), the variable frequency drives are bypassed and the ps run at constant speed.

1.3 Design Evaluation 1.3.1 Pump Performance reactor coolant pump is sized to deliver a flow rate that equals or exceeds the required flow rate.

ing prior to plant startup confirms the total delivery capability of the reactor coolant pump. See tion 14.2. Thus, adequate forced circulation coolant flow is confirmed prior to initial plant ration.

required net positive suction head is provided with ample margin to provide operational integrity minimize the potential for cavitation. The AP1000 does not require reactor coolant pump ration to achieve safe shut down. Minimum net positive suction head requirements are not uired to provide safe operation of the AP1000.

1.3.2 Overspeed Conditions ctor coolant pump overspeed can be postulated for either a fault in the connected electrical em that results in an increase in the frequency of the supplied current or due to a pipe rupture ch results in an increase in the flow through the pump as the coolant exits the pipe.

grid disconnect transients or turbine trips actuated by either the reactor trip system or the turbine ection system, the turbine overspeed control system acts to limit the reactor coolant pump rspeed. The turbine control system acts to rapidly close the turbine governor and intercept valves.

electrical fault requiring immediate generator trip (with resulting turbine trip) will result in an rspeed condition in the electrically coupled reactor coolant pump no greater than that described iously for the grid disconnect/turbine trip transient.

p overspeed from high coolant flow rates associated with pipe rupture events are mitigated by inertia of the pump, flywheel, and motor and by the connection of the motor to the electrical grid.

ause of the application of mechanistic pipe break criteria, dynamic effects such as pump rspeed are not evaluated for breaks in piping in which leak-before-break is demonstrated.

5.4-3 Revision 1

ditions. The pressure boundary components (pump casing, stator closure, stator main flange, or shell, stator lower flange, stator cap, and external piping and tube side of the external heat hanger) meet the requirements of the ASME Boiler and Pressure Vessel Code,Section III.

se components are designed, analyzed, and tested according to the requirements in agraph NB-3400 of the ASME Code,Section III. Wells provided for resistance temperature ctors and a phase reference sensor, and speed sensor penetrations also satisfy the uirements of the ASME Code,Section III.

motor terminals form part of the pressure boundary in the event of a stator-can failure. The ME Code does not include criteria or methods for completely designing or analyzing such inals. Motor terminals are designed, analyzed, and tested using criteria established and dated based on many years of service. Where applicable, ASME Code requirements and criteria used. Individual terminals are hydrostatically tested to test the integrity prior to performance ing.

1.3.4 Coastdown Capability important to reactor protection that the reactor coolant continues to flow for a time after reactor and loss of electrical power. To provide this flow, each reactor coolant pump has a high-density heel and high-inertia rotor. The rotating inertia of the pump, motor, and flywheel is used during coastdown period to continue the reactor coolant flow. The reactor coolant pump is designed for safe shutdown earthquake. The coastdown capability of the pump is maintained even for the e of loss of offsite and onsite electrical power coincident with the safe shutdown earthquake. Core transients and figures are provided in Subsections 15.3.1 and 15.3.2.

ss of component cooling water has no impact on coastdown capability. The reactor coolant pump operate without cooling water until a safety-related pump trip occurs on high bearing water perature. This prevents damage that could potentially affect coastdown.

reactor trip system maintains the pump operation within the assumptions used for loss of coolant analyses. This also provides that adequate core cooling is provided to permit an orderly uction in power if flow from a reactor coolant pump is lost during operation.

reactor coolant pump coastdown occurs on a power loss to the plant. The following conditions assumed to occur simultaneously:

Reactor coolant system at normal operation temperature and pressure, Loss of cooling water, Loss of pump power, Reactor trip e stator can should leak during operation, the reactor coolant may cause a short in the stator dings. In such a case, the result would be the same as a loss of power to that pump. With either a r or a stator can failure, no fluid would be lost to the containment.

5.4-4 Revision 1

vibration warning level and high-vibration level alarm set-points are, in part, based on evaluation e effect of vibration on bearing life.

bearings provide adequate stiffness to control shaft motion, protect the pump impeller and shaft rinths from wear, and avoid contact between the motor stator and rotor. The bearing loads are ntained within the load capabilities of hydrodynamic journal bearings even under the severe ditions experienced during seismic events. The bearing/shaft design and loadings are established nalysis and testing.

frame vibration detectors provide indication of bearing performance. Control room indicators and ms provide indication for operator action.

bearing cooling provisions include a temperature monitoring system. The system operates tinuously and has at least four redundant indicators per pump. Upon initiation of failure, the em indicates and alarms in the control room as a high bearing water temperature. All of the ps trip when the high temperature setpoint is reached.

1.3.6 Integrity of Rotating Components rotating components of the pump and motor are analyzed for dynamic characteristics, including ral frequencies, stability, and forced responses to normal operation loads, and for several tulated fault conditions associated with the rotating masses. The fault conditions include seized r events, and integrity of the rotating components, including the flywheel.

1.3.6.1 Natural Frequency and Critical Speeds damped natural frequency of the reactor coolant pump rotating assembly is greater than percent of the normal operating speed.

ermination of the damped natural frequency of the reactor coolant pump rotor bearing system el includes the effects of the bearing films, can annular fluid interaction, motor magnetic nomena, and pump structure. The damped natural frequencies for the AP1000 reactor coolant p exhibit sufficient energy dissipation to be stable. The high degree of damping provides smooth p operation.

pump is analyzed for the response of the rotor and stator to external forcing functions. The port and connection of the pump to the steam generator and piping are considered in the lysis. The responses are evaluated using criteria including critical loads, stress deformation, r, and displacement limits to establish the actual system critical speeds.

1.3.6.2 Rotor Seizure design of the pump is such as to preclude the instantaneous stopping of any rotating component e pump or motor. The rotating inertia and power supplied to the motor would overcome rference between the impeller, bearings, flywheel assemblies, motor rotor, or rotor can and the ounding components for a perid of time. A change in the condition of any of the components cient to cause an interference would be indicated by the instrumentation monitoring speed, ation, temperature, or current.

reactor coolant system and reactor coolant pump are analyzed for a locked rotor event. To lyze the mechanical and structural effects of a rapid slow down of the rotating assembly, a failure 5.4-5 Revision 1

tulated mechanisms for a rapid slowdown of the rotor, including impeller rub and rotor or stator failure. The connection of the pump with the steam generator and discharge piping is analyzed he vibration of the pump, hydraulic effects, and the torque due to the rapid slow down of the ting assembly. The stresses in the pump casing, motor housing, steam generator channel head, piping are analyzed using ASME Code,Section III, Service Level D limits for this condition.

transient analysis of thermal and hydraulic effects of a postulated locked rotor event is based on nmechanistic, instantaneous stop of the impeller. This conservative assumption bounds any er stop and provides a comparison with the same analysis done for other nuclear power plants.

transient analysis considers the effect of the locked rotor on the reactor core and the reactor lant system pressure. The results of the transient analysis are found in Chapter 15 and show that reactor coolant system pressure does not exceed the system design pressure.

1.3.6.3 Flywheel Integrity reactor coolant pump in the AP1000 complies with the requirement of General Design Criterion C) Number 4. That Criterion states that components important to safety be protected against the cts of missiles.

flywheel assemblies are located within and surrounded by the heavy walls of the stator closure, or main flange, casing, thermal barrier, or lower stator flange. In the event of a postulated worst-e flywheel assembly failure, the surrounding structure can, by a large margin, contain the energy e fragments without causing a rupture of the pressure boundary. The analysis in Reference 10 of capacity of the housing to contain the fragments of the flywheel is done using the energy orption equations of Hagg and Sankey (Reference 2).

pliance with the requirement of GDC 4 related to missiles can be demonstrated without rence to flywheel integrity, nevertheless, the intent of the guidelines of Regulatory Guide 1.14 is wed in the design and fabrication of the flywheel. The guidelines in Regulatory Guide 1.14 apply teel flywheels. Since the bi-metallic design of the AP1000 reactor coolant pump flywheel does not ond in the same manner as homogeneous steel, many of the guidelines in the Regulatory Guide not directly applicable.

reactor coolant pump flywheel assemblies are fabricated from a tungsten heavy alloy, e 403 stainless steel, and 18Mn-18Cr alloy steel (ASTM A289, Grade 8). Heavy alloy segments TM B777, Class 4) are fitted to a stainless steel hub (ASTM A336, Grade F6); these segments not relied upon structurally. The segments are held into place by an interference fit retainer nder of 18Mn-18Cr alloy steel placed over the outside of the assembly. The assembly is metically sealed from primary coolant by endplates and an outer thin shell of Alloy 625. Ni/Fe/Cr y 600 is not used for this application.

bi-metallic flywheel design will be manufactured using multiple processes and materials. In ordance with Regulatory Guide 1.14, each structural component of the bi-metallic flywheel will be ected prior to final assembly according to its fabrication and the procedures outlined in tion III, NB-2500 of the ASME Code. The Type 403 stainless steel inner hub material will be ject to impact testing using three Charpy V-notch tests per ASTM A370, magnetic particle mination per ASTM A788 Supplemental Requirement S18, and ultrasonic examination per M A788 Supplemental Requirement S20, Acceptance Levels BR and S. The retainer ring will be ject to fracture toughness testing per ASTM E399, magnetic particle examination per ASTM A788 plemental Requirement S18, and ultrasonic examination per ASTM A788 Supplemental uirement S20, Acceptance Levels BR and S. Following finishing operations on the flywheel 5.4-6 Revision 1

lity of the completed assemblies.

design speed of the flywheel is defined as 125 percent of the synchronous speed of the motor.

design speed envelopes all expected overspeed conditions. At the normal speed the calculated imum primary stress in the flywheel assemblies is less than one third of minimum yield strength.

he design speed the calculated maximum primary stress in the flywheel assemblies is less than thirds of minimum yield strength.

analysis of the flywheel failure modes of ductile failure, nonductile failure and excessive rmation of the flywheel is performed to evaluate the flywheel design. The analysis is performed etermine that the critical flywheel failure speeds, based on these failure modes, are greater than design speed. The critical flywheel failure speeds are not the same as the critical speed identified he rotor. The critical flywheel failure speeds are greater than the design speed. The overspeed dition for a postulated pipe rupture accident is less than the critical flywheel failure speeds.

flywheel assemblies are sealed within a welded nickel-chromium-iron alloy enclosure to prevent tact with the reactor coolant or any other fluid. The enclosure minimizes the potential for corrosion e flywheel and contamination of the reactor coolant. The enclosure material specifications are M-B-443 and ASTM-B-564. Even though the welds of the flywheel enclosure are not external sure boundary welds, these welds are made using procedures and specifications that follow the s of the ASME Code. A dye penetrant test of the enclosure welds is performed in conformance these requirements. The final assemblies are leak tested using a leak test hole located in the r hub.

credit is taken in the analysis of the flywheel missile generation for the retention of the fragments he enclosure. A leak in the enclosure during operation could result in an out-of-balance flywheel embly. An out-of-balance flywheel exhibits an increase in vibration, which is monitored by ation instrumentation.

flywheel enclosure contributes only a small portion of the energy in a rotating flywheel assembly.

stress in the welds of the flywheel enclosure components for normal and design speeds are in the criteria in subsection NG of the ASME Code, which is used as a guideline.

e rupture overspeed is based on a break of the largest branch line pipe connected to the reactor lant system piping that is not qualified for leak-before-break criteria. The exclusion of the reactor lant loop piping and branch line piping of 6 inches or larger size from the basis of the pump loss of lant accident overspeed condition is based on the provision in GDC 4 to exclude dynamic effects ipe rupture when a leak-before-break analysis demonstrates that appropriate criteria are sfied. See Subsection 3.6.3 for a discussion of leak-before-break analyses. The criteria of section 3.6.2 are used to determine pipe break size and location for those piping systems that do satisfy the requirements for mechanistic pipe break criteria.

ddition to material specification and non destructive testing requirement, each flywheel is subject spin test at 125 percent overspeed, followed by visual inspection, during manufacture. This onstrates quality of the flywheel. Since the basis for the safety of the flywheel is retention of the ments within the reactor coolant pump pressure boundary, periodic inservice inspections of the heel assemblies are not required to ensure that the basis for safe operation is maintained.

ause of the configuration of the flywheel assemblies, inservice inspection of the flywheel emblies may not result in significant inspection results. Inspection of the flywheel assemblies 5.4-7 Revision 1

ld not be consistent with goals relative to maintaining exposure as low as reasonably achievable.

, opening the pump may increase the potential for entry of foreign objects into the motor area.

these reasons, routine, periodic inspection of the flywheel assemblies in the AP1000 reactor lant pump is not recommended.

1.3.6.4 Other Rotating Components rotating components (other than the flywheel), including the impeller, auxiliary impeller, rotor, and r can, are evaluated for potential missile generation. In the event of fracture, the fragments from e components are contained by the surrounding pressure housing. The impeller is contained by pump casing. The rotor and rotor can are contained by the stator, stator can, and motor housing.

auxiliary impeller is contained by the motor housing. In each case, the energy of the postulated ments is less than that required to penetrate through the pressure boundary.

1.4 Tests and Inspections ctor coolant pump construction is subject to a quality assurance program. The pressure ndary components meet requirements established by the ASME Code. In addition, the flywheel is ject to quality assurance requirements. Table 5.4-3 outlines the inspection included in the reactor lant pump quality assurance program.

reactor coolant pump inservice inspection program is according to the ASME Code,Section XI.

design enables removal of the pump internals for inspection of the pump casing, if required. As d earlier, routine inspections of the impeller, flywheel, and motor internals are not required for operation of the pump.

1.4.1 Reactor Coolant System Flow Rate Verification al verification of the reactor coolant system flow rate is made during the plant initial test program.

ctor coolant system flow rates are measured during the pre-core load hot functional tests, and ng the startup tests. The objective of these tests is to verify that the reactor coolant system flow meets the flow rate range of Technical Specification 3.4.1.

r the pre-core reactor coolant system flow rate measurement is taken, analytical adjustments are e to the pre-core measured reactor coolant system flow rate to predict a post-core reactor lant system flow rate. Calculations of the reactor coolant system flow rate with and without the are performed. The calculation of the pre-core load reactor coolant system flow rate is pared with results of the pre-core load flow testing, and this information will be used in the ulation of the post-core load reactor coolant system flow rate as appropriate. The predicted t-core load reactor coolant system flow rate is checked to verify that it satisfies Technical cification 3.4.1. Verifications are also made that the post-core load reactor coolant system flow s satisfy Technical Specification 3.4.1 flow limits during startup testing.

2 Steam Generators 2.1 Design Bases steam generator channel head, tubesheet, and tubes are a portion of the reactor coolant sure boundary. The tubes transfer heat to the steam system while retaining radioactive taminants in the primary system. The steam generator removes heat from the reactor coolant 5.4-8 Revision 1

steam generator secondary shell functions as containment boundary during operation and ng shutdown when access opening closures are in place.

les 5.4-4 and 5.4-5 give steam generator design data. AP1000 equipment, seismic and ASME er and Pressure Vessel Code classifications of the steam generator components are discussed in tion 3.2. ASME Code and Code Case compliance are discussed in Subsection 5.2.1. The ASME e classification for the secondary side is specified as Class 2. The pressure-retaining parts of the m generator, including the primary and secondary pressure boundaries, are designed to satisfy criteria specified in Section III of the ASME Code for Class 1 components.

section 3.9.3 discusses the design stress limits, loads, and combined loading conditions.

section 3.9.1 discusses the transient conditions applicable to the steam generator. The number ansients is based on 60 years of operation.

ddition to the loading conditions associated with pressure and temperature variations for transient anticipated accident conditions, the steam generator is evaluated for fluid borne and structural ation originating with the reactor coolant pump. The steam generator is also evaluated for the on the primary outlet nozzles resulting from a postulated locked reactor coolant pump rotor. See section 5.4.1.3.6 for a discussion of the locked rotor postulation.

pter 11 gives estimates of radioactivity levels anticipated in the secondary side of the steam erators during normal operation and the bases for the estimates. Chapter 15 discusses the dent analysis of a steam generator tube rupture.

water chemistry on the primary side, selected to provide the necessary boron content for tivity control, should minimize corrosion of reactor coolant system surfaces. The effectiveness of water chemistry in the control of the secondary side corrosion is discussed in Chapter 10.

patibility of steam generator tubing with both primary and secondary coolants is discussed her in Subsection 5.4.2.4.3.

steam generator is designed to minimize the potential for mechanical or flow-induced vibration.

e support adequacy is discussed in Subsection 5.4.2.3.3. The tubes and tubesheet are analyzed confirmed to withstand the maximum accident loading conditions defined in Subsection 3.9.3.

her consideration is given in Subsection 5.4.2.3.4 to the effect of tube-wall thinning on accident dition stresses.

2.2 Design Description AP1000 steam generator is a vertical-shell U-tube evaporator with integral moisture separating ipment. Figure 5.4-2 shows the steam generator, indicating several of its design features.

design of the Model Delta-125 steam generator, except for the configuration of the channel head, milar to an upgraded Model Delta-75 steam generator. The Delta-75 steam generator has been ed in operation as a replacement steam generator.

am generator design features are described in the following paragraphs.

the primary side, the reactor coolant flow enters the primary chamber via the hot leg nozzle. The er portion of the primary chamber is elliptical and merges into a cylindrical portion, which mates to tubesheet. This arrangement provides enhanced access to all tubes, including those at the 5.4-9 Revision 1

apex of the head to the tubesheet.

reactor coolant flow enters the inverted U-tubes, transferring heat to the secondary side ng its traverse, and returns to the cold leg side of the primary chamber. The flow exits the steam erator via two cold leg nozzles to which the reactor coolant pumps are directly attached. A high-grity, nickel-chromium-iron (Alloy 690) weld is made to the nickel-chromium-iron alloy buttered s of these nozzles.

assive residual heat removal (PRHR) nozzle attaches to the bottom of the channel head of the 1 steam generator on the cold leg portion of the head. This nozzle provides recirculated flow the passive residual heat removal heat exchanger to cool the primary side under emergency ditions. A separate nozzle on one of the steam generator channel heads is connected to a line the chemical and volume control system. The nozzle provides for purification flow and makeup from the chemical and volume control system to the reactor coolant system.

AP1000 steam generator channel head has provisions to drain the head. To minimize deposits of oactive corrosion products on the channel head surfaces and to enhance the decontamination of e surfaces, the channel head cladding is machined or electropolished for a smooth surface. The ary manways provide enhanced primary chamber access compared to previous model steam erators.

uld steam generator replacement using a channel head cut be required, the arrangement of the 000 steam generator channel head facilitates steam generator replacement in two ways. It is pletely unobstructed around its circumference for mounting cutting equipment. And is long ugh to permit post-weld heat treatment with minimal effect of tubesheet acting as a heat sink.

tubes are fabricated of nickel-chromium-iron Alloy 690. The tubes undergo thermal treatment wing tube-forming operations. The tubes are tack-expanded, welded, and expanded over the full th of the tubesheet. Full depth expansion was selected because of its capability to minimize ondary water access to the tube-to-tube-sheet crevice. The method by which the tubes are anded into the tubesheet is determined based on consideration of the residual stresses and the ltant susceptibility of the tube to degradation. Residual stresses (and the expanded tubes ceptibility to degradation) are limited, in part, through tight control of the pre-expansion clearance ween the tube and tubesheet hole.

port of the tubes is provided by ferritic stainless steel tube support plates. The holes in the tube port plates are broached with a hole geometry to promote flow along the tube and to provide an ropriate interface between the tube support plate and the tube. Figure 5.4-3 shows the support e hole geometry. Anti-vibration bars installed in the U-bend portion of the tube bundle minimize potential for excessive vibration.

am is generated on the shell side, flows upward, and exits through the outlet nozzle at the top of vessel. Feedwater enters the steam generator at an elevation above the top of the U-tubes ugh a feedwater nozzle. The feedwater enters a feedring via a welded thermal sleeve connection leaves it through nozzles attached to the top of the feedring. The nozzles are fabricated of an y that is very resistant to erosion and corrosion with the expected secondary water chemistry and rate through the nozzles. After exiting the nozzles, the feedwater flow mixes with saturated water oved by the moisture separators. The flow then enters the downcomer annulus between the pper and the shell.

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uding appropriate pressure losses in the downcomer and the risers that lead to negative damping ors.

am generator bubble collapse water hammer has occurred in certain early pressurized water tor steam generator designs having feedrings equipped with bottom discharge holes. Prevention mitigation of feedline-related water hammer has been accomplished through an improved design operation of the feedwater delivery system. The AP1000 steam generator and feedwater system rporate features designed to eliminate the conditions linked to the occurrence of steam generator er hammer. The steam generator features include introducing feedwater into the steam generator n elevation above the top of the tube bundle and below the normal water level by a top discharge ring. The top discharge of the feedring helps to reduce the potential for vapor formation in the ring. This minimizes the potential for conditions that can result in water hammer in the feedwater ng. The feedwater system features (Subsection 10.4.7 discusses in more detail) designed to ent and mitigate water hammer include a short, horizontal or downward sloping feedwater pipe team generator inlet.

se features minimize the potential for trapping pockets of steam which could lead to water mer events.

tification and striping are reduced by an upturning elbow inside the steam generator which raises feedring relative to the feedwater nozzle. The elevated feedring reduces the potential for stratified by allowing the cooler, more dense feedwater to fill the nozzle/elbow arrangement before rising the feedring.

potential for water hammer, stratification, and striping is additionally reduced by the use of a arate startup feedwater nozzle. The startup feedwater nozzle is located at an elevation that is the e as the main feedwater nozzle and is rotated circumferentially away from the main feedwater zle. A startup feedwater spray system independent of the main feedwater feedring is used to duce startup feedwater into the steam generator. The layout of the startup feedwater piping udes the same features as the main feedwater line to minimize the potential for waterhammer.

startup feedwater system is used to introduce water into the secondary side of the steam erator as described in Subsection 10.4.7.2.3.

he bottom of the wrapper, the water is directed toward the center of the tube bundle by the lowest support plate. This recirculation arrangement serves to minimize the low-velocity zones having potential for sludge deposition.

he water passes the tube bundle, it is converted to a steam-water mixture. Subsequently, the m-water mixture from the tube bundle rises into the steam drum section, where centrifugal sture separators remove most of the entrained water from the steam. The steam continues to the ondary separators, or dryers, for further moisture removal, increasing its quality to a designed imum of 99.75 percent (0.25 percent by weight maximum moisture). Water separated from the m combines with entering feedwater and recirculates through the steam generator. A sludge ector located amidst the inner primary separator risers provides a preferred region for sludge ling away, from the tubesheet and tube support plates. The dry, saturated steam exits the steam erator through the outlet nozzle, which has a steam-flow restrictor. (See Subsection 5.4.4.)

2.3 Design Evaluation grity of the pressure retaining function of the steam generator is provided by compliance with the ME Code. The evaluation of the stress levels and fatigue usage for the steam generator pressure 5.4-11 Revision 1

service environment (velocity, chemistry, etc.) are employed throughout the design.

ting the heat transfer requirements and tube vibration and tube wall integrity requirements in ition to the ASME Code requirements is discussed in the following subsections:

2.3.1 Forced Convection steam generator transfers to the secondary coolant loop the heat generated during power ration in the reactor and by the reactor coolant pumps. The evaluation of the steam generator mal performance, including required heat transfer area and steam flow, uses conservative umptions for parameters such as primary flow rates and heat transfer coefficients. The effective t transfer coefficient is determined by the physical characteristics of the AP1000 steam generator the fluid conditions in the primary and secondary systems for the nominal 100 percent design

e. It includes a conservative allowance for fouling and uncertainty. Tables 5.4-4 and 5.4-5 show nominal design requirements and parameters. Table 5.1-1 lists additional parameters used to luate the steam generator design.

2.3.2 Natural Circulation Flow en the normal feedwater supply is not available, water may be supplied to the steam generators he startup feedwater system. The startup feedwater system is a nonsafety-related system that ides a nonsafety-related source of decay heat removal. In addition, the system is used during tup and shutdown and other times when the normal feedwater system is not available.

en the steam generator is supplied with water from the startup feedwater system, the steam erator has enough surface area and a small enough primary-side hydraulic resistance to remove ay heat from the reactor coolant by natural circulation without operation of the reactor coolant ps.

e passive residual heat removal system activates, the passive residual heat removal nozzle nection to the steam generator passes coolant flow from the passive residual heat removal heat hanger into the cold leg side of the channel head. Coolant is drawn through the reactor coolant ps into the cold legs and then into the reactor vessel.

2.3.3 Mechanical and Flow-Induced Vibration under Normal Operating Conditions ential sources of tube excitation are considered, including primary fluid flow within the U-tubes, hanically induced vibration, and secondary fluid flow on the outside of the U-tubes. The effects of ary fluid flow and mechanically induced vibration, including those developed by the reactor lant pump, are acceptable during normal operation. The primary source of potential tube radation due to vibration is the hydrodynamic excitation of the tubes by the secondary fluid. This a has been emphasized in both analyses and tests, including evaluation of steam generator rating experience.

ee potential tube vibration mechanisms related to hydrodynamic excitation of the tubes have been tified and evaluated. These include potential flow-induced vibrations resulting from vortex dding, turbulence, and fluid-elastic vibration mechanisms.

uniform, two-phase turbulent flow exists throughout most of the tube bundle. Therefore, vortex dding is possible only for the outer few rows of the inlet region. Moderate tube response caused ortex shedding is observed in some carefully controlled laboratory tests on idealized tube arrays.

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trolled laboratory conditions were unexpectedly reproduced in the steam generator.

w-induced vibrations due to flow turbulence are also small: Root mean square amplitudes are less allowances used in tube sizing. These vibrations cause stresses that are two orders of nitude below fatigue limits for the tubing material. Therefore, neither unacceptable tube wear nor ue degradation due to secondary flow turbulence is anticipated.

e fluid elastic excitation is potentially more significant than either vortex shedding or turbulence.

atively large tube amplitudes can feed back proportionally large tube driving forces if an instability shold is exceeded. Tube support spacing, in both the tube support plates in the straight leg region the anti-vibration bars in the U-bend region, provides tube response frequencies such that the ability threshold is not exceeded. This approach provides large margins against initiation of fluid tic vibration for tubes effectively supported by the tube support system.

all clearances between the tubes and the supporting structure are required for steam generator ication. These clearances introduce the potential that any given tube support location may not be lly effective in restraining tube motion if there is a finite gap around the tube at that location.

d-elastic tube response within available support clearances is therefore theoretically possible if ondary flow conditions exceed the instability threshold when no support is assumed at the tion with a gap around the tube. This potential has been investigated both with tests and lyses for both the U-bend and straight leg regions.

000 steam generator tube wear potential is expected to be within available design margins even imiting tube fit-up conditions, based on previous experience. The AP1000 steam generator udes a number of features that minimize the potential for tube wear at tube supports and vibration bars. Provisions to minimize the potential for wear include optimal spacing between the supports and the configuration of the anti-vibration bar assemblies. Tube wear is minimized in tube support plate design by the configuration of the broached hole through the support plate, the ace finish of the broached hole in the tube support plate, the clearance between the tube and the in the tube support plate, and tube support plate material selection.

e bending stresses corresponding to tube vibration response remain more than two orders of nitude below fatigue limits as a consequence of vibration amplitudes constrained by the tube ports. These analyses and tests for limiting postulated fit-up conditions include simultaneous tributions from flow turbulence.

outlined, analyses and tests demonstrate that unacceptable tube degradation resulting from tube ation is not expected for the AP1000 steam generators. Operating experience with steam erators having the same size tubes and similar flow conditions supports this conclusion.

U-bend fatigue (discussed in NRC Bulletin 88-02) is not a consideration in the AP1000 steam erators. The mechanism considered in Bulletin 88-02 requires denting of the top tube support

e. But this is not expected with the stainless steel tube support plates in the AP1000 steam erator. Additionally, the location of anti-vibration bars is controlled by in-process dimensional ection.

2.3.4 Allowable Tube Wall Thinning under Accident Conditions evaluation determined the extent of tube wall thinning that can be tolerated under accident ditions. The worst-case loading conditions are assumed to be imposed upon uniformly thinned 5.4-13 Revision 1

steam generator tubes, existing originally at their minimum wall thickness and reduced by a servative general corrosion and erosion loss, provide an adequate safety margin (sufficient wall kness) in addition to the minimum required for a maximum stress less than the allowable stress

, as defined by the ASME Code.

dies have been made on AP1000 sized tubing under accident loadings. The results show that the imum Level D Service condition stress due to combined pipe rupture and safe shutdown hquake loads is less than the allowable limit. The tube thickness required to achieve the eptable stress is less than the minimum AP1000 steam generator tube wall thickness, which is uced to account for assumed general corrosion and erosion rate. Thus, an adequate safety gin is exhibited. The general corrosion rate is based on a conservative weight-loss rate for y 690 TT tubing in flowing, 650°F primary-side reactor coolant fluid. The estimated weight loss, ed on testing when equated to a thinning rate and projected over a 60-year design objective, is h less than the assumed corrosion allowance of 3 mils. This leaves the remainder of the general osion allowance for thinning on the secondary side.

2.4 Steam Generator Materials 2.4.1 Selection and Fabrication of Materials pressure boundary materials used in the steam generator are selected and fabricated in ordance with the requirements of Section II and III of the ASME Code. Subsection 5.2.3 contains neral discussion of material specifications. Table 5.2-1 lists the types of materials. Fabrication of tor coolant pressure boundary materials is also discussed in Subsection 5.2.3, particularly in sections 5.2.3.3 and 5.2.3.4.

stry-wide corrosion testing and specification development programs have justified the selection ermally treated Alloy 690, a nickel-chromium-iron alloy (ASME SB-163), for the steam generator

s. The channel head divider plate is also Alloy 690 (ASME SB-168). The interior surfaces of the tor coolant channel head, nozzles, and manways are clad with austenitic stainless steel. The ary side of the tubesheet is weld clad with nickel-chromium-iron alloy (ASME SFA-5.14). The s are then seal welded to the tubesheet cladding. These fusion welds, comply with Sections III IX of the ASME Code. The welds are dye-penetrant inspected and leak-tested before each tube xpanded the full depth of the tubesheet bore.

el-chromium-iron alloy in various forms is used for parts where high velocities could otherwise to erosion/corrosion. These include the nozzles on the feedwater ring and startup feedwater rger.

section 5.2.1 discusses authorization for use of ASME Code cases used in material selection.

section 1.9.1 discusses the extent of conformance with Regulatory Guides 1.84, Design and rication Code Case Acceptability ASME Section III, Division 1.

ing manufacture, the primary and secondary sides of the steam generator are cleaned according ritten procedures following the guidance of Regulatory Guide 1.37, Quality Assurance uirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear er Plants, and ASME NQA-1 Part II. Onsite cleaning and cleanliness control also follow the ance of Regulatory Guide 1.37 (discussed in Subsection 1.9.1). Cleaning process specifications discussed in Subsection 5.2.3.4.

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e ASME Code.

heat and lot of tubing material for each steam generator tube is recorded and documented as of the quality assurance records. Archive samples of each heat and lot of steam generator tubing erial are provided for use in future materials testing programs or as inservice inspection bration standards. A minimum of 7 feet of tubing in the final heat treat condition is supplied.

exterior of the steam generator surface may be submerged following a postulated actuation of automatic depressurization system (ADS). During this event, water may be present on the ide of the steam generator without affecting the heat transfer or pressure boundary capabilities of AP1000 steam generator.

2.4.2 Steam Generator Design Effects on Materials eral features in the AP1000 steam generator minimize crevice areas and the deposition of taminants from the secondary-side flow. Such crevices and deposits could otherwise produce a l environment allowing potential chemical concentration and material corrosion.

portion of the tube within the tubesheet is expanded to close the crevice between the tube and sheet. The length of the expansion is carefully controlled to minimize the potential of an over-anded condition above the tubesheet and to minimize the extent of unexpanded tube at the top of tubesheet.

tube support plates are made of corrosion resistant Type 405 stainless steel alloy. A three-lobed, ifoil, tube hole design provides flow adjacent to the tube outer surface. This provides high eping velocities at the tube and tube support plate intersections. The trifoil tube support plate ides in-plane and out-of-plane strength. The sweeping velocities through the support plate uce sludge accumulation in the tube-to-tube support crevices. Figure 5.4-3 shows the trifoil ached holes. This support plate design contributes to a high circulation ratio. The increased flow a high circulation ratio circulation results in increased flow in the interior of the bundle, as well as zontal velocity across the tubesheet, which reduces the tendency for sludge deposition.

effect of the total bundle flow on the vibrational stability of the tube bundle has been analyzed, consideration given to flow-induced excitation frequencies. The maximum unsupported span th of tubing in the U-bend region and the optimal number of anti-vibration bars has been rmined, using advanced statistical techniques and vibration modeling. The anti-vibration bars are icated from Type 405 stainless steel. The construction minimizes the gaps between the anti-ation bars and tubes.

itional measures in the AP1000 steam generator design minimize areas of dryout in the steam erator and sludge accumulations in low-velocity areas. The wrapper design results in significant er velocities across the tubesheet.

gh capacity blowdown system is capable of continuous blowdown of the steam generators at a erate volume and intermittent flow. The intakes of the blowdown system are at the tube bundle phery.

assive sludge collector, which provides a low flow settling zone, is in the upper shell region ted among the inner primary moisture separator risers. The sludge collector, or mud drum, ides a location for particulate to settle remote from the tubesheet and tube support plates. The drum can be cleaned during a plant shutdown.

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ch access ports are provided for sludge lancing, inspection of the tube bundle by portable ection equipment, and retrieval of loose objects. They are located above the tubesheet 90° apart on the tubelane and two at 90° from the tube lane) to provide access to the secondary face of tubesheet. Also, a minimum of two 4-inch ports located on the secondary shell in line with the lane and above the top tube support plate provide access to the U-Bend area. A blowdown hole, ted at the bottom of the secondary side drain channel permits continuous blowdown and itoring of secondary water chemistry. The materials of the secondary side of the steam generator also compatible with chemical cleaning.

2.4.3 Compatibility of Steam Generator Tubing with Primary and Secondary Coolants industry corrosion tests mentioned in Subsection 5.4.2.4.1, subjected the steam generator ng material thermally treated Alloy 690 ASME SB-163, to simulated steam generator water mistry. These tests indicated that the loss due to general corrosion over the 60-year operating ign objective is small compared to the tube wall thickness. Testing to investigate the susceptibility eat exchanger construction materials to stress corrosion in caustic and chloride aqueous tions indicate that Alloy 690 TT provides as good or better corrosion resistance as either y 600 TT or nickel-iron-chromium Alloy 800. Alloy 690 TT also resists general corrosion in severe rating water conditions.

e operating experience has revealed areas on secondary surfaces where localized corrosion s were significantly greater than the low general corrosion rates. Both intergranular stress osion and tube wall thinning were experienced in localized areas, although not simultaneously at same location or under the same environmental conditions (water chemistry, sludge position).

all volatile treatment (AVT) control program minimizes the possibility of the tube wall thinning nomenon. Successful AVT operation requires maintenance of low concentrations of impurities in steam generator water. This reduces the potential for formation of highly concentrated solutions w-flow zones, which is a precursor of corrosion. By restricting the total alkalinity in the steam erator and prohibiting extended operation with free alkalinity, the all volatile treatment program imizes the possibility for intergranular corrosion in localized areas due to excessive levels of free stic.

oratory testing shows that Alloy 690 TT tubing is compatible with the AVT environment.

hermal corrosion testing in high-purity water shows that Alloy 690 TT exhibiting normal rostructure tested at normal engineering stress levels is not susceptible to intergranular stress osion cracking in extended exposure to high-temperature water. These tests also show that no eral type corrosion occurred. Field experience with Alloy 690 TT tubing in operation since 1989 been excellent.

el boiler tests evaluate similar AVT chemistry guidelines adopted by Westinghouse and EPRI.

formance to the guidelines enhances tube corrosion performance. The secondary water mistry guidelines for AP1000 are found in Chapter 10. Action levels for secondary side water mistry during power operation are given in Table 10.3.5-1. Extensive operating data has been umulated for all volatile treatment chemistry.

mprehensive program of steam generator inspections, including the recommendations of ulatory Guide 1.83, Inservice Inspection of Pressurized Water Reactor Steam Generator Tubes, 5.4-16 Revision 1

uded with the standard operating condition water chemistry controls are chemistry controls during power (including shutdown, no-load, heatup, cooldown, and refueling operations). The startup water nozzle may be used to supply hydrazine, ammonia, and other chemicals to control ondary pH and oxygen during wet layup. This nozzle, in combination with the blowdown line, can be used to remove sensible heat from the steam generator during cooldown. Sparging the steam erator with nitrogen through the blowdown line also promotes secondary recirculation at zero er. This recirculation can be used, in conjunction with the addition of cleaning agents into the ondary side, to remove magnetite, copper, or other deposited contaminants. The AP1000 steam erator is also configured for pressure pulse cleaning and water slap methods to remove deposits he secondary side.

h margins against primary water stress corrosion cracking exist with the specification of thermally ted Alloy 690 tubing. Alloy 690 TT is resistant to primary water stress corrosion cracking over the ge of anticipated operating environments. The tubing is thermally treated according to a ratory-derived treatment process and is generally consistent with industry-accepted and EPRI edures.

tube support plates are fabricated of ferritic stainless steel. Laboratory tests show that this erial is resistant to corrosion in the AVT environment. If corrosion of ferritic stainless steel were to ur because of the concentration of contaminants, the volume of the corrosion products is entially equivalent to the volume of the parent material consumed. This would be expected to lude denting. The support plates are also designed with trifoil tube holes rather than cylindrical

s. The trifoil tube hole (see Figure 5.4-3) design promotes high velocity flow along the tube and is ected to minimize the accumulation of impurities at the support plate location.

2.5 Steam Generator Inservice Inspection steam generator is designed to permit inspection of pressure boundary parts, including individual

s. Preservice inspection of the AP1000 steam generators is performed according to the ASME

e. Inservice inspection complies with the requirements of 10 CFR 50.55a.

design includes a number of openings to provide access to both the primary and secondary s of the steam generator. The openings include four 18-inch diameter manways, one for access ach chamber of the reactor coolant channel head and two in the steam drum for inspection and ntenance of the upper shell internals. In addition, there are a minimum of four 6-inch diameter dholes in the shell, located just above the tubesheet secondary surface are provided. A minimum wo 4-inch diameter inspection openings are provided at each end of the tubelane between the er tube support plate and the row 1 tubes. Additional access to the tube bundle U-bend is ided through the internal deck plate at the bottom of the primary separators. For proper tioning of the steam generator, some of the deck-plate openings are covered with hatch plates ded in place that are removable by grinding, gouging, or other methods to cut off the welds.

ulatory Guide 1.83 provides recommendations on the inspection of tubes. The recommendations er inspection equipment, baseline inspections, tube selection, sampling and frequency of ection, methods of recording, and required actions based on findings. Any eddy current ection performed in the manufacturing facility is conducted by personnel qualified to the uirements for inspectors performing inservice inspection of operating units. The manufacturing ity inspection is conducted using the same equipment as, or equipment similar to, that used ng inservice inspection of operating units. Exceptions to Regulatory Guide 1.83 are noted in section 1.9.1.

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m generator includes features to enhance robotics inspection of steam generator tubes without ned entry of the channel head. These include a cylindrical section of the channel head, primary ways, and provisions to facilitate the remote installation of nozzle dams. Computer simulation g designs of existing robotically delivered inspection and maintenance equipment verifies that s can be accessed. To facilitate tube identification for manual activities, the tube location for a tion of the tubes is scribed on the tubesheet.

minimum requirements for inservice inspection of steam generators, including tube repair ria, are discussed in Subsection 5.4.15 considering NRC requirements and industry mmendations. The steam generator tube integrity is verified in accordance with a Steam erator Tube Surveillance Program. The Steam Generator Tube Surveillance Program is ussed in Subsection 5.4.15.Section XI of the ASME Code provides general acceptance criteria ndications of tube degradation in the steam generator.

eam generator tube surveillance program is implemented in accordance with the mmendations and guidance of Nuclear Energy Institute (NEI) 97-06, Steam Generator Program delines (Reference 201). A program for periodic monitoring of degradation of steam generator rnals is also implemented in accordance with NEI 97-06. Applicable Electric Power Research itute (EPRI) Steam Generator Management Program (SGMP) guidelines are followed as cribed in the NEI 97-06. The Programs are in compliance with applicable sections of ASME tion XI.

97-06 and the referenced EPRI SGMP guidelines provide recommendations concerning the ection of tubes, which cover inspection equipment, baseline inspections, tube selection, pling and frequency of inspection, methods of recording, required actions based on findings, and plugging. The minimum requirements for inservice inspection of steam generators, including ging criteria, are established in Technical Specification 5.5.4.

tube surveillance and degradation monitoring programs include provisions to maintain the patibility of steam generator tubing with primary and secondary coolant to limit the steam erators susceptibility to corrosion. These provisions are in accordance with NEI 97-06.

2.6 Quality Assurance steam generator is constructed to a quality assurance program that meets the requirements of ASME Code and ASME NQA-1-1994 Edition. Table 5.4-6 outlines the testing included in the m generator quality assurance program.

radiographic inspection and acceptance standard comply with the requirements of Section III of ASME Code per applicable Code Year and Addenda.

id penetrant inspection and acceptance standards comply with the requirements of Section III of ASME Code per applicable Code Year and Addenda. Liquid penetrant inspection is performed on d-deposited tubesheet cladding, channel head cladding, divider-plate-to-tubesheet and to nnel head weldments, tube-to-tubesheet weldments, and weld-deposit cladding.

netic particle inspection and acceptance standards comply with the requirements of Section III of ASME Code per applicable Code Year and Addenda. Magnetic particle inspection is performed he tubesheet forging, channel head forging, nozzle forging, and the following weldments:

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Instrument connection (secondary)

Temporary attachments, after removal Accessible pressure retaining welds after hydrostatic test asonic inspection and acceptance standards comply with the requirements of Section III of the ME Code per applicable Code Year and Addenda. Ultrasonic tests are performed on the sheet forgings, tubesheet cladding, secondary shells and heads plates and forgings, and nozzle ings.

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

rostatic tests comply with Section III of the ASME Code.

-destructive examination of pressure boundary and associated weldments will be performed in ordance with the applicable Code Year and Addenda of ASME Section III, Subsections NB NC.

3 Reactor Coolant System Piping 3.1 Design Bases reactor coolant system piping accommodates the system pressures and temperatures attained er all expected modes of plant operation or anticipated system interactions. The piping in the tor coolant system is AP1000 equipment Class A (ANS Safety Class 1, Quality Group A) (see section 3.3.2) and is designed and fabricated according to ASME Code,Section III, Class 1 uirements. Lines with a 3/8-inch or less flow restricting orifice qualify as AP1000 equipment ss B (ANS Safety Class 2, Quality Group B) and are designed and fabricated with ASME Code, tion III, Class 2 requirements. If one of these lines breaks, the chemical volume control charging ps are capable of providing makeup flow while maintaining pressurizer water level. Stresses are ntained within the limits of Section III of the ASME Code. Code and material requirements are ided in Section 5.2. Inservice inspection of Class 1 components is discussed in section 5.2.4.

erials of construction are specified to minimize corrosion/erosion and to provide compatibility with operating environment including the expected radiation level. The welding, cutting, heat treating other processes used to minimize sensitization of stainless steel are discussed in section 5.2.3.

thickness of reactor coolant system piping satisfies the design requirements of the ASME Code, tion III, Subsection NB. The analysis of piping of nominal pipe size of 6 inches or greater which onstrates leak-before-break characteristics, as outlined in Subsection 3.6.3, does not include s due to the dynamic effects of pipe rupture. The minimum pipe bend radius is 1.5-nominal pipe meters, and ovality meets the requirements of the ASME Code.

welds, branch connection nozzle welds, and boss welds are of a full-penetration design. Flanges form to ANSI B16.5. Socket weld fittings and socket joints conform to ANSI B16.11.

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reactor coolant system piping includes those sections of reactor coolant hot leg and cold leg ng interconnecting the reactor vessel, steam generators, and reactor coolant pumps. It also udes piping connected to the reactor coolant loop piping and primary components. Figure 5.1-5 ws the Piping and Instrumentation Drawing (P&ID) of the reactor coolant system. The boundary e reactor coolant system includes the second of two isolation or shut off valves and the piping ween those valves. A single ASME Code safety valve may also represent the boundary of the tor coolant system. The connected piping in the reactor coolant system includes the following:

Chemical and volume control system (CVS) purification return line from the system isolation valve up to a nozzle on the steam generator channel head Chemical and volume control system purification line from the branch connection on the pressurizer spray line to the system isolation valve Pressurizer spray lines from the reactor coolant cold legs up to the spray nozzle on the pressurizer vessel Normal residual heat removal system (RNS) pump suction line from one reactor coolant hot leg up to the designated isolation valve Normal residual heat removal system discharge line from the designated check valve to the connection to the core makeup tank return lines to the reactor vessel direct injection nozzle Accumulator lines from the designated check valve to the reactor vessel direct injection nozzle Passive core cooling system (PXS) lines from the cold legs to the core make-up tanks and back to the reactor vessel direct injection nozzles Drain, sample and instrument lines to the designated isolation valve.

Pressurizer surge line from one reactor coolant loop hot leg to the pressurizer vessel surge nozzle Pressurizer spray scoop, reactor coolant temperature element installation boss, and the temperature element well itself All branch connection nozzles attached to reactor coolant loops Pressure relief lines in the pressurizer safety and relief valve module from nozzles on top of the pressurizer vessel up to and including the pressurizer safety valves Automatic depressurization system (ADS) lines from the pressurizer relief lines to the stages 1, 2, and 3 automatic depressurization system valves Automatic depressurization system lines from the connection with the hot leg up to the fourth stage valves Auxiliary spray line from the isolation valve up to the main pressurizer spray line 5.4-20 Revision 1

Vent line from the reactor vessel head to the system isolation valves In-containment refueling water storage tank injection lines from the designated valves to the reactor vessel direct injection nozzle le 5.4-7 gives principal design data for the reactor coolant piping.

scussion of the codes used in the fabrication of reactor coolant piping and fittings appears in tion 5.2.

ctor coolant system piping is fabricated of austenitic stainless steel. The piping is forged mless without longitudinal or electroslag welds. It complies with the requirements of the ASME e,Section II (Parts A and C),Section III, and Section IX. The reactor coolant system piping does contain any cast fittings. Changes in direction are accomplished in most cases using bent pipe ead of elbows to minimize the number of welds, fittings, and short radius turns.

3.2.2 Piping Connections ts and connections are welded, except for the pressurizer safety valves, the reactor head vent miscellaneous vents and drains, and orifice flanges, where flanged joints are used. Fillet welds be used to connect small instrument lines to socket weld connections. Piping connections for iliary systems are above the horizontal centerline of the reactor coolant loop piping, except for the wing:

The residual heat removal pump suction line, which is located at the bottom of a hot leg pipe.

This enables the water level in the reactor coolant system to be lowered in the reactor coolant loop pipe while continuing to operate the residual heat removal system, should this be required for maintenance.

The pressurizer level channel nozzles with a 0.375-inch or less flow restrictor and the hot leg level channel nozzle with a 0.375-inch flow restrictor located in the hot leg piping.

The sample connection located at 45 degrees below the horizontal centerline of each hot leg.

The cold leg-narrow range thermowells attached at the horizontal centerline.

The wide-range thermowell tap and three of the six narrow-range thermowell taps in each hot leg.

3.2.3 Encroachment into Coolant Flow s encroaching into the primary coolant loop flow path are limited to the following:

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 narrow-range and wide-range temperature detectors are in resistance temperature detector wells that extend into both the hot and cold legs of the reactor coolant loop piping.

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tor coolant system piping and supports for design conditions, normal conditions, anticipated sients, and postulated accident conditions are discussed in Subsection 3.9.3. The requirements dynamic testing and analysis are discussed in Subsection 3.9.2. The reactor coolant system ign transients for normal operation, anticipated transients and postulated accident conditions are ussed in Subsection 3.9.1.

pressurizer surge line has been specifically designed and instrumented to minimize the potential hermal stratification that could increase cyclic stresses and fatigue usage. At the connection of surge line to the hot leg, the surge line is sloped 24 degrees from horizontal. The connection to reactor coolant hot leg is in the portion of the loop piping that is at an angle with horizontal and cent to the steam generator inlet nozzle. The run between the hot leg and pressurizer tinuously slopes up. The surge line has an angle of at least 2.5 degrees to horizontal. The surizer surge line is shown in Figure 5.4-4. Changes of direction in the surge line are made using bends instead of elbow fittings.

surge line temperature is monitored for indication of thermal stratification. The temperature is itored at three locations using strap-on resistance temperature detectors. One location is on the ical section of pipe directly under the pressurizer. The other two locations are on the top and om of the pipe at the same diameter on a more horizontal section of pipe near the pressurizer.

peratures in the spray lines from the cold legs of one loop are measured and indicated. Alarms these signals actuate to warn the operator of low spray water temperature or to indicate fficient flow in the spray lines.

3.4 Material Corrosion/Erosion Evaluation pipe material is selected to minimize corrosion in the reactor coolant water chemistry. (See section 5.2.3.) A periodic analysis of the coolant chemistry is performed to verify that the reactor lant water quality meets the specifications. Water quality is maintained to minimize corrosion by g the chemical and volume control system and sampling system, described in Chapter 9.

tamination of stainless steel and nickel-chromium-iron alloys by copper, low-melting-temperature ys, mercury, and lead is prohibited during fabrication, installation, and operation.

austenitic stainless steel surfaces are cleaned to an appropriate halogen limit. The austenitic nless steel piping is very resistant to erosion due to single-phase fluid flow. The flow rate in the tor coolant loop piping and branch connections during normal operation and anticipated sients is significantly below the threshold value for erosion due to water for austenitic stainless l.

material selection, water chemistry specification, and residual stress in the piping minimize the ntial for stress corrosion cracking. (See Subsection 5.2.3.) Reactor coolant system piping is ss-relieved subsequent to bending or other fabrication operations which could result in significant dual stress in the pipe. Processes such as welding or heat treating which apply heat to stainless l are controlled to minimize the potential for sensitization of the stainless steel.

ssure boundary welds out to the second valve that delineates the reactor coolant system ndary are accessible for inservice examination as required by ASME Code,Section XI, and are d with removable insulation. Reactor coolant system piping is seamless and does not have any itudinal welds.

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sure boundary components meet requirements established by the ASME Code and ME NQA-1. The testing included in the reactor coolant system piping quality assurance program is ined in Table 5.4-8.

ansverse tension test conforming with the supplementary requirements S2 of material cification ASME SA-376 applies to each heat of pipe material.

asonic examination is performed throughout 100 percent of the wall volume of each pipe, fitting, other forgings according to the applicable requirements of Section III of the ASME Code for tor coolant system piping. Unacceptable defects are eliminated according to the requirements of ASME Code. The surfaces of weld areas are smooth enough to permit preservice and inservice

-destructive examination.

ends of pipe sections and branch ends are machined to provide a smooth weld transition cent to the weld.

uid penetrant examination is performed on accessible surfaces, including weld surfaces, of each hed pipe and fitting according to the criteria of the ASME Code,Section III. Acceptance dards are according to the applicable requirements of the ASME Code,Section III. Liquid etrant examinations are done on the area of pipe bends before the bending operation and after subsequent heat treatment. Since reactor coolant system piping is austenitic stainless steel, netic particle testing for surface examination is not an option. Fillet weld joints are examined by d penetrant examination method.

iographic examination is performed on circumferential butt welds and on branch connection zle welds exceeding 4-inch nominal pipe size.

examination of a weld repair is repeated as required for the original weld. Except, when the ct was originally detected by the liquid penetrant method, and when the repair cavity does not eed the lesser of 0.38 inch or 10 percent of the thickness, it need be re-examined only by the d penetrant method.

4 Main Steam Line Flow Restriction 4.1 Design Bases outlet nozzle of the steam generator has a flow restrictor that limits steam flow in the unlikely nt of a break in the main steam line. A large increase in steam flow results in choked flow in the rictor which limits further increase in flow. In a steam line qualified for mechanistic pipe break, a den rupture resulting in a large increase in steam flow is not expected. The flow restrictor orms the following functions:

Limits rapid rise in containment pressure Limits the rate of heat removal from the reactor to keep the cooldown rate within acceptable limits Reduces thrust forces on the main steam line piping Limits pressure differentials on internal steam generator components, particularly the tube support plates 5.4-23 Revision 1

4.2 Design Description flow restrictor consists of seven nickel-chromium-iron Alloy 690 (ASME SB-564) venturi inserts ch are installed in holes in an integral steam outlet nozzle forging. The inserts are arranged with venturi at the centerline of the outlet nozzle, and the other six are equally spaced around it. After rtion into the nozzle forging holes, the venturi inserts are welded to the nickel-chromium-iron y buttering on the inner surface of the forging.

4.3 Design Evaluation flow restrictor design has been analyzed to determine its structural adequacy. The equivalent at area of the steam generator outlet is 1.4 square feet. The resultant pressure drop through the rictor at 100 percent steam flow is approximately 20 psi. This is based on a design flow rate of x 106 pounds per hour. Materials of construction of the flow restrictor are in accordance with e Class 1 Section III of the ASME Code. The material of the inserts is not an ASME Code sure boundary, nor is it welded to an ASME Code pressure boundary. The method for seismic lysis is dynamic.

4.4 Inspections e the restrictor is not part of the steam system pressure boundary, inservice inspections are not uired.

5 Pressurizer pressurizer provides a point in the reactor coolant system where liquid and vapor are maintained quilibrium under saturated conditions for pressure control of the reactor coolant system during dy-state operations and transients. The pressurizer provides a controlled volume from which l can be measured.

pressurizer contains the water inventory used to maintain reactor coolant system volume in the nt of a minor system leak for a reasonable period without replenishment. The pressurizer surge connects the pressurizer to one reactor coolant hot leg. This allows continuous coolant volume pressure adjustments between the reactor coolant system and the pressurizer.

5.1 Design Bases pressurizer is sized to meet following requirements:

The combined saturated water volume and steam expansion volume is sufficient to provide the desired pressure response to system volume changes.

The water volume is sufficient to prevent a reactor trip during a step-load increase of 10 percent of full power, with automatic reactor control.

The water volume is sufficient to prevent uncovering of the heaters following reactor trip and turbine trip, with normal operation of control systems and no failures of nuclear steam supply systems.

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The steam volume is large enough to prevent water relief through the safety valves following a complete loss of load with the high water level initiating a reactor trip, without steam dump.

A low pressurizer pressure engineered safety features actuation signal will not be activated because of a reactor trip and turbine trip, assuming normal operation of control and makeup systems and no failures of the nuclear steam supply systems.

pressurizer is sized to have sufficient volume to accomplish the preceding requirements without er-operated relief valves. The AP1000 pressurizer has approximately 40 percent more volume the pressurizers for previous plants with similar power levels. This increased volume provides t operating flexibility and minimizes challenges to the safety relief valves.

pressurizer and surge line provide the connection of the reactor coolant system to the safety f valves and the automatic depressurization system valves. The safety relief valves provide rpressure protection for the reactor coolant system. The automatic depressurization system is ided to reduce reactor coolant system pressure in stages to allow stored water in the ontainment refueling water storage tank to flow into the reactor coolant system to provide cooling.

pressurizer surge nozzle and the surge line between the pressurizer and one hot leg are sized to ntain the pressure drop between the reactor coolant system and the safety valves within wable limits during a design discharge flow from the safety valves or the valves of the automatic ressurization system. Requirements for the surge line and piping connecting the pressurizer to ty and automatic depressurization valves is discussed in Subsection 5.4.3.

tion 3.2 discusses the AP1000 equipment classification, seismic category and ASME Code sification of the pressurizer. ASME Code and Code Case compliance is discussed in section 5.2.1.

design stress limits, loads, and combined loading conditions are discussed in Subsection 3.9.3.

ign transients for the components of the reactor coolant system are discussed in section 3.9.1. The pressurizer surge nozzle and surge line are designed to withstand the thermal sses resulting from volume surges occurring during operation. The evaluation of design sients for the pressurizer addresses the potential for thermal stratification at the surge nozzle.

pressurizer provides a location for high point venting of noncondensable gases from the reactor lant system. The gas accumulations in the pressurizer can be removed by remote manual ration of the first-stage automatic depressurization system valves following an accident.

assing of the pressurizer using the automatic depressurization valves will not be required on a ine basis for normal and moderate frequency events. See Subsection 5.4.12 for a discussion of

-point vents.

5.2 Design Description 5.2.1 Pressurizer pressurizer is a vertical, cylindrical vessel having hemispherical top and bottom heads structed of low alloy steel. Internal surfaces exposed to the reactor coolant are clad austenitic nless steel. Material specifications are provided in Table 5.2-1 for the pressurizer.

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spray line nozzles and the automatic depressurization and safety valve connections are located e top head of the pressurizer vessel. Spray flow is modulated by automatically controlled air-rated valves. The spray valves can also be operated manually from the control room. In the om head at the connection of the surge line to the surge nozzle a thermal sleeve protects the zle from thermal transients.

taining screen above the surge nozzle prevents passage of any foreign matter from the surizer to the reactor coolant system. Baffles in the lower section of the pressurizer prevent an urge of cold water from flowing directly to the steam/water interface. The baffles also assist in ng the incoming water with the water in the pressurizer. The retaining screen and baffles also act diffuser. The baffles also support the heaters to limit vibration.

tric direct-immersion heaters are installed in vertically oriented heater wells located in the surizer bottom head. The heater wells are welded to the bottom head and form part of the sure boundary. The heaters can be removed for maintenance or replacement.

heaters are grouped into a control group and backup groups. The heaters in the control group proportional heaters which are supplied with continuously variable power to match heating ds. The heaters in the backup group are either off or at full power. The power supply to the ters is a 480-volt 60 Hz. three-phase circuit. Each heater is connected to one leg of a delta-nected circuit and is rated at 480 volts with one-phase current. The capacity of the control and kup groups is defined in Table 5.4-10.

anway in the upper shell provides access to the internal space of the pressurizer in order to ect or maintain the spray nozzle. The manway closure is a gasketed cover held in place with aded fasteners. Periodic planned inspections of the pressurizer interior are not required.

ckets on the upper shell attach the structure (a ring girder) of the pressurizer safety and relief e (PSARV) module. The pressurizer safety and relief valve module includes the safety valves the first three stages of automatic depressurization system valves. The support brackets on the surizer represent the primary vertical load path to the building structure. Sway struts between the girder and pressurizer compartment walls also provide lateral support to the upper portion of the surizer. See Subsection 5.4.10 for additional details.

r steel columns attach to pads on the lower head to provide vertical support for the vessel. The mns are based at elevation 107'-2". Lateral support for the lower portion of the vessel is provided way struts between the columns and compartment walls.

AP1000 pressurizer has metallic reflective insulation (MRI) installed on the external surfaces.

insulation is designed to reduce heat losses from the pressurizer, to reduce heat load on the tainment cooling system, and to limit temperatures in nearby concrete or components. During mal operating conditions, the insulation has an average maximum heat transfer rate of BTU/hr-ft2 at a containment design temperature of 120°F.

5.2.2 Instrumentation rument connections are provided in the pressurizer shell to measure important parameters. Eight l taps are provided for four channels of level measurement. Level taps are also used for nection to the pressure measurement instrumentation. Two temperature taps monitor water/

m temperature. A sample tap connection is provided for connection to the sampling system to 5.4-26 Revision 1

Chapter 7 for details of the instrumentation associated with pressurizer pressure, level, and perature.

5.2.3 Operation ing steady-state operation at 100 percent power, approximately 50 percent of the pressurizer me is water and 50 percent is steam. Electric immersion heaters in the bottom of the vessel keep water at saturation temperature. The heaters also maintain a constant operating pressure.

mall continuous spray flow is provided through a manual bypass valve around each power-rated spray valve to minimize the boron concentration difference between the pressurizer liquid the reactor coolant. This continuous flow also prevents excessive cooling of the spray piping.

portional heaters in the control group are continuously on during normal operation to compensate he continuous introduction of cooler spray water and for losses to ambient.

se conditions result in a continuous outsurge in most cases during normal operation and cipated transients. The outsurge minimizes the potential for thermal stratification in the surge line.

ing an outsurge of water from the pressurizer, flashing of water to steam and generation of steam utomatic actuation of the heaters keep the pressure above the low-pressure engineered safety ures actuation setpoint. During an in-surge from the reactor coolant system, the spray system ich is fed from two cold legs) condenses steam in the pressurizer. This prevents the pressurizer sure from reaching the high-pressure reactor trip setpoint. The heaters are energized on high er level during in-surge to heat the subcooled surge water entering the pressurizer from the tor coolant loop.

ing heatup and cooldown of the plant, when the potential for thermal stratification in the surizer is the greatest, the pressurizer may be operated with a continuous outsurge of water from pressurizer. This is achieved by continuous maximum spray flow and energizing of all of the kup pressurizer heater groups. The temperature difference between the pressurizer and hot leg is imized by maintaining the lowest reactor coolant system pressure possible consistent with ration of a reactor coolant pump. This mode of operation minimizes the frequency and magnitude ermal shock to the surge line nozzle and lower pressurizer head, and the potential for tification in the pressurizer and surge line. The design analyses of the pressurizer include sideration of transients on the lower head and shell regions to account for these possible insurge/

urge events.

pressurizer is the initial source of water to keep the reactor coolant system full of water in the nt of a small loss of coolant. Pressurizer level and pressure measurements indicate if other rces of water, including the chemical volume and control system and passive safety systems, t be used to supply additional reactor coolant.

er to the pressurizer heaters is blocked when the core makeup tanks are actuated. This action uces the potential for steam generator overfill for a steam generator tube rupture accident.

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reactor coolant system pressure is controlled by the pressurizer whenever a steam volume is ent in the pressurizer.

sign basis safety limit has been set so that the reactor coolant system pressure does not exceed maximum transient value based on the design pressure as allowed under the ASME Code, tion III. Evaluation of plant conditions of operation considered for design indicates that this safety is not reached. The safety valves provide overpressure protection. See Subsection 5.2.2.

ing startup and shutdown, the rate of temperature change in the reactor coolant system is trolled automatically by the steam dump system. Heatup rate is controlled by energy input from reactor coolant pumps and by the modulation of the steam dump valves. Pressurizer heatup rate ontrolled by the electrical heaters in the pressurizer.

en the pressurizer is filled with water, i.e., during initial system heatup or near the end of the ond phase of plant cooldown, reactor coolant system pressure is controlled by the letdown rate.

AP1000 pressurizer heaters are powered from the 480 V ac system. During loss of offsite power nts concurrent with a turbine trip, selected pressurizer heater buses are capable of being ered from the onsite diesel generators via manual alignment. This permits use of the pressurizer ontrol purposes when power is supplied by the diesel-generators. The power supplied by the el-generators is sufficient to establish and maintain natural circulation in hot standby condition in formance with the requirement of 10 CFR 50.34 (f)(2)(xiii).

ss of offsite power occurs and onsite power is available, the pressurizer heaters and startup water pumps can operate to provide natural circulation and cooling through the steam erators.

uld the onsite diesel generators not be available during loss of offsite power events, core decay t is removed from the reactor coolant system using the passive residual heat removal heat hanger. The decay heat is transferred to the in-containment refueling water storage tank (IRWST) er. The passive core cooling system does not require the use of pressurizer heaters to maintain sure control. The passive containment cooling system functions to maintain the plant in a safe dition.

REG-0737, Action Item II.E.3.1, outlines four requirements for emergency power supply to the surizer heaters for purposes of establishing natural circulation in the reactor coolant system ng a loss of offsite power. NUREG-0737 does not address scenarios involving natural circulation ling for a loss of all ac power, which is a design basis for the AP1000. Under these circumstances, ling is provided by the passive residual heat removal system. Upon a loss of all ac power, the ters are not available to maintain the pressurizer inventory in a saturated condition. That dition is not needed for the plant to be maintained in a safe condition. On this basis, compliance the requirements of the action item is not required to provide for the safety of the AP1000.

ertheless, AP1000 compliance with the intent of these requirements is summarized in the wing paragraphs.

heaters are powered from separate electrical buses for each heater group. Two groups of ters can be administratively loaded onto the non-Class 1E diesel-generator-backed buses ure 8.3.1-1).

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lant system pressure and subcooling.

ablished administrative procedures are followed for re-energizing groups. Associated actions can ontrolled from either the main control room or the shutdown panel. It is not necessary to shed r loads in order to manually load a heater group.

ed on analysis of other pressurizer water reactors, the reactor coolant system sensible heat acity is such that adequate subcooling can be maintained in the reactor coolant system for four rs without heat input from the pressurizer heaters. Thus, the time required to accomplish nection of the heaters to the emergency buses is consistent with timely initiation of natural ulation conditions.

e the buses supplying the heaters for the diesel generators are not Class 1E, the 480 V breakers plying the heaters are not required to be qualified in accordance with safety-related uirements.

5.3.2 Pressurizer Level Control normal operating water volume at full-load conditions is approximately 50 percent of the free rnal vessel volume. Under part-load conditions the water volume in the pressurizer is reduced portionally with reductions in plant load to approximately 25 percent of the free internal vessel me at the zero-power condition.

5.3.3 Pressure Setpoints reactor coolant system design and operating pressure, together with the safety valve setpoints, ter actuation setpoints, pressurizer spray valve setpoints, and protection system pressure oints, are listed in Table 5.4-11. When operating in load regulation mode, the pressurizer spray backup heaters are on continuously. This continuous operation decreases the number of ations of the backup heaters and spray valves, thereby extending the component lifetimes.

selected design margin considers core thermal lag, coolant transport times and pressure drops, rumentation and control response characteristics, and system relief valve characteristics. The ign pressure allows for operating transient pressure changes.

low pressurizer pressure engineered safety features actuation signal does not require a cident low pressurizer water level signal.

5.3.4 Pressurizer Spray separate, automatically controlled spray valves with remote manual overrides are used to initiate surizer spray.

arallel with each spray valve is a manual throttle valve. The throttle permits a small, continuous through both spray lines to reduce thermal stresses and thermal shock when the spray valves

n. Flow through this valve helps to maintain uniform water chemistry and temperature in the surizer. Temperature sensors with low temperature alarms are located in each spray line to alert operator to insufficient bypass flow.

layout of the common spray line piping routed to the pressurizer forms a water seal that prevents m buildup back to the control valves. The design spray rate is selected to prevent the pressurizer 5.4-29 Revision 1

pressurizer spray lines and valves are large enough to provide the required spray flowrate under driving force of the differential pressure between the surge line connection in the hot leg and the y line connection in the cold leg. The spray line inlet connections extend into the cold leg piping e form of a scoop in order to use the velocity head of the reactor coolant loop flow to add to the y driving force. The spray line also assists in equalizing the boron concentration between the tor coolant loops and the pressurizer.

wpath from the chemical and volume control system to the pressurizer spray line is also ided. This path provides auxiliary spray to the vapor space of the pressurizer during cooldown, standby, and hot shutdown when the reactor coolant pumps are not operating. The pressurizer y connection and the spray piping can withstand the thermal stresses resulting from the duction of cold spray water.

5.4 Tests and Inspections pressurizer construction is subject to a quality assurance program. The pressure boundary ponents meet requirements established by the ASME Code and ASME NQA-1. Table 5.4-12 ines the testing included in the pressurizer quality assurance program.

design of the pressurizer permits the inspection program prescribed by the ASME Code, tion XI. To implement the requirements of the ASME Code,Section XI, the following welds, when ent, are designed and constructed to present a smooth transition surface between the parent al and the weld metal. The weld surface is ground smooth for ultrasonic inspection.

Surge nozzle to the lower head Safety and spray nozzles to the upper head Nozzle to safe end attachment welds The girth full-penetration welds liner within the safe end nozzle region extends beyond the weld region to maintain a uniform metry for ultrasonic inspection.

pheral support rings are furnished for the removable insulation modules.

6 Automatic Depressurization System Valves automatic depressurization system (ADS) valves are part of the reactor coolant system and rface with the passive core cooling system (PXS). Twenty valves are divided into four ressurization stages. These stages connect to the reactor coolant system at three different tions. The automatic depressurization system first, second, and third stage valves are included art of the pressurizer safety and relief valve (PSARV) module and are connected to nozzles on of the pressurizer. The fourth stage valves connect to the hot leg of each reactor coolant loop.

reactor coolant system P&ID, Figure 5.1-5, shows the arrangement of the valves.

ning of the automatic depressurization system valves is required for the passive core cooling em to function as required to provide emergency core cooling following postulated accident ditions. Operation of the passive core cooling system, including setpoints for the opening of the matic depressurization system valves is discussed in Section 6.3.

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6.1 Design Bases section 5.4.8 discusses the general design basis, design evaluation, and testing and inspection eactor coolant system valves, including the automatic depressurization system valves. The matic depressurization system valves are seismic Category 1, AP1000 equipment Class A ponents. (See Subsection 3.2.2.) The fourth stage valves are interlocked so that they can not be ned until reactor coolant system pressure has been substantially reduced. The design criteria and es, functional requirements, mechanical design, and testing and inspection of the passive core ling system are included in Section 6.3. The design requirements for the passive core cooling em also apply to automatic depressurization valves except where the requirements for reactor lant system valves are more restrictive.

6.2 Design Description first stage automatic depressurization system valves are motor-operated 4-inch valves. The ond and third stage automatic depressurization system valves are motor-operated 8-inch valves.

fourth stage automatic depressurization system valves are 14 inch squib valves arranged in es with normally-open, dc powered, motor-operator valves. See Section 6.3 for a discussion of sizing of the automatic depressurization system valves.

control system for the opening of the automatic depressurization system valves, as part of the sive core cooling system, has an appropriate level of diverse and redundant features to minimize inadvertent opening of the valves.

each stage 1-3 discharge path a pair of valves are placed in series to minimize the potential for nadvertent discharge of the automatic depressurization system valves. The fourth stage valves interlocked so that they cannot be opened until reactor coolant system pressure has been stantially reduced.

first, second, and third stage valves are located on the pressurizer safety and relief valve module tered into two groups. Each group has one pair of valves for each stage. The two groups are on rent elevations and are separated by a steel plate.

uum breakers are provided in the AP1000 ADS discharge lines to help prevent water hammer wing ADS operation. The vacuum breakers limit the pressure reduction that could be caused by m condensation in the discharge line and thus limit the potential for liquid backflow from the ontainment refueling water storage tank following ADS operation.

pass test line is connected to the inlet and outlet of the first, second, and third stage upstream ation valves. This bypass line can control the differential pressure across the upstream valves ng inservice testing. The bypass test solenoid valves do not have a safety-related function to n.

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uirements by the following:

Valve equipment qualification Pre-operational valve operational verification In-service valve operational verification omatic depressurization system valve qualification is addressed in Subsection 5.4.8.1.2 for the e 1/2/3 motor operated valves and in Subsection 5.4.8.1.3 for the stage 4 squib valves. The ipment qualification includes type testing which verifies the automatic depressurization system e operability and flow capacity. Automatic depressurization system valve pre-operational valve rational verification is addressed in Subsection 14.2.9.1. Automatic depressurization system e in-service valve operational verification is addressed in Subsection 3.9.6.2.2 and Table 3.9-16.

6.4 Inspection and Testing Requirements requirements for tests and inspections for reactor coolant system valves is found in section 5.4.8.4. In addition, tests for the automatic depressurization system valves and piping are ducted during preoperational testing of the passive core cooling system, as discussed in tions 6.3 and 14.2.

6.4.1 Flow Testing al verification of the resistance of the automatic depressurization system piping and valves is ormed during the plant initial test program. A low pressure flow test and associated analysis is ducted to determine the total piping flow resistance of each automatic depressurization system e group connected to the pressurizer (i.e. stages 1-3) from the pressurizer through the outlet of downstream valve. The reactor coolant system shall be at cold conditions with the pressurizer full ater. The normal residual heat removal pumps will be used to provide injection flow into the tor coolant system, discharging through the ADS valves.

ections and associated analysis of the piping flow paths from the discharge of the automatic ressurization system valve groups connected to the pressurizer (i.e., stages 1-3) to the spargers conducted to verify the line routings are consistent with the line routings used for design flow stance calculations. The calculated piping flow resistances from the pressurizer through the rger, with valves of each group open are bounded by the resistances used in the Chapter 15 ty analysis.

ection of the piping flow paths from each hot leg through the automatic depressurization stage 4 es is conducted. The calculated flow resistances with valves in each group open are bounded by resistances used in the Chapter 15 safety analysis.

7 Normal Residual Heat Removal System normal residual heat removal system (RNS) performs the following major functions:

Reactor Coolant System Shutdown Heat Removal - Remove heat from the core and the reactor coolant system during shutdown operations.

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In-containment Refueling Water Storage Tank Cooling - Provide cooling for the in-containment refueling water storage tank.

Reactor Coolant System Makeup - Provide low pressure makeup to the reactor coolant system.

Post-Accident Recovery - Remove heat from the core and the reactor coolant system following successful mitigation of an accident by the passive core cooling system.

Low Temperature Overpressure Protection - Provide low temperature overpressure protection (LTOP) for the reactor coolant system during refueling, startup, and shutdown operations.

Long-Term, Post-Accident Containment Inventory Makeup Flowpath - Provide long-term, post-accident makeup flowpath to the containment inventory.

Spent Fuel Pool Cooling - Provide backup for cooling the spent fuel pool.

7.1 Design Bases 7.1.1 Safety Design Bases safety-related functions provided by the normal residual heat removal system include tainment isolation of normal residual heat removal system lines penetrating containment, ervation of the reactor coolant system pressure boundary and a flow path for long term post-dent makeup to the containment inventory. The containment isolation valves perform the tainment isolation function according to the criteria specified in Subsection 6.2.3. The system erves the reactor coolant system pressure boundary according to the criteria specified in section 5.4.8.

normal residual heat removal system piping and components outside containment are an 000 Class C, Seismic Category I pressure boundary. This classification recognizes the ortance of pressure boundary integrity even though these components have no safety-related tions.

7.1.2 Nonsafety Design Bases section 5.4.7 outlines the principal functions of the normal residual heat removal system. The mal residual heat removal system is designed to be reliable. This reliability is achieved by using undant equipment and a simplified system design. The normal residual heat removal system is a safety-related system. It is not required to operate to mitigate design basis events.

normal residual heat removal system is designed for a single nuclear power unit and is not red between units. The normal residual heat removal system is operated from the main control m.

normal residual heat removal system provides the capability to cool the spent fuel pool during s when it is not needed for removing heat from the reactor coolant system.

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reactor coolant system. It reduces the temperature of the reactor coolant system during the ond phase of plant cooldown. The first phase of cooldown is accomplished by transferring heat the reactor coolant system via the steam generators to the main steam system (MSS).

owing cooldown, the normal residual heat removal system removes heat from the core and the tor coolant system during the plant shutdown, until the plant is started up.

normal residual heat removal system reduces the temperature of the reactor coolant system 350° to 125°F within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after shutdown. The system maintains the reactor coolant perature at or below 125°F for the plant shutdown. The system performs this function based on following:

Operation of the system with both subsystems of normal residual heat removal system pumps and heat exchangers available.

Initiation of normal residual heat removal system operation at four hours following reactor shutdown, after the first phase of cooldown by the main steam system has reduced the reactor coolant system temperature to less than or equal to 350°F and 450 psig.

The component cooling water system supply temperature to the normal residual heat removal system heat exchangers is based on maximum normal ambient wet bulb temperature as defined in Chapter 2, Table 2.0-201. The maximum normal ambient temperature is assumed for shutdown cooling.

Operation of the system is consistent with reactor coolant system cooldown rate limits and consistent with maintaining the component cooling water below design limits during cooldown.

Core decay heat generation is based on the decay heat curve for a three-region core having burnups consistent with a 24-month or 18-month refueling schedule and based on the ANSI/ANS-5.1-1994 decay heat curve (Reference 5).

A failure of an active component during normal cooldown does not preclude the ability to cool down, but lengthens the time required to reach 125°F. Furthermore, if such a single failure occurs while the reactor vessel head is removed, the reactor coolant temperature remains below boiling temperature.

The system operates at a constant normal residual heat removal flow rate throughout refueling operations. This includes the time when the level in the reactor coolant system is reduced to a midloop level to facilitate draining of the steam generators or removal of a reactor coolant pump. Operation of the system at the minimum level that the reactor coolant system can attain using the normal reactor coolant system draining connections and procedures results in no incipient vortex formation which would cause air entrainment into the pump suction.

The pump suction line is self-venting with continually upward sloped pipe from the pump suction to the hot leg. This arrangement prevents entrapment of air and minimizes system venting efforts for startup.

Features are included that permit mid-loop operations to be performed from the main control room.

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me control system during refueling operations. The purification flow rate is consistent with the fication flow rate specified in Table 9.3.6-1.

7.1.2.3 In-Containment Refueling Water Storage Tank Cooling normal residual heat removal system provides cooling for the in-containment refueling water age tank during operation of the passive residual heat removal heat exchanger or during normal t operations when required. The system is manually initiated by the operator. The normal dual heat removal system limits the in-containment refueling water storage tank water perature to less than boiling temperature during extended operation of the passive residual heat oval system and not greater than 120°F during normal operation. The system performs this tion based on the following:

Operation of the system with both subsystems of normal residual heat removal system pumps and heat exchangers available.

The component cooling water system supply temperature to the normal residual heat removal system heat exchangers is based on an ambient design wet bulb temperature of no greater than 86.1°F (0 percent exceedance). The 86.1°F value is assumed for normal conditions and transients that start at normal conditions.

e the normal residual heat removal system is not a safety-related system, its operation is not ited in Chapter 15 Accident Analyses.

7.1.2.4 Low Pressure Reactor Coolant System Makeup and Cooling normal residual heat removal system provides low pressure makeup from the cask loading pit to reactor coolant system. The system is manually initiated by the operator following receipt of an matic depressurization signal. If the system is available, it provides reactor coolant system eup once the pressure in the reactor coolant system falls below the shutoff head of the normal dual heat removal system pumps. The system provides makeup from the cask loading pit to the tor coolant system and provides additional margin for core cooling. The normal residual heat oval system is not required to mitigate design basis accidents, and therefore its operation is not sidered in Chapter 15 Accident Analyses.

7.1.2.5 Low Temperature Overpressure Protection normal residual heat removal system provides a low temperature overpressure protection tion for the reactor coolant system during refueling, startup, and shutdown operations. The em is designed to limit the reactor coolant system pressure to the lower of either the limits cified in 10 CFR 50, Appendix G, or 110 percent of the normal residual heat removal system ign pressure.

7.1.2.6 Spent Fuel Pool Cooling normal residual heat removal system has the capability to supplement or take over the cooling of spent fuel pool when it is not needed for normal shutdown cooling.

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ws the piping and instrumentation diagram for the normal residual heat removal system.

le 5.4-13 gives the important system design parameters.

inside containment portions of the system from the reactor coolant system up to and including containment isolation valves outside containment are designed for full reactor coolant system sure. The portion of the system outside containment, including the pumps, valves and heat hangers, has a design pressure and temperature such that full reactor coolant system pressure is w the ultimate rupture strength of the piping.

normal residual heat removal system consists of two mechanical trains of equipment. Each train udes one residual heat removal pump and one residual heat removal heat exchanger. The two s of equipment share a common suction line from the reactor coolant system and a common harge header. The normal residual heat removal system includes the piping, valves and rumentation necessary for system operation.

normal residual heat removal system suction header is connected to a reactor coolant system leg with a single step-nozzle connection. The step-nozzle connection is employed to minimize the ihood of air ingestion into the residual heat removal pumps during reactor coolant system

-loop operations. The suction header then splits into lines with two parallel sets of two normally ed, motor-operated isolation valves in series. This arrangement allows for normal residual heat oval system operation following a single failure of an isolation valve to open and also allows for mal residual heat removal system isolation following a single failure of an isolation valve to close.

lines join into a common suction line inside containment. A single line from the inside-tainment refueling water storage tank is connected to the suction header before it leaves tainment.

e outside containment, the suction header contains a single normally closed, motor-operated ation valve. Downstream of the suction header isolation valve, the header branches into two arate lines, one to each pump. Each branch line has a normally open, manual isolation valve tream of the residual heat removal pumps. These valves are provided for pump maintenance.

normal residual heat removal system suction header is continuously sloped from the reactor lant system hot leg to the pump suction. This eliminates any local high points where air could ect and cause low net positive suction head, pump binding and a loss of residual heat removal ability.

discharge of each residual heat removal pump is directed to its respective residual heat removal t exchanger. The outlet of each residual heat removal heat exchanger is routed to the common harge header, which contains a normally closed, motor-operated isolation valve. For pump ection, a miniflow line with an orifice is included from downstream of the residual heat removal t exchanger to upstream of the residual heat removal pump suction. This line is sized to provide cient pump flow when the pressure in the reactor coolant system is above the residual heat oval pump shutoff head.

e inside containment, the common discharge header contains a check valve that acts as a tainment isolation valve. Downstream of the check valve, the discharge header branches into two s, one to each passive core cooling system direct vessel injection nozzle. These branch lines h contain a stop check valve and check valve in series that serve as the reactor coolant system sure boundary. A line to the chemical and volume control system demineralizers branches from of the direct vessel injection lines. This line is used for shutdown purification of the reactor 5.4-36 Revision 1

safety relief valve is located on the normal residual heat removal system suction header inside tainment. This valve provides low temperature overpressure protection of the reactor coolant em. Subsection 5.4.9 describes the sizing basis of this valve. Another safety relief valve outside ontainment provides protection against excess pressure for the piping and components.

en the normal residual heat removal system is in operation, the water chemistry is the same as of the reactor coolant. Sampling may be performed using the normal residual heat removal heat hangers channel head drain connections. Sampling of the reactor coolant system using these nections is available at shutdown. Sampling of the in-containment refueling water storage tank is ilable during normal plant operation.

7.2.1 Design Features Addressing Shutdown and Mid-Loop Operations following is a summary of the specific AP1000 design features that address Generic Letter

) 88-17 regarding mid-loop operations. In addition, these features support improved safety during tdown.

p Piping Offset - As shown in Figure 5.3-6, the reactor coolant system hot legs and cold legs are ically offset. This permits draining of the steam generators for nozzle dam insertion with hot leg l much higher than traditional designs. The reactor coolant system must be drained to a level ch is sufficient to provide a vent path from the pressurizer to the steam generators. This is inally 80 percent level in the hot leg. This loop piping offset also allows a reactor coolant pump to eplaced without removing a full core.

p-nozzle Connection - The normal residual heat removal system employs a step-nozzle nection to the reactor coolant system hot leg. The step-nozzle connection has two effects on mid-operation. One effect is to substantially lower the RCS hot leg level at which a vortex occurs in residual heat removal pump suction line due to the lower fluid velocity in the hot leg nozzle. This eases the margin from the nominal mid-loop level to the level where air entrainment into the p suction begins.

ther effect of the step-nozzle is that, if a vortex should occur, the maximum air entrainment into pump suction has been shown experimentally to be no greater than 5 percent. This level of air stion will make air binding of the pump much less likely.

mal Residual Heat Removal Throttling During Mid-Loop - The normal residual heat removal ps are designed to minimize susceptibility to cavitation. Normally, the normal residual heat oval system operates without the need for throttling a residual heat removal control valve when level in the reactor coolant system is reduced to a mid-loop level. If the reactor coolant system is aturated conditions and mid-loop level, some throttling of a flow control valve is necessary to ntain adequate net positive suction head.

-Venting Suction Line - The residual heat removal pump suction line is sloped continuously ard from the pump to the reactor coolant system hot leg with no local high points. This eliminates ntial problems with refilling the pump suction line if a residual heat removal pump is stopped n cavitating due to excessive air entrainment. With the self-venting suction line, the line will refill the pumps can be immediately restarted once an adequate level in the hot leg is re-established.

e Range Pressurizer Level - A nonsafety-related independent pressurizer level transmitter, brated for low temperature conditions, provides water level indication during startup, shutdown, refueling operations in the main control room and at the remote shutdown workstation. The 5.4-37 Revision 1

ng shutdown operations.

Leg Level Instrumentation - The AP1000 reactor coolant system contains level instrumentation ach hot leg with indication in the main control room. In addition to the wide-range pressurizer level rumentation (used during cold plant operation) which provides continuous level indication in the n control room from the normal level in the pressurizer, two narrow-range hot leg level ruments are available. Alarms are provided to alert the operator when the reactor coolant system leg level is approaching a low level. The isolation valves in the line used to drain the reactor lant system close on a low reactor coolant system level during shutdown operations. Operations uired during mid-loop are performed by the operator in the main control room. The level itoring and control features significantly improve the reliability of the AP1000 during mid-loop rations.

ctor Vessel Outlet Temperature - Reactor coolant system hot leg wide range temperature ruments are provided in each hot leg for normal residual heat removal system operation with mal inventory. The normal residual heat removal temperature instruments, upstream of the heat hangers, indicate reactor coolant system hot leg temperature when in reduced inventory ditions. In addition, at least two incore thermocouple channels are available to measure the core temperature during midloop residual heat removal operation. These two thermocouple channels associated with separate electrical divisions.

S Valves - The automatic depressurization system first-, second-, and third-stage valves, nected to the top of the pressurizer, are open whenever the core makeup tanks are blocked ng shutdown conditions while the reactor vessel upper internals are in place. This provides a vent to preclude pressurization of the reactor coolant system during shutdown conditions when ay heat removal is lost. This also allows the in-containment refueling water storage tank to matically provide injection flow if it is actuated on a loss of decay heat removal.

capability to restore containment integrity during shutdown conditions is provided. The tainment equipment hatches are equipped with guide rails that allow reinstallation of the hatches e-establish containment integrity. The containment design also includes penetrations for porary cables and hoses needed for shutdown operations.

cedures direct the operator in the proper conduct of midloop operation and aid in identifying and ecting abnormal conditions that might occur during shutdown operations.

7.2.2 Design Features Addressing Intersystem LOCA AP1000 has addressed the intersystem LOCA section of SECY 90-016 with a number of design ures. These design features are:

es and Standards/Seismic Protection - The portions of the normal residual heat removal em located outside containment (that serve no active safety functions) are classified as AP1000 ipment Class C so that the design, manufacture, installation, and inspection of this pressure ndary is in accordance with the following industry codes and standards and regulatory uirements: 10 CFR 50, Appendix B; Regulatory Guide 1.26 Quality Group C; and ASME Boiler Pressure Vessel Code,Section III, Class 3. The pressure boundary is classified as Seismic egory I.

eased Design Pressure - The portions of the normal residual heat removal system from the tor coolant system to the containment isolation valves outside containment are designed to the 5.4-38 Revision 1

tor coolant system. Specifically, the piping is designed as schedule 80S, and the flanges, valves, fittings are specified to be greater than or equal to ANS class 900. The design pressure of the mal residual heat removal system is 900 psi, which is approximately 40 percent of operating tor coolant system pressure.

ctor Coolant System Isolation Valve - The AP1000 normal residual heat removal system tains an isolation valve in the pump suction line from the reactor coolant system. This motor-rated containment isolation valve is designed to the reactor coolant system pressure. It provides dditional barrier between the reactor coolant system and lower pressure portions of the normal dual heat removal system.

mal Residual Heat Removal System Relief Valve - The inside containment AP1000 normal dual heat removal system relief valve is connected to the residual heat removal pump suction This valve is designed to provide low-temperature overpressure protection of the reactor coolant em as described in Subsection 5.2.2. It is connected to the high pressure portion of the pump ion line and reduces the risk of overpressurizing the low pressure portions of the system.

tures Preventing Inadvertent Opening of Isolation Valves - The reactor coolant system ation valves are interlocked to prevent their opening at reactor coolant system pressures above psig. Section 7.6 discusses this interlock. The power to these valves is administratively blocked ng normal power operation.

S Pressure Indication and High Alarm - The AP1000 Normal residual heat removal system tains an instrumentation channel that indicates pressure in each normal residual heat removal p suction line. A high pressure alarm is provided in the main control room to alert the operator to ndition of rising RCS pressure that could eventually exceed the design pressure of the normal dual heat removal system.

sed valves connecting to spent fuel pool - The cross-connecting piping between the normal dual heat removal system and the spent fuel pool cooling system is isolated by normally closed es.

7.3 Component Description descriptions of the normal residual heat removal system components are provided in the wing subsections. Table 5.4-14 lists the key equipment parameters for the normal residual heat oval system components.

7.3.1 Normal Residual Heat Removal Pumps (MP01 A&B) residual heat removal pumps are provided. These pumps are single stage, vertical in-line, om suction centrifugal pumps. They are coupled with a motor shaft driven by an ac powered ction motor.

h pump is sized to provide the flow required by its respective heat exchanger for removal of its ign basis heat load. Redundant pumps and heat exchangers provide sufficient cooling to prevent S boiling if one subsystem is inoperative. A continuously open miniflow line is also provided to ect the pump from operation at low flow conditions.

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ability. These heat exchangers are vertically mounted, shell and U-tube design. Reactor coolant circulates through the stainless steel tubes while component cooling water circulates through the on steel shell. The tubes are welded to the tubesheet.

7.3.3 Normal Residual Heat Removal Valves normal residual heat removal system packed valves designated for radioactive service are ided with stem packing designs that provide enhanced resistance to leakage. Leakage to the osphere is essentially zero for these valves.

ual and motor-operated valves have backseats to facilitate repacking and to limit stem leakage n the valves are open. The basic material of construction for valves is stainless steel.

7.3.3.1 Reactor Coolant System Inner/Outer Isolation Valves (V001 A&B, V002 A&B) re are two parallel sets of two valves in series for a total of four valves. These valves are normally ed, motor-operated valves and are located inside the containment. These valves form the reactor lant pressure boundary. They are opened only for normal cooldown after reactor coolant system ressurization to 450 psig. They are controlled from the main control room and fail in the as-is ition. These valves are protected from inadvertently opening when the reactor coolant system sure is above 450 psig by an interlock. Power to these valves is administratively blocked during mal power operations.

7.3.3.2 In-Containment Refueling Water Storage Tank Suction Line Isolation Valve (V023) re is one motor-operated valve located inside containment in the line from the in-containment eling water storage tank to the pump suction header. This valve is designed for full reactor lant system pressure. It also acts as a containment isolation valve.

7.3.3.3 Residual Heat Removal Isolation Valve (V011) re is one motor-operated valve in the pump discharge header outside of containment. This valve esigned for full reactor coolant system pressure. It also acts as a containment isolation valve.

7.3.3.4 In-Containment Refueling Water Storage Tank Return Isolation Valve (V024) re is one normally closed motor-operated valve located inside containment in the discharge line e in-containment refueling water storage tank. This valve is aligned for full-flow testing of the dual heat removal pumps or for operations involving cooling of the in-containment refueling water age tank.

7.3.3.5 Cask Loading Pit Isolation Valve (V055) re is one normally closed motor-operated valve in the line between the cask loading pit and the dual heat removal pump suction line. This valve can be opened by the operator to provide low sure injection from the cask loading pit to the reactor coolant system during an accident.

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s. During plant cooldown the operator can close these valves to increase the circulating flow rate e reactor coolant through the residual heat removal heat exchangers to decrease the reactor lant system cooldown time. These valves automatically open on low flow in the residual heat oval heat exchanger discharge line.

7.4 System Operation and Performance ration of the normal residual heat removal system is described in the following sections. System rations are controlled and monitored from the main control room, including mid-loop operations.

reactor coolant system is equipped with mid-loop level instrumentation with remote readout in main control room. This instrumentation is used for monitoring mid-loop operations from the main trol room.

7.4.1 Plant Startup nt startup includes the operations that bring the reactor plant from a cold shutdown condition to oad operating temperature and pressure, and subsequently to power operation.

ing cold shutdown conditions, both residual heat removal pumps and heat exchangers operate to ulate reactor coolant and remove decay heat. The residual heat removal pumps are switched off n plant startup begins. The normal residual heat removal system remains aligned to the reactor lant system to maintain a low pressure letdown path to the chemical and volume control system.

alignment provides reactor coolant system purification flow and low temperature over-pressure ection of the reactor coolant system. As the reactor coolant pumps are started, their thermal input ins heating the reactor coolant inventory. Once the pressurizer steam bubble formation is plete, the normal residual heat removal system suction header isolation valve and the discharge der isolation valve are closed and tested for leakage. The valve arrangement is then set for mal operation, as shown in Figure 5.4-6.

7.4.2 Plant Cooldown nt cooldown is the operation that brings the reactor plant from normal operating temperature and sure to refueling conditions.

initial phase of plant cooldown consists of reactor coolant cooldown and depressurization. Heat ansferred from the reactor coolant system via the steam generators to the main steam system.

ressurization is accomplished by spraying reactor coolant into the pressurizer, which cools and denses the pressurizer steam bubble.

en the reactor coolant temperature and pressure have been reduced to 350°F and 450 psig, ectively (approximately four hours after reactor shutdown), the second phase of plant cooldown itiated with the normal residual heat removal system being placed in service.

ore starting the residual heat removal pumps, the in-containment refueling water storage tank ation valve is closed. Then the normal residual heat removal system suction header isolation e and the discharge header isolation valve are opened. When the pressure in the reactor coolant em has been reduced to below 450 psig, the inner/outer isolation valves are opened.

e the proper valve alignment has been performed and component cooling water flow has been ated to both residual heat removal heat exchangers, normal residual heat removal system 5.4-41 Revision 1

mode of operation continues for the duration of the cooldown until the reactor coolant system perature is reduced to 140°F and the system is depressurized. The reactor coolant system may be opened for either maintenance or refueling. Cooldown continues until the reactor coolant em temperature is lowered to 125°F (about 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after reactor shutdown).

ing the cooldown operations, the reactor coolant system water level is drained to a mid-loop l to facilitate steam generator draining and maintenance activities. For normal refuelings, the l to which the reactor coolant system is drained is that which allows air to be vented into the m generators from the pressurizer. This level is nominally an 80 percent water level in the hot The design of the AP1000 normal residual heat removal system is such that throttling of the dual heat removal pump flow during mid-loop operations to avoid air-entrainment into the pump ion is not required.

he appropriate time during the cooldown, the operator lowers the water level in the reactor coolant em by placing the chemical and volume control system letdown control valve into the refueling ndown mode. At this time the makeup pumps are turned off; and the letdown flow control valve trols the drain rate to the liquid waste processing system. The drain rate proceeds initially at the imum drain rate and is substantially reduced once the level in the reactor coolant system is ered to the top of the hot leg. The letdown flow control valve as well as the letdown line tainment isolation valve receives a signal to automatically close once the appropriate level is ined. Alarms actuate in the main control room if the level continues to drop to alert the operator to ually isolate the letdown line.

7.4.3 Refueling h residual heat removal pumps and heat exchangers remain operating during refueling. Water sfers from the in-containment refueling water storage tank to the refueling cavity are performed he spent fuel pool cooling system (SFS). This function has traditionally been performed by dual heat removal systems. That capability still exists if the need arises. To improve clarity in the eling cavity and reduce operational radiation exposure, the spent fuel pool cooling system is used ood the refueling cavity without flooding through the reactor vessel.

decay heat decreases and as fuel is moved to the spent fuel pool, one residual heat removal p and heat exchanger may be taken out of service. However, the valves remain aligned should need arise to start this pump quickly in case of a failure of the operating residual heat removal p.

7.4.4 Accident Recovery Operations n actuation of automatic depressurization, the normal residual heat removal system can be loyed to provide low-pressure reactor coolant system makeup. Provided that radiation levels de containment are below a high radiation value and after resetting the safeguards actuation al to the valves as necessary, the operator may open the cask loading pit suction valves and the dual heat removal discharge isolation valve and start the residual heat removal pumps. Water is ped from the cask loading pit to the direct vessel injection lines. Operation of the normal residual t removal system will not prevent the passive core cooling system from performing its safety tions.

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over the cooling function of the spent fuel pool cooling system. The normally closed valves in the s-connecting piping are opened. One normal residual heat removal pump is started. Spent fuel l water is drawn through the pump, passed through a heat exchanger and returned to the pool.

mode of cooling is available when the normal residual heat removal system is not needed for mal shutdown cooling. The spent fuel pool water flow path between the spent fuel pool and the mal residual heat removal system is independent of the flow path used for spent fuel pool cooling he spent fuel pool cooling system.

7.4.6 Fire Leading to MODE 5, Cold Shutdown e event of loss of normal component cooling system function where it is desired to transfer to DE 5, Cold Shutdown, to facilitate maintenance, the fire protection system can provide the source ooling water for a normal residual heat removal system pump and heat exchanger as described in section 9.2.2.4.5.5.

7.5 Design Evaluation e the normal residual heat removal system is connected to the reactor coolant system, portions e system that create the reactor coolant system pressure boundary are designed according to SI/ANS 51.1 (Reference 6) with regards to maintaining the reactor coolant system pressure ndary integrity.

e the normal residual heat removal system penetrates the containment boundary, the tainment penetration lines are designed according to the containment isolation criteria identified ubsection 6.2.3.

ety-related makeup water can be provided through the normal residual heat removal system for

-term post-accident containment makeup. This makeup is provided through the manual tainment isolation test connection valve in the discharge of the normal residual heat removal em.

normal residual heat removal system components and piping are compatible with the radioactive s they contain.

design of the normal residual heat removal system has been compared with the acceptance ria set forth in Subsection 5.4.7, Residual Heat Removal System, Revision 3, of the NRCs ndard Review Plan. The specific General Design Criteria identified in the Standard Review Plan ion are General Design Criteria 2, 4, 5, 19, and 34. Additionally, positions of Regulatory des 1.1, 1.29, and 1.68 were also reviewed to determine the degree of compliance between the 000 and the acceptance criteria. Branch Technical Position RSB 5-1 was also reviewed as ropriate.

ussions of the conformance with Regulatory Guides and Branch Technical Positions are found in tion 1.9. Compliance with General Design Criteria is found Section 3.1.

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operational tests are conducted to verify proper operation of the normal residual heat removal em (RNS). The preoperational tests include valve inspection and testing, flow testing, and fication of heat removal capability.

7.6.1.1 Valve Inspection and Testing inspection requirements of the normal residual heat removal system valves that constitute the tor coolant pressure boundary are consistent with those identified in Subsection 5.2.4. The ection requirements of the normal residual heat removal system valves that isolate the lines etrating containment are consistent with those identified in Section 6.6.

low temperature overpressure protection relief valve, RNS-V021, located on the normal residual t removal system suction relief line, is bench tested with water. Valve set pressure is verified to be than or equal to the value assumed in the low temperature overpressure protection analysis.

eving capacity of the valve is certified in accordance with the ASME code,Section III, NC-7000.

7.6.1.2 Flow Testing h installed normal residual heat removal system pump is tested to measure the flow through the mal residual heat removal system heat exchangers when aligned to cool the reactor coolant em. Testing will be performed with the pump suction aligned to the reactor coolant system hot leg the discharge aligned to the passive core cooling system direct vessel injection lines. Flow will measured using instrumentation in the pump discharge line. Testing will confirm that each pump ides at least the required flow rate shown in Table 5.4-14. This is the minimum flow rate required nsure that the normal residual heat removal system can meet its functional requirement of cooling reactor during shutdown operations.

h installed normal residual heat removal system pump is also tested to measure the flow when ned to deliver low pressure makeup to the reactor coolant system. Testing will be performed with pump suction aligned to the cask loading pit and the discharge aligned to the passive core ling system direct vessel injection lines. Flow will be measured using instrumentation in the pump harge line. The reactor coolant system will be at atmospheric pressure for this test. Testing will firm that each pump provides at least the required flow rate shown in Table 5.4-14. This is the imum flow rate required to ensure that the normal residual heat removal system can meet its tional requirement to prevent 4th stage ADS actuation for small breaks.

7.6.1.3 Heat Removal Capability Analysis t exchanger manufacturers test results and heat exchanger data will be used to perform an lysis to verify that the heat removal capability of each normal residual heat removal system heat hanger, as measured by the product of the heat transfer coefficient and the effective heat transfer a, UA, is equal to or greater than the required value shown in Table 5.4-14. This is the minimum e required to ensure that the normal residual heat removal system can meet its functional uirement of cooling the reactor during shutdown operations.

7.7 Instrumentation Requirements normal residual heat removal system contains instrumentation to monitor system performance.

tem parameters necessary for system operation are monitored in the main control room including following:

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Residual heat removal pump discharge pressure.

ddition, the reactor coolant system contains instrumentation to control and monitor the operations e normal residual heat removal system. These include the following:

Reactor coolant system wide range pressure; and, Reactor coolant system hot leg level.

rumentation is also provided to enable mid-loop operations to be performed from the main control m.

motor-operated valves connected to the reactor coolant system hot leg are interlocked to ent them from opening when reactor coolant system pressure exceeds 450 psig. These valves also interlocked to prevent their being opened unless the isolation valve from the in-containment eling water storage tank to the residual heat removal pump suction header is closed. Section 7.6 cribes this interlock.

8 Valves es in the reactor coolant system and safety-related valves in connecting systems provide the ary means for the flow of water into and out of the reactor coolant system. In the following agraphs the design basis, description, evaluation and testing of ASME Code Class 1, 2 3 valves is discussed. This discussion includes safety-related valves not in the reactor coolant em because the valve requirements are independent of the system.

8.1 Design Bases es within the reactor coolant system and safety-related valves in connected systems are igned, manufactured, and tested to meet the requirements of the ASME Code,Section III. As d in Section 5.2, valves out to and including the second valve that is normally closed or capable utomatic or remote closure are part of the reactor coolant system. The reactor coolant pressure ndary valves are manufactured to the ASME Code Class 1 requirements. Valves of 1 inch and ller in lines connected to the reactor coolant system are manufactured to Class 2 requirements n the flow is limited by a flow-limiting orifice.

tainment isolation valves are manufactured to ASME Code, Class 2 requirements. Other AP1000 ipment Class C safety-related valves are manufactured to ASME Code, Class 3 requirements.

ety-related valves in auxiliary systems are manufactured to ASME Code Class 2 and 3 uirements depending on their function and classification as outlined in Subsection 3.2.2.

le 5.4-15 provides design data for the reactor coolant pressure boundary valves. Valves and rators are sized to provide valve operation under the full range of design basis flow and pressure p conditions, including recovery from potential mispositioning of the valves. Operating modes, mal operating and worst-case differential pressures, fluid temperature ranges, and environmental cts are considered in sizing valves and valve operators. Table 5.4-16 gives the normal and imum differential pressure expected during opening and closing of motor-operated valves in the tor coolant pressure boundary. Check valves considered part of the reactor coolant system are ted inside the containment.

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esign conditions including the required system operating cycles to be experienced by the valve, ironmental conditions under which the valve is required to function, and severe transient loadings ected during the life of the valve. The design conditions considered may include water hammer pipe break transients, sealing and leakage requirements, operating fluid conditions (including

, velocity, temperature, and temperature gradient), maintenance requirements, time between or refurbishments, corrosion requirements, vibratory loading, planned testing methods, and test uency, and periods of idle operation. Design conditions may include other requirements identified ng plant detail design. The maximum loading resulting from the design conditions and transients evaluated in accordance with the ASME Code,Section III Class 1 design requirements.

ve safety-related check valves include the capability to verify the movement of each check valves rator during inservice testing by observing a direct instrumentation indication of the valve position y using non-intrusive test methods. This instrumentation provides nonintrusive check valve cation and may be either permanently or temporarily installed.

ck valve model and size selection are based on the systems flow conditions, installed location of valve with respect to flow disturbance, and orientation of the valve in the piping system. Design ures, surface finish, and materials can accommodate provisions for nonintrusive determination of position and potential valve degradation over time. Valve internal parts are designed with self-ning features for the purpose of assured alignment after each valve opening. Qualification testing ides for the adequacy of the safety-related check valves under design conditions. This testing udes test data from the manufacturer, field test data and empirical test data supported by test or (such as prototype) of similar valves where similarity is justified by technical data. Sampling size he qualification test is justified by technical data.

safety-related active check valves with extended structures functional qualification will be ormed to demonstrate by test, by analysis or by a combination thereof, the ability to operate at safety-related design conditions. This functional qualification will demonstrate the valve rability during and after loads representative of the maximum seismic and vibratory event. Check e internal parts are analyzed for maximum design basis loading conditions in accordance with the uirements in ASME Code,Section III.

8.1.2 Motor-Operated Valves Design and Qualification sign basis and required operating conditions are established for active safety-related motor-rated valves. Based on the design conditions the motor-operated valves will have a structural lysis performed to demonstrate their components are within the structural limits at the design ditions. The motor-operated valves are designed for a range of conditions up to the design ditions which includes fluid flow, differential pressure (including line break, if necessary), system sure and temperature, ambient temperature, operating voltage range and stroke time. The sizing e motor operators on the valves take into account diagnostic equipment accuracies, changes in ut capability for increasing differential pressures and flow and ambient temperature and uction in motor voltage, control switch repeatability, friction variations and other changes in ameters that could result in an increase in operating loads or a decrease in operator output.]*

es that are subjected to large temperature changes during operation and can have water or high sure fluid trapped in the bonnet cavity are evaluated for pressure locking. Provisions are ided, as required to reduce the susceptibility to bonnet overpressurization, pressure locking, and mal binding.

e motor-operated valves have a functional qualification performed to demonstrate by test, by lysis or by a combination thereof, the ability to operate over a range up to the design conditions.

Staff approval is required prior to implementing a change in this information.

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operating conditions, demonstrate capability under maximum pipe end loads and demonstrate interruption and functional capability. The testing includes test data provided by the ufacturer, field test data, empirical data supported by testing or analysis of prototype tests of lar motor-operated valves that support the qualification where similarity must be justified by nical data. The qualification must be used for validating the required thrust and torque as licable to operate the valve and the output capability of the motor operator.]*

or-operated valves are designed to be able to change their position from an improper position

-positioned) either prior to or during accidents. The recovery from mis-positioning is considered a safety-related function. The nonsafety-related capability to recover from valve mis-positioning is ided for plant operational availability considerations. Systems with safety-related functions that tain motor-operated valves are designed to tolerate mis-positioning as a single failure or undant features are provided to preclude mis-positioning. These features include multiple position cators and alarms, technical specification surveillance, power lock-out, and confirmatory open or e signals.

e recovery from mis-positioning is a nonsafety-related function, equipment qualification testing inservice testing is not required for the recovery from mis-position function.

visions are made, where possible, for in-situ testing of motor-operated valves at a range of ditions up to the maximum design basis operating conditions in the safety-related design direction en or close). Where an alternative to in-situ testing is required, the justification of the alternative hod to design condition differential testing is documented as part of the valve test program.

8.1.3 Other Power-Operated Valves Including Explosively Actuated Valves Design and Qualification ign basis and required operating conditions are established for power-operated (POV) and losively actuated valve assemblies with an active safety-related function. Power-operated valve emblies include pneumatic-hydraulic-, air piston-, and solenoid-operated assemblies.

losively-actuated valves have the valve disk welded to the valve seat and are actuated by an losive charge fired by an electrical signal.

e power-operated safety related valves will have a structural analysis performed to demonstrate r components are within the structural limits at the design conditions. Power operated valve emblies and explosively actuated valves are designed to accept the maximum compression, ion, and torsional loads which the assembly is capable of producing in combination with other s such as pressure, thermal, or externally applied loads. The maximum loading resulting from the ign conditions and transients is evaluated in accordance with the ASME Code,Section III Class 1 ign requirements. Packing adjustment limits are identified to reduce the potential for stem binding.

power-operated valves are designed to operated at design operating conditions which include flow, differential pressure (including pipe break, if necessary), system pressure, fluid perature, ambient temperature, fluid supply conditions (or electrical power supply), spring force stroke time requirements. The power operated valves, depending on their design and actuation e, have the operators sized to account for diagnostic equipment accuracies, changes in output ability for increasing differential pressures and flow, friction variations and changes in other ameters that could result in an increase in operating loads or a decrease in operator output.

power-operated, safety-related valves have a functional qualification performed to demonstrate est, by analysis or by a combination thereof, the ability to operate at the design conditions.

Staff approval is required prior to implementing a change in this information.

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esentative of the maximum seismic or vibratory event (as required to perform their intended tion), demonstrate the valve sealing capability, demonstrate capability under cold and hot rating conditions, demonstrate capability under maximum pipe end loads and demonstrate flow rruption and functional capability. The testing includes test data from the manufacturer, field test

, empirical data supported by test, or analysis of prototype tests of similar power-operated valves support qualification of the power-operated valve. Similarity must be justified by technical data.

enoid-operated valves are verified to satisfy the applicable requirements for Class 1E ponents. Solenoid-operated valves are verified to perform their safety-related design uirements over a range of electrical power supply conditions including minimum and maximum age.]*

8.2 Design Description materials of construction are selected to minimize the effects of corrosion and erosion and are patible with the environment. The valves in contact with reactor coolant fluid shall be constructed tainless steel materials or alloys acceptable for the fluid chemistry.

ety-related valves do not have full penetration welds within the valve body walls except that losive actuated valves may be fabricated using full penetration welds of the valve bodies.

es and actuators are furnished as a matched system capable of operating over the entire range esign basis conditions. The function of the valve and operator including switch settings for motor-rated valves are qualified by testing, analysis or a combination thereof.

es that have stem packing are constructed with packing material compatible with the system fluid stem material. Where the design permits, valves greater than 2 inch diameter have live load king to maintain a compressive packing force. Valves supplied with stem packing are supplied a backseat which may be utilized to minimize stem leakage. The backseat capability does not on system pressure to achieve a satisfactory seal. Valve designs such as main steam isolation es, safety relief valves, packless valves and small solenoid valves by nature of the design of e valves do not have backseat capability. Motor operated valves are not backseated during mal operation. The backseating of the valve must not compromise the structural integrity of the e and the backseats are capable of retaining the valve stem against full system pressure and imum thrust produced by the actuator.

e valves at the interface with the reactor coolant system and connected safety-related systems either of the wedge or parallel disc design and have essentially straight through flow. The wedge ign is flex-wedge; solid wedge designs are not used. Gate valves have backseats. Gate valves are susceptible to overpressurization as the result of the heatup of trapped fluid shall be provided venting capability to alleviate the issue. The valve shall be of outside screw and yoke design.

e valves are not used in flow regulation or throttling service.

be valves are either T or Y type of either a standard or balanced plug design. Valves that are used hrottling service are designed with a disc or disc/cage assembly that will provide the required flow racteristic. Motor operated and manual valves are of the outside screw and yoke design.

ck valves are typically swing type, but tilt disk, nozzle check, and lift check may be used. Check es containing radioactive fluid are fabricated of stainless steel. These valves do not have body etration other than the inlet, outlet and bonnet. The check hinge is serviced through the bonnet.

rating parts are contained within the body. The disc of swing check valves has limited rotation to ide a change of seating surface and alignment after each valve opening.

Staff approval is required prior to implementing a change in this information.

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cle NB-3000. ASME Code, Class 2 valves meet the design requirements of ASME Code, tion III, Article NC-3000. ASME Code Class 3 valves meet the design requirements of ASME e,Section III, Article ND-3000. The AP1000 equipment Classes A, B, and C valves, which are ufactured to ASME Code Classes 1, 2, and 3 respectively, meet established functional uirements. The functional requirements include operability, differential pressure during opening or ure, and seat leakage. The functional requirements are consistent with the guidelines in ulatory Guide 1.148 and ANSI N278.1-1975 (Reference 7).

design transients for the valves including the number and the duration of each type of cycle are tified in Subsection 3.9.1.1.

es with extended structures have testing or analysis performed to demonstrate that the natural uency is greater than 33 hz. In addition, a structural analysis is performed to verify the design ing will not effect the intended operation of the valve.

lification testing of each power operated valve which includes motor-operated, air operated, raulic operated, solenoid operated and explosive actuated valves demonstrates the capability of operator to operate over the full range of expected plant operating conditions. Qualification ing also demonstrates the closing, opening, and seating capability of the valve against the imum pressure differential and flow within a specified time over the entire operating range.

uirements for qualification testing of power-operated active valves are based on QME-1 ference 8). The testing programs in Section 3.10 demonstrate the capability of the valves to rate, as required, during anticipated and postulated plant conditions.

ctor coolant chemistry parameters are compatible with valve construction materials.

8.4 Tests and Inspections nondestructive examinations for the reactor coolant pressure boundary valves meet the more gent requirements of the ASME Code,Section III, or ANSI B16.34 (Reference 9). The destructive examination required is evaluated for each type and class of valve. The examinations sist of the following:

Radiographic Examination - Classes 1 and 2 valve bodies, bonnets, and discs which of cast material are radiographically examined in accordance with the ASME Code,Section III.

The procedure and acceptance standards are according to the requirements for Class 1 in the ASME Code,Section III.

Ultrasonic Examination - Classes 1 and 2 valve bodies, bonnets, and discs and Classes 1, 2, and 3 valve stems of 1 inch nominal diameter or larger fabricated of wrought or forged material are ultrasonically examined. The procedures and acceptance standards are according to the requirements for Class 1 in the ASME Code,Section III.

Liquid Penetrant Examination - Bodies, bonnets, discs, and stems, including machined surfaces on these parts, are liquid-penetrant examined in accordance with the ASME Code,Section III. The procedures and acceptance standards are according to the requirements for Class 1 in the ASME Code,Section III.

rostatic pressure boundary test and seat leakage are performed on the reactor coolant pressure ndary valves. The valves are subjected to the following tests as appropriate following ufacture: hydrostatic pressure boundary test, disc hydrostatic test, backseat leakage test, 5.4-49 Revision 1

operational testing is performed on the valves to verify operability during design basis operating ditions. The preoperational testing is described in the following sections. The requirements of C Generic Letter 89-10 are used as guidelines to develop the preservice test program for valve rability. Except when test alternatives are justified, design conditions are used for the operability ing.

section 5.2.4 discusses inservice inspection for ASME Code Class 1 valves. Section 6.6 usses inservice inspection for ASME Code Class 2 and 3 components. Valves are accessible for ssembly and internal visual inspection to the extent practical. Subsection 3.9.6 discusses the rvice testing program for active valves.

8.5 Preoperational Testing ults of preoperational testing will be used to demonstrate that the results of testing under in situ or alled conditions can be used to confirm the capacity of the valve to operate under design ditions as discussed in Section 14.4.

8.5.1 Check Valves ve check valves are tested in the open and close direction. Testing a check valve confirms the e operability to move to the position to fulfill the safety-related mission during applicable plant es. The test shows that the check valve opens in response to flow and closes when the flow is ped. Operability testing of the valves is described in Subsection 3.9.3.2.2. Full-flow testing during licable plant modes of check valves or sufficient flow to fully open the check valve to demonstrate e operability under design conditions is permitted in most cases by the system design. Where testing cannot be accomplished, an alternate method of demonstrating operability is developed, justified. A demonstration of reverse-flow isolation of the check valves that is that the check valve es when the flow is stopped is performed using direct means or diagnostics. The testing includes effects of rapid pump starts and stops as required by expected system operating conditions.

valves to be tested, the safety-related functions of the valves, and the type of testing to be done erify the capability of the valves to perform the safety-related functions are outlined in valve rvice test requirements found in Subsection 3.9.6 and Table 3.9-16. The valves to be tested, ty-related functions, and test requirements for preoperational testing are the same as outlined in rvice test requirements.

ing pre-operational testing the following is verified to demonstrate the acceptability of the tional performance.

The valves are verified to fully open or fully closed under design flow conditions.

The disc movement from full open to full close is free.

The valve leakage when fully closed is within established limits, as applicable.

The disc is stable in the full open position at the system operating flow, conditions.

The valve disc position can be verified without disassembly of the valve.

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The testing requirements in the inservice test plan can be accommodated in the piping system design.

8.5.2 Motor-Operated Valves ive safety-related motor-operated valves are tested to verify that the valves open and close under ic and safety-related design conditions. Where the safety-related design conditions cannot be ieved, the testing is performed at the maximum achievable dynamic conditions. During the testing cal parameters needed to determine the required closing and opening loads are measured.

se parameters include thrust, torque, travel, differential pressure, system pressure, fluid flow, age, temperature, operating time and thrust/torque at seating, unwedging and at control switch The data collected during the testing on the parameters is used to determine the required rator loads and output capability for the design operating conditions in conjunction with the nostic equipment inaccuracies, load changes for increasing differential pressures and flow and ient temperature and reduction in motor voltage, control switch repeatability, friction variations changes in other parameters that could result in an increase in operating loads or decrease in rator output capability. The resulting operating loads including uncertainties are then compared to structural capabilities of the motor-operated valve.]* Active safety-related motor-operated valves tested prior to operation for operability as described in Subsection 3.9.3.2.2.

-operational testing and evaluation is used to demonstrate the acceptability of the valves tional performance including the following.

The valves are verified to open and close as applicable at a range of safety-related conditions up to the design conditions to perform their safety function.

The control switch settings must be adequate to provide margin for diagnostic accuracy, control switch repeatability, load sensitive behavior and degradation.

The motor operator capability at degraded voltage must exceed the required operating loads and the loads at the control switch settings including diagnostic equipment inaccuracies, load changes for increasing differential pressures and flow, control switch repeatability, friction variations and other parameters that could result in an increase in operating loads or decrease in operator output capability.

The maximum operating loads including diagnostic equipment inaccuracies, load changes for increasing differential pressures and flow, control switch repeatability, friction variations and other parameters that could result in an increase in operating loads or decrease in operator output capability are verified not to exceed the allowable structural capability limits of the motor-operated valve components.

The stroke time measurements during opening and closing must be within the design requirements if stroke time is important to the safety function.

The remote position indication is verified against the local position indication.

The valve leakage when fully closed is within established limits, as applicable.

Staff approval is required prior to implementing a change in this information.

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es under static and design conditions. Where the design conditions cannot be achieved, the ing is performed at the maximum achievable dynamic conditions. During the testing, critical ameters needed to determine the required closing and opening loads are measured. These ameters include seat load, torque or thrust, travel, spring rate, differential pressure, system sure, fluid flow, temperature, power supply, operating time and minimum supply pressure. The collected during the testing on the parameters is used to determine the required operating loads he design operating conditions in conjunction with the diagnostic equipment inaccuracies and r parameters that could result in an increase in operating loads or decrease in operator output ability. The resulting operating loads including uncertainties are then compared to the structural abilities of the power-operated valve.]*

ing pre-operational testing the following are verified to demonstrate the acceptability of the tional performance.

The valves are verified to open and close as applicable at a range of conditions up to the design conditions to perform its safety function.

For air-operated valves and hydraulically-operated valves the operator capability at minimum supply pressure, power supply or loss of motive force exceed the required operating loads including diagnostic equipment inaccuracies and other parameters that could result in an increase in operating loads or decrease in operator output capability.

For solenoid-operated valves the valve must be capable of opening or closing the valve at the minimum power supply.

For air-operated valves and hydraulically-operated valves the maximum operating loads including diagnostic equipment inaccuracies and other parameters that could result in an increase in operating loads are verified not to exceed the allowable structural capability limits of the power-operated valve components.

The stroke time measurements during opening and closing must be within the design requirements for safety-related functions.

The remote position indication is verified against the local position indication.

The valve leakage when fully closed is within established limits, as applicable.

9 Reactor Coolant System Pressure Relief Devices ety valves connected to the pressurizer provide overpressure protection for the reactor coolant em during power operation. The relief valve on the suction line of the normal residual heat oval system (RNS) provides low temperature overpressure protection consistent with the elines of NRC Branch Technical Position RSB 5-2. The following discusses the requirements for valves. Sizing of the safety valves is discussed in Subsection 5.2.2.

er-operated relief valves are not provided in the AP1000 reactor coolant system. Non-reclosing sure relief devices are not used for pressure relief on the AP1000 reactor coolant system.

tion 10.3 discusses safety valves for the main steam system. The automatic depressurization es which are also connected to the pressurizer and are the interface with the passive core ling system, are not pressure relief devices. (See Subsection 5.4.6.)

Staff approval is required prior to implementing a change in this information.

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e resulting from complete loss of load. The safety valve on the suction line of the normal residual t removal system can accommodate the flow from both makeup pumps with no letdown and a er-solid reactor coolant system during low-temperature modes. Table 5.4-17 gives design ameters for the pressurizer safety valves and the residual heat removal system relief valve.

of the pressurizer safety valves and the normal residual heat removal relief valve at elevated peratures in post-accident environments is not anticipated.

9.2 Design Description pressurizer safety valves and the normal residual heat removal system relief valve are spring ed, self-actuated by direct fluid pressure, and have backpressure compensation features. These es are designed to reclose and prevent further flow of fluid after normal conditions have been ored. The pressurizer safety valves are of the totally enclosed pop type. The normal residual heat oval relief valve is designed for water relief.

pressurizer safety valves are incorporated in the pressurizer safety and relief valve (PSARV) ule, which provides the connection to the pressurizer nozzles. The routing of pipe between the surizer and the safety valves does not include a loop seal. Any condensation of steam in the necting pipe up to the valve rains back to the pressurizer. Condensate does not collect as a slug ater to be discharged during the initial opening of the valve. The discharge of the safety valve is ed through a rupture disk to containment atmosphere. The rupture disk is provided to contain age past the valve, is designed for a substantially lower set pressure than the safety valve set sure, and does not function as a relief device. The reactor coolant system Piping and rumentation Drawing (Figure 5.1-5) shows the arrangement of the safety valves.

relief valve in the normal residual heat removal system is located between the suction line of the p and the valve that isolates the residual heat removal system from the reactor coolant system.

discharge from that valve is directed to the containment atmosphere. Subsection 5.4.7 usses the residual heat removal system. Figure 5.4-6 shows a simplified sketch of the normal dual heat removal system.

ccordance with the requirements of 10 CFR 50.34(f)(2)(xi), positive position indication is provided he pressurizer safety valves and the normal residual heat removal system relief valve, which ide overpressure protection for the reactor coolant pressure boundary.

peratures in the safety valve discharge lines are measured, and an indication and a high perature alarm are provided in the control room. An increase in a discharge line temperature is an cation of leakage or relief through the associated valve. Leakage past the pressurizer safety valve ng normal operation is collected and directed to the reactor coolant drain tank. Section 7.5 usses the functional requirements for the instrumentation required to monitor the safety valves.

9.3 Design Evaluation pressurizer safety valves prevent reactor coolant system pressure from exceeding 110 percent ystem design pressure, in compliance with the ASME Code,Section III. The relief valve on the ion line of the normal residual heat removal system protects that system from exceeding percent of the design pressure of the system and from exceeding the pressure-temperature s determined from ASME Code, Appendix G, analyses.

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ed on full flow at 2575 psia, assuming 3 percent accumulation.

ertain design basis events described in Chapter 15, the pressurizer safety valves are predicted to rate with very low flow rates. For these events, the reactor coolant system pressure is slowly easing as a result of the mismatch between the decay heat removal rate from the passive dual heat removal heat exchanger and the core decay heat. This slow pressurization of the tor coolant system results in a small amount of steam flow through the safety valves. Under e conditions, the safety valves do not fully open and would not experience significant cycling.

ration of the safety valves under these conditions could result in small leakage from the valve ch less than the capacity of the normal makeup system), but does not impair the valve rpressure protection capability.

relief valve on the normal residual heat removal system has an accumulation of 10 percent of the pressure. The set pressure is the lower of the pressure based on the design pressure of the dual heat removal system and the pressure based on the reactor vessel low temperature sure limit. The pressure limit determined based on the design pressure includes the effect of the sure rise across the pump. The set pressure in Table 5.4-17 is based on the reactor vessel low perature pressure limit. The lowest permissible set pressure is based on the required net positive ion head for the reactor coolant pump.

9.4 Tests and Inspections safety and relief valves are the subject of a variety of tests to validate the design and to verify sure boundary and functional integrity. For valves that are required to function during a Service el D condition, static deflection tests are performed to demonstrate operability. Section 3.10 cribes these tests.

ety valves similar to those connected to the pressurizer have been tested within the Electric er Research Institute (EPRI) safety and relief valve test program. Capacity data for the specific 000 safety valve size has been correlated with the EPRI test data to demonstrate that the valve dequate for steam flow and water flow, even though water flow is not anticipated through the surizer safety valves. The completion of this program addresses the requirements of CFR 50.34(f)(2)(x) as related to reactor coolant system relief and safety valve testing. The normal dual heat removal system relief valve is designed for water relief and is not a reactor coolant em pressure relief device since it has a set pressure less than reactor coolant system design sure. Therefore, the valve selected for the normal residual heat removal system relief valve is pendent from the Electric Power Research Institute safety and relief valve test program.

ctor coolant system pressure relief devices are subjected to preservice and inservice hydrostatic s, seat leakage tests, operational tests, and inspections, as required. The preservice and rvice inspection and testing programs for valves are described in Subsections 3.9.6 and 5.2.4 Section 6.6. The test program for the safety valves complies with the requirements of ASME endix I of the OM Code.

pressure boundary portion of the valves are required to be inservice inspected according to the s of Section XI of the ASME Code. There are no full-penetration welds within the valve body

s. Valves are accessible for disassembly and internal visual inspection.

e testing of the pressurizer safety valves is performed to verify that the pressurizer safety valves rate with low flow at pressures near the valve set pressure. Type tests are performed to correlate leakage through the safety valves as a function of inlet pressure, at pressures near the valve set 5.4-54 Revision 1

or equal to that modeled in the accident analyses. The testing demonstrates that the valves leak flow rate of at least 0.35 lbm/sec at a pressure below the valve full-open pressure. The valve full-n pressure is the pressure at which the safety valve opens with significant blowdown flow. The ation of the testing need not duplicate the times indicated in the accident analysis results but uld last for a sufficient time to demonstrate stable valve operation. Stable valve performance out excessive valve cycling or chattering for a 15 minute time duration is sufficient. Following this ing, the valve integrity is demonstrated, and the valve leakage is required to be less than the eup capability of the chemical and volume control system makeup pumps.

10 Component Supports 10.1 Design Bases ponent supports provide deadweight support for the piping and equipment, allow lateral thermal ement of the loop during plant operation, and restrain the loops and components during accident seismic conditions. Subsection 3.9.3 discusses the loading combinations and design stress

s. Support design is according to the ASME Code,Section III, Subsection NF.

design provides for the integrity of the reactor coolant pressure boundary for normal, seismic, accident conditions. The design also maintains the piping stresses less than ASME Code limits less than the limits required to support mechanistic pipe break discussed in Subsection 3.6.3.

tion 3.9 presents the results of piping and supports stress evaluations. The loads associated with dynamic effects of postulated pipe rupture for pipes 6" and larger, which satisfied the uirements for mechanistic pipe break, are not included. See Subsection 3.6.3.

edition of the ASME code,Section III, subsection NF, which is used as the baseline requirement, ress the guidance of Regulatory Guides 1.124 and 1.130. The plant design is in conformance these requirements of the ASME Code. Conformance with Regulatory Guides 1.124 and 1.130 scussed in detail in Section 1.9. The embedded portions of the component supports are designed ording to AISC N690 and ACI 349, as discussed in Subsection 3.8.3.

10.2 Design Description support structures are welded, structural steel sections. Linear structures (tension and pression struts, columns, and beams) are used except for the reactor vessel supports, which are e-and-shell-type structures. Attachments to the supported equipment are either integral (welded e component) or non-integral (pinned to, bolted to, or borne against the components). The ports-to-concrete attachments are either brackets welded to heavy embedded plates or anchor s or are embedded fabricated assemblies.

supports permit thermal growth of the supported systems but restrain vertical and lateral ement resulting from seismic and pipe-break loadings. This is accomplished by using pinned s in the vertical support columns, girders, bumper pedestals, and hydraulic snubbers, and lateral ts.

ause of manufacturing and construction tolerances, ample adjustment for the support structures ides proper erection alignment and fit-up. This is accomplished by shimming or grouting at the ports-to-concrete interface and by shimming at the supports-to-equipment interface.

supports for the various components are described in the following paragraphs.

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inlet nozzles (See Figure 3.8.3-4). The boxes are air-cooled to achieve a concrete design perature of 200°F. To reduce heat transfer from the nozzle to the concrete, cooled air is baffled ically through the support, and the heated air is vented at the top.

ical and horizontal loads are transmitted from the reactor vessel nozzle pad to the box structure ugh an integral recessed pocket at the top of the box. The nozzle pad bears on permanently icated wear plates that allow radial thermal movements of the nozzle with minimal friction stance to the movement. The vessel support boxes transfer loads from the reactor pressure sel to vertical and horizontal embedments in the primary shield wall concrete.

10.2.2 Steam Generator hown in Figure 3.8.3-5, each steam generator support consists of the following:

tical Support vertical support consists of a single vertical column extending from the steam generator partment floor to the bottom of each steam generator channel head. The column is constructed heavy wide flange section, and is pinned at both ends to permit thermal movement of each m generator during plant heatup and cooldown. The column is located so that it allows full ess to the steam generator for routine maintenance activities. It is located far enough from the tor coolant pump motors to permit pump maintenance and inservice inspection.

er Lateral Support lower horizontal support is located at the bottom of the channel head. It consists of a tension/

pression strut oriented nearly perpendicular to the hot leg. The strut is pinned at both the wall ket and the steam generator channel head to permit movement of the steam generator during t heatup and cooldown.

per Lateral Support upper horizontal support in the direction of the hot leg is located on the upper shell just above the sition cone. It consists of two large hydraulic snubbers oriented parallel with the hot leg terline. One snubber is mounted on each side of the generator on top of the steam generator partment wall. The hydraulic snubbers are valved to permit relatively unrestricted steam erator movement during thermal transient conditions, and to lock up and act as a rigid strut er dynamic loads.

upper steam generator horizontal support in the direction normal to the hot leg is located on the er shell just below the transition cone. It consists of two rigid struts oriented perpendicular to the leg. The two rigid struts are mounted on the steam generator compartment wall at the elevation of operating deck. The steam generator loads are transferred to the struts and snubbers through nions on the generator shell.

10.2.3 Reactor Coolant Pump reactor coolant pumps are supported entirely by the steam generators; consequently, there are eactor coolant pump supports.

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Four steel columns attached to the lower head to provide vertical support for the pressurizer.

Struts connected to the lower head and surrounding walls provide lateral support.

The upper lateral support consists of a box-type ring girder that surrounds the pressurizer.

The support connects to the corners of the pressurizer cubicle walls with eight standard sway struts. The girder rests on and is supported vertically by the pressurizer valve support brackets. The pressurizer upper support also supports the pressurizer safety relief piping and valve module, in addition to providing lateral support to the pressurizer.

10.2.5 Control Rod Drive Mechanism Supports support for the control rod drive mechanism is provided by the integrated head package, as cribed in Subsection 3.9.7.

10.3 Design Evaluation evaluation verifies the design adequacy and structural integrity of the reactor coolant loop and the ary equipment supports system. This evaluation compares the analytical results with established ria for acceptability. Structural analyses demonstrate design adequacy for safety and reliability of plant in case of a seismic disturbance, and/or loss of coolant accident conditions. Loads that the em is expected to encounter during its lifetime (thermal, weight, and pressure) are applied, and sses are compared to allowable values. Subsection 3.9.3 discusses the modeling and analysis hods.

10.4 Tests and Inspections destructive examinations are performed according to the procedures of the ASME Code, tion V, except as modified by the ASME Code,Section III, Subsection NF.

11 Pressurizer Relief Discharge AP1000 does not have a pressurizer relief discharge system. The AP1000 has neither power rated pressurizer relief valves nor a pressurizer relief discharge tank. Some of the functions ided by the pressurizer relief discharge system in previous nuclear power plants are provided by ions of other systems in the AP1000.

safety valves connected to the top of the pressurizer provide for overpressure protection of the tor coolant system. First-, second-, and third-stage automatic depressurization system valves ide for depressurization of the reactor coolant system and venting of noncondensable gases in pressurizer following an accident. These functions are discussed in Subsections 5.2.2, 5.4.12, in Section 6.3. The AP1000 does not have power operated relief valves connected to the surizer.

discharge of the safety valves is directed through a rupture disk to containment atmosphere.

discharge of the first-, second-, and third-stage automatic depressurization system valves is cted to the in-containment refueling water storage tank. For the automatic depressurization em valves, the following discussion considers only the gas venting function. Only the first stage matic depressurization valves are used to vent non-condensible gases following an accident.

sizing considerations and design basis for the in-containment refueling water storage tank for the 5.4-57 Revision 1

safety valve on the normal residual heat removal system, which provides low temperature rpressure protection, discharges into the containment atmosphere. See Subsection 5.4.7 for a ussion of the connections to and location of the safety valve in the normal residual heat removal em.

11.1 Design Bases containment has the capability to absorb the pressure increase and heat load resulting from the harge of the safety valves to containment atmosphere. The in-containment refueling water age tank has the capability to absorb the pressure increase and heat load from the discharge, uding the water seal, steam and gases, from a first-stage automatic depressurization system e when used to vent noncondensable gases from the pressurizer following an accident. The ting of noncondensable gases from the pressurizer following an accident is not a safety-related tion.

11.2 System Description h safety valve discharge is directed to a rupture disk at the end of the discharge piping. A small is connected to the discharge piping to drain away condensed steam leaking past the safety

e. The discharge is directed away from any safety related equipment, structures, or supports that ld be damaged to the extent that emergency plant shutdown is prevented by such a discharge.

discharge from each of two groups of automatic depressurization system valves is connected to parate sparger below the water level in the in-containment refueling water storage tank. The ng and instrumentation diagram for the connection between the automatic depressurization em valves and the in-containment refueling water storage tank is shown in Figure 6.3-1. The ontainment refueling water storage tank is a stainless steel lined compartment integrated into the tainment interior structure. The discharge of water, steam, and gases from the first-stage matic depressurization system valves when used to vent noncondensable gases does not result ressure in excess of the in-containment refueling water storage tank design pressure.

itionally, vents on the top of the tank protect the tank from overpressure, as described in section 6.3.2.

rflow provisions prevent overfilling of the tank. The overflow is directed into the refueling cavity.

in-containment refueling water storage tank does not have a cover gas and does not require a nection to the waste gas processing system. The normal residual heat removal system provides safety-related cooling of the in-containment refueling water storage tank.

11.3 Safety Evaluation design of the control for the reactor coolant system and the volume of the pressurizer is such a discharge from the safety valves is not expected. The containment design pressure, which is ed on loss of coolant accident considerations, is greatly in excess of the pressure that would lt from the discharge of a pressurizer safety valve. The heat load resulting from a discharge of a surizer safety valve is considerably less than the capacity of the passive containment cooling em or the fan coolers. See Section 6.2.

ting of noncondensable gases, including entrained steam and water from the loop seals in the s to the automatic depressurizations system valves, from the pressurizer into spargers below the er line in the in-containment refueling water storage tank does not result in a significant increase 5.4-58 Revision 1

uired for venting of noncondensable gases from the pressurizer following an accident.

11.4 Instrumentation Requirements instrumentation for the safety valve discharge pipe, containment, and in-containment refueling er storage tank are discussed in Subsections 5.2.5, 5.4.9, and in Sections 6.2 and 6.3, ectively. Separate instrumentation for the monitoring of the discharge of noncondensable gases ot required.

11.5 Inspection and Testing Requirements tions 6.2 and 6.3 discuss the requirements for inspection and testing of the containment and ontainment refueling water storage tank, including operational testing of the spargers. Separate ing is not required for the noncondensable gas venting function.

12 Reactor Coolant System High Point Vents requirements for high point vents are provided for the AP1000 by the reactor vessel head vent es and the automatic depressurization system valves. The primary function of the reactor vessel d vent is for use during plant startup to properly fill the reactor coolant system and vessel head.

h reactor vessel head vent valves and the automatic depressurization system valves may be vated and controlled from the main control room. The AP1000 does not require use of a reactor sel head vent to provide safety-related core cooling following a postulated accident.

reactor vessel head vent valves (Figure 5.4-8) can remove noncondensable gases or steam the reactor vessel head to mitigate a possible condition of inadequate core cooling or impaired ral circulation through the steam generators resulting from the accumulation of noncondensable es in the reactor coolant system. The design of the reactor vessel head vent system is in ordance with the requirements of 10 CFR 50.34 (f)(2)(vi).

reactor vessel head vent valves can be operated from the main control room to provide an rgency letdown path which is used to prevent pressurizer overfill following long-term loss of heat events. An orifice is provided downstream of each set of head vent valves to limit the emergency own flow rate.

first stage valves of the automatic depressurization system are attached to the pressurizer and ide the capability of removing noncondensable gases from the pressurizer steam space following ccident. Venting of noncondensable gases from the pressurizer steam space is not required to ide safety-related core cooling following a postulated accident. Gas accumulations are removed emote manual operation of the first stage automatic depressurization system valves.

discharge of the automatic depressurization system valves is directed to the in-containment eling water storage tank. Subsection 5.4.6 and Section 6.3 discuss the automatic ressurization system valves and discharge system.

passive residual heat removal heat exchanger piping and the core makeup tank inlet piping in passive core cooling system include high point vents that provide the capability of removing condensable gases that could interfere with heat exchanger or core makeup tank operation.

se gases are normally expected to accumulate when the reactor coolant system is refilled and surized following refueling shutdown. Any noncondensable gases that collect in these high ts can be manually vented.

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t exchanger and venting capability, which is part of the passive core cooling system.

12.1 Design Bases reactor vessel head vent arrangement is designed to remove noncondensable gases or steam the reactor coolant system via remote manual operations from the main control room through a of valves. The system discharges to the in-containment refueling water storage tank (IRWST).

reactor vessel head vent system is designed to provide an emergency letdown path that can be d to prevent long-term pressurizer overfill following loss of heat sink events. The reactor vessel d vent is designed to limit the emergency letdown flow rate to within the capabilities of the normal eup system. The reactor vessel head vent system can also vent noncondensable gases from the tor head in case of a severe accident.

system vents the reactor vessel head by using only safety-related equipment. The reactor vessel d vent system satisfies applicable requirements and industry standards, including ASME Code sifications, safety classifications, single-failure criteria, and environmental qualification.

piping and equipment from the vessel head vent up to and including the second isolation valve designed and fabricated according to ASME CodesSection III, Class 1 requirements. The ainder of the piping and equipment are design and fabricated in accordance with ASME Code, tion III, Class 3 requirements.

supports and support structures conform with the applicable requirements of the ASME Code.

Class 1 piping used for the reactor vessel head vent is 1-inch schedule 160. In accordance with ME Section III it is analyzed following the procedures of NC-3600 for Class 2 piping.

piping stresses meet the requirements of ASME Code,Section III, NC-3600, with a design perature of 650°F and a design pressure of 2485 psig.

automatic depressurization system functions as a part of the passive core cooling system. The stage automatic depressurization system valves are connected to the pressurizer. The valves designed, constructed, and inspected to ASME Code Class 1 and seismic Category I uirements. Subsection 5.4.6 and Section 6.3 discuss the design bases for the automatic ressurization system and automatic depressurization system valves.

primary function of the passive residual heat removal heat exchanger and core makeup tank point vents is to prevent accumulation of noncondensable gases from the reactor coolant em that could interfere with operation of the passive core cooling system. Section 6.3 discusses design bases for the passive residual heat removal heat exchanger, the core makeup tanks, and r vent lines.

12.2 System Description reactor vessel head vent arrangement consists of two flow paths, each with redundant isolation es. Orifices are located downstream of each set of head vent isolation valves to limit the reactor sel head vent flow rate. Table 5.4-18 lists the equipment design parameters. The reactor vessel d vent arrangement is shown on the reactor coolant system piping and instrumentation diagram ure 5.1-5).

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eactor coolant pressure boundary leakage. The solenoid-operated isolation valves are powered he safety-related Class 1E DC and UPS system. The solenoid-operated isolation valves are fail-ed, normally closed valves. The valves are included in the valve operability program and are lified to IEEE-323, IEEE-344, and IEEE-382.

vent system piping is supported such that the resulting loads and stresses on the piping and on vent connection to the vessel head are acceptable.

automatic depressurization system valves are included as part of the pressurizer safety and f valve module attached to the top of the pressurizer and are connected to the pressurizer zles. The automatic depressurization system includes a group of valves attached to the reactor lant system hot leg that are not used to vent noncondensable gases. The pressurizer safety and f valve module is supported by an attachment to the top of the pressurizer and provides support he automatic depressurization system valves. The automatic depressurization system valves are ve valves required to provide safe shutdown or to mitigate the consequences of postulated dents. Subsection 5.4.6 discusses the function control and power requirements for the automatic ressurization system valves.

12.3 Safety Evaluation reactor vessel head vent system is designed so that a single failure of the remotely operated t valves, power supply, or control system does not prevent isolation of the vent path. The two ation valves in the active flow path provide a redundant method of isolating the venting system.

h two valves in series, the failure of any one valve does not inadvertently open a vent path or ent isolation of a flow path. The Chapter 15 accident analysis and supporting analyses are ormed consistent with the reactor vessel head vent system design parameters provided in le 5.4-18.

reactor vessel head vent system has two normally de-energized valves in series in each flow

. This arrangement eliminates the possibility of opening a flow path due to the spurious ement of one valve.

eak of the reactor vessel head vent system line would result in a small loss of coolant accident of greater than one-inch diameter. Such a break is similar to those analyzed in Subsection 15.6.5.

e a break in the head vent line would behave similarly to the hot leg break case presented in section 15.6.5, the results presented therein apply to a reactor vessel head vent system line ak. This postulated vent line results in no calculated core uncovery.

section 5.4.6 and Section 6.3 discuss the evaluation of the automatic depressurization system es. Inadvertent opening of an automatic depressurization system valve is included in the sients considered for specification of the inadvertent reactor coolant system depressurization in section 3.9.1.

tion 6.3 discusses the evaluation of the passive residual heat removal heat exchanger and core eup tanks. These high point vent lines contain two manual isolation valves in series, so that a le failure of either valve to reclose following venting operation does not prevent isolation of the path. The high point vent line from the passive residual heat removal heat exchanger to the ontainment refueling water storage tank contains a flow-restricting orifice such that postulated ak flow is within the makeup capability of the chemical and volume control system and therefore ld not normally require actuation of the passive safety systems.

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tion 6.6. Subsection 3.9.6 discusses inservice testing and inspection of valves. Subsection 5.2.4 usses inservice inspection and testing of ASME Code, Class 1 components that are part of the tor coolant pressure boundary.

requirements for tests and inspections for reactor coolant system valves is found in section 5.4.8.4. In addition, tests for the reactor vessel head vent valves and piping are ducted during preoperational testing of the reactor coolant system, as discussed in Section 14.2.

12.4.1 Flow Testing al verification of the capacity of the reactor vessel head vent valves is performed during the plant al test program. A low pressure flow test and associated analysis is conducted to determine the acity of each reactor vessel head vent flow path. The reactor coolant system is at cold conditions the pressurizer full of water. The normal residual heat removal pumps are used to provide ction flow into the reactor coolant system, discharging through the reactor vessel head vent es. The measured flow rate at low pressure is such that the head vent flow capacity is at least lbm/sec at an RCS pressure of 1250 psia.

12.5 Instrumentation Requirements reactor head vent valves can be operated from the control room or the remote shutdown kstation. The isolation valves in the vent line and automatic depressurization system valves have ition sensors. The position indication from each solenoid-operated isolation valve is monitored in control room.

13 Core Makeup Tank core makeup tank (CMT) in the passive core cooling system stores cold borated water under em pressure for high pressure reactor coolant makeup. See Section 6.3 for a discussion of the ration of the core makeup tank in the passive core cooling system and the connections to the makeup tank.

13.1 Design Bases core makeup tank is designed and fabricated according to the ASME Code,Section III as a ss 1 component. See Subsection 5.2.1. The boundaries of the ASME Code include the pressure-taining materials up to, but excluding, the circumferential welds at nozzle safe ends. The manway er and bolting materials are included within this boundary. The core makeup tank is AP1000 ipment Class A (ANS Safety Class 1, Quality Group A). Stresses are maintained within the limits e ASME Code,Section III. Section 5.2 provides the ASME Code and material requirements.

section 5.2.4 discusses inservice inspection.

erials of construction are specified to minimize corrosion/erosion and to provide compatibility with operating environment, including the expected radiation level. Subsection 5.2.3 discusses the ding, cutting, heat treating and other processes used to minimize sensitization of stainless steel.

rumentation nozzles are welded to the clad inside wall of the vessel according to ASME Code, tion III. Butt welds, branch connection nozzle welds, and boss welds are of a full-penetration ign. Flanges conform to ANSI B16.5.

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ccurrences of the first transient, leakage at power, in the plant lifetime. This event covers ations which a small leak draws in hot reactor coolant system fluid. There are an assumed ccurrences in the plant lifetime of the second transient, increase in containment temperature ve normal operating range.

13.2 Design Description core makeup tank is a low-alloy steel vessel with 308L stainless steel internal cladding. The imum free internal volume for the core makeup tank is 2500 cubic feet. The normal full-power perature and pressure in the core makeup tank are 70° to 120°F and 2250 psia, respectively. The is designed to withstand the design environment of 2500 psia and 650°F. The core makeup tank vertically mounted, cylindrical pressure vessel with hemispherical top and bottom heads.

core makeup tank is supported on columns. One nozzle on the lower head connects the tank to reactor vessel direct vessel injection (DVI) piping. One nozzle in the center of the upper head nects the tank to a line connected to one of the RCS cold legs. The top nozzle incorporates a ser inside the tank. The diffuser has the same diameter and thickness as the connecting piping.

bottom of the diffuser is plugged and holes are drilled in the side. The diffuser forces the steam to turn 90 degrees which limits the steam penetration into the coolant in the core makeup tank.

core makeup tank includes a manway and cover in the shell to allow access to the tank interior.

maintain system pressure, the flowpath from the reactor coolant system cold leg to the upper head e core makeup tank is normally open. The core makeup tank discharge piping flow path from the er head to the reactor vessel is blocked by two normally closed, fail-open, parallel isolation valves.

Section 6.3 for a description of the system operation.

tank includes nozzles and flanges for connection to level detection instrumentation.

sample lines, one in the upper head and the other in the lower head, are provided for sampling solution in the core makeup tank. A fill connection is provided for core makeup tank make up er from the chemical and volume control system.

13.3 Design Evaluation section 3.9.3 discusses the loading combinations, stress limits, and analytical methods for the ctural evaluation of the reactor coolant system core makeup tank for design conditions, normal ditions, anticipated transients, and postulated accident conditions. Subsection 3.9.2 discusses requirements for dynamic testing and analysis. The reactor coolant system design transients for mal operation, anticipated transients and postulated accident conditions are discussed in section 3.9.1.

ss intensities resulting from design loads do not exceed the limits specified in ASME Code, tion III. The rules for the evaluation of the faulted conditions are defined in Appendix F of the ME Code,Section III. Only those stress limits applicable for an elastic system analysis are used he external load analysis.

13.4 Material Corrosion/Erosion Evaluation se portions of the core makeup tank in contact with reactor coolant are fabricated from or clad stainless steel. The water chemistry of the core makeup tank, comparable to reactor coolant, ses minimal corrosion of the stainless steel. Erosion is not an issue, since there is normally no 5.4-63 Revision 1

tamination of stainless steel and nickel-chromium-iron alloys by copper, low-melting-temperature ys, mercury, and lead is prohibited. The material selection, water chemistry specification, and dual stress in the piping minimize the potential for stress corrosion cracking, as discussed in section 5.2.3.

13.5 Test and Inspections rpy V-notch tests and drop-weight fracture toughness tests are performed as required.

ntation of test specimens is according to the ASME Code,Section III, except that the material is considered to be subjected to high irradiation.

pliance with the sensitization requirement is demonstrated by passing the susceptibility to rgranular attack test of ASTM A-262, Practice E, including the oxalic acid screening test ording to Practice A. Inservice inspection requirements for Class 1 are discussed in section 5.2.4.

ddition, materials and welds are inspected according to the requirements of the ASME Code, tion III Class 1.

14 Passive Residual Heat Removal Heat Exchanger passive residual heat removal heat exchanger (PRHR HX) is the component of the passive core ling system that removes core decay heat for any postulated non-loss of coolant accident event re a loss of cooling capability via the steam generators occurs. Section 6.3 discusses the ration of the passive residual heat removal heat exchanger in the passive core cooling system.

14.1 Design Bases passive residual heat removal heat exchanger automatically actuates to remove core decay heat 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as discussed in Section 6.3, assuming the condensate from steam generated in the ontainment refueling water storage tank (IRWST) is returned to the tank. The passive residual t removal heat exchanger is designed to withstand the design environment of 2500 psia and

°F.

passive residual heat removal heat exchanger and the in-containment refueling water storage are designed to delay significant steam release to the containment for at least one hour. The sive residual heat removal heat exchanger will remove sufficient decay heat from the reactor lant system to satisfy the applicable post-accident safety evaluation criteria detailed in Chapter 15 at least 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In addition, the passive residual heat removal heat exchanger will cool the tor coolant system, with reactor coolant pumps operating or in the natural circulation mode, so the reactor coolant system pressure can be lowered to reduce stress levels in the system if uired. See Section 6.3 for a discussion of the capability of the passive core cooling system.

passive residual heat removal heat exchanger is designed and fabricated according to the ME Code,Section III, as a Class 1 component. Those portions of the passive residual heat hanger that support the primary-side pressure boundary and falls under the jurisdiction of ASME e,Section III, Subsection NF are AP1000 equipment Class A (ANS Safety Class 1, Quality up A). Stresses for ASME Code,Section III equipment and supports are maintained within the s of Section III of the Code. Section 5.2 provides ASME Code,Section III and material uirements. Subsection 5.2.4 discusses inservice inspection.

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14.2 Design Description passive residual heat removal heat exchanger consists of an upper and lower tubesheet nted through the wall of the in-containment refueling water storage tank. A series of 0.75-inch r diameter C-shaped tubes connect the tubesheets shown in Figure 6.3-5. The primary coolant ses through the tubes, which transfer decay heat to the in-containment refueling water storage water and generate enough thermal driving head to maintain the flow through the heat hanger during natural circulation. The design minimizes the diameter of the tubesheets and ws ample flow area between the tubes in the in-containment refueling water storage tank.

horizontal lengths of the tubes and lateral support spacing in the vertical section allow for the ntial temperature difference between the tubes at cold conditions and the tubes at hot conditions.

tubes are supported in the in-containment refueling water storage tank interior with a frame cture.

passive residual heat removal heat exchanger is welded to the in-containment refueling water age tank.

14.3 Design Evaluation section 3.9.3 discusses the loading combinations, stress limits, and analytical methods for the ctural evaluation of the passive residual heat removal heat exchanger for design conditions, mal conditions, anticipated transients, and postulated accident conditions. Operation of passive dual heat removal heat exchanger is evaluated using Service Levels B, C, and D plant conditions.

ddition to loads due to conditions in the reactor coolant system and operation of the passive dual heat removal heat exchanger, the passive residual heat removal heat exchanger is luated for hydraulic loads due to discharge of steam from the automatic depressurization system es into a sparger in the in-containment refueling water storage tank. These loads are evaluated g Service Level B limits and are not combined with any other Service Level C or D conditions.

mic, loss of coolant accident, sparger activation and flow-induced vibration loads are derived g dynamic models of the passive residual heat removal heat exchanger. The dynamic analysis siders the hydraulic interaction between the coolant (steam or water) and the system structural ments.

section 3.9.2 discusses the requirements for dynamic testing and analysis. Subsection 3.9.1 usses the reactor coolant system design transients for normal operation, anticipated transients, postulated accident conditions. In addition to reactor coolant system design transients, there are additional Service Level B transients that affect only the passive residual heat removal heat hanger. In the plant lifetime, there are an assumed 30 occurrences of the first transient, leakage ower. This event covers situations in which a small leak in the manway cover draws in hot reactor lant system fluid. There are an assumed 10 occurrences in the plant lifetime of the second sient, increase in in-containment refueling water storage tank temperature, due an event which vates passive core cooling.

ss intensities resulting from design loads do not exceed the limits specified in ASME Code, tion III. The rules evaluating the Service Level D conditions are defined in Appendix F of the ME Code,Section III. Only those stress limits applicable for an elastic system analysis are used he external load analysis.

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re is no flow through the passive residual heat removal heat exchanger during normal plant ration. The tubesheet temperatures are calculated to provide sufficient temperature drop between tubesheet and the attachment to the tank. Section 6.3 describes the passive residual heat oval heat exchanger performance characteristics.

14.4 Material Corrosion/Erosion Evaluation se portions of the passive residual heat removal heat exchanger in contact with reactor coolant fabricated from or clad with corrosion-resistant material. The use of severely sensitized austenitic nless steel in the pressure boundary of the reactor coolant system is prohibited. A periodic lysis of the coolant chemical composition verifies that the reactor coolant quality meets the cifications discussed in Subsection 5.2.3.

phur, lead, copper, mercury, aluminum, antimony, arsenic, and other low-melting-point elements their alloys and compounds are restricted in their use as construction materials, erection aids, ning agents, and coatings for finished surfaces of the passive residual heat removal heat hanger that are in contact with reactor coolant system fluid or in-containment refueling water age tank. Contamination of stainless steel and nickel-chromium-iron alloys by copper, low-ting-temperature alloys, mercury, and lead is prohibited. The material selection, water chemistry cification, and residual stress in the piping minimize the potential for stress corrosion cracking, as ussed in Subsection 5.2.3.

nless steel and nickel-chromium-iron alloys used in the passive residual heat removal heat hanger are procured to ASME specifications.

14.5 Testing and Inspections passive residual heat removal heat exchanger is designed and manufactured to permit inservice ection as specified in the ASME Code,Section XI. Methods and techniques developed for steam erator tube eddy current inspection can be used for the passive residual heat removal heat hanger tubes.

ess for inspection and maintenance is possible through manways in the top and bottom channel ds without draining the in-containment refueling water storage tank.

design of the passive residual heat removal heat exchanger incorporates a flexible member at heat exchanger to in-containment refueling water storage tank interface to minimize the load osed on the wall of the in-containment refueling water storage tank resulting from thermal ansion on the tubesheet.

rostatic tests are performed in accordance with the requirements of the ASME Code,Section III, g working fluids meeting the appropriate water chemistry specifications.

15 Combined License Information Steam Generator Tube Surveillance Program is addressed in Subsection 5.4.2.5.

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Hagg, A. C. and Sankey, G. O., The Containment of Disk Burst Fragments by Cylindrical Shells, ASME Journal of Engineering for Power, April 1974, pp. 114-123.

Not used.

ASTM-E-165-95, Practice for Liquid Penetrant Inspection Method.

ANSI/ANS-5.1-1994, Decay Heat Power in Light Water Reactors.

ANSI/ANS-51.1-1983, Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants.

ANSI N278.1-1975, Self-Operated and Power-Operated Safety-Relief Valves Functional Specification Standard.

ASME QME-1-2007 Edition, Qualification of Active Mechanical Equipment Used in Nuclear Power Plants.

ANSI B16.34-1996, Valves - Flanged and Buttwelding End.

Curtiss-Wright Electro-Mechanical Corporation Report AP1000RCP-06-009-P, Revision 2 (Proprietary), and AP1000RCP-06-009-NP, Revision 2 (Non-Proprietary), Structural Analysis Summary for the AP1000 Reactor Coolant Pump High Inertia Flywheel, July 2009.

. Nuclear Energy Institute, Steam Generator Program Guidelines, NEI 97-06, Revision 2, May 2005.

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it design pressure (psia) 2500 it design temperature (°F) 650 imated Unit overall height (ft) 22 mponent cooling water flow (gpm) 650 ximum continuous component cooling water inlet temperature (°F)(1) 95 al estimated weight motor and casing, dry (lb) 200,000 mp Design flow (gpm) 78,750 Developed head (feet) 365 Pump discharge nozzle, inside diameter (inches) 22 Pump suction nozzle, inside diameter (inches) 26 Speed (synchronous)(rpm) 1800 tor Type Squirrel Cage Induction Voltage (V) 6900 Phase 3 Frequency (Hz) 60 Insulation class Class H or N Current (amp)

Starting Variable Nominal input, cold reactor coolant Variable tor/pump rotor minimum required moment of inertia Sufficient to provide flow coastdown as given in Figure 15.3.2-1 An elevated component cooling water supply temperature of up to 110°F may occur for a 6-hour period.

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Not Used.

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RT(a) UT(a) PT(a) MT(a) stings - Casing (or pressure boundary) X X wheel X X X gings X X te X ldments Circumferential X X X Instrument connections X tor terminals(b) X X s:

RT - radiographic, UT - ultrasonic, PT - dye penetrant, MT - magnetic particle See Subsection 5.4.1.3.3.

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pe Vertical U-tube Feedring-type sign pressure, reactor coolant side (psia) 2500 sign pressure, steam side (psia) 1200 sign pressure, primary to secondary (psi) 1600 sign temperature, reactor coolant side (°F) 650 sign temperature, steam side (°F) 600 G Power, MWt/unit 1707.5 al heat transfer surface area (ft2) 123,538 am nozzle outlet pressure, psia 836 am flow, lb/hr per S/G 7.49x106 al steam flow, lb/hr 14.97x106 ximum moisture carryover (weight percent) maximum 0.25 load temperature, °F 557 edwater temperature, °F 440 mber of tubes per unit 10,025 be outer diameter, inch 0.688 be wall thickness, inch 0.040 be pitch, inches 0.980 (triangular) 5.4-71 Revision 1

(Nominal Values) be pitch, inches 0.980 (triangular) erall length, inches 884.26*

per shell I.D., inches 210 wer shell I.D., inches 165 besheet thickness, inches 31.13**

mary water volume, ft3 2077 Water volume in tubes, ft3 1489 Water volume in plenums, ft3 588 condary water volume, ft3 3646 condary steam volume, ft3 5222 condary water mass, lbm 175,758 sign fouling factor, hr-°F-ft2/BTU 9.0 x 10-5 s:

Measured from steam nozzle to the flat, exterior portion of the channel head.

Base metal thickness.

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RT(a) UT(a) PT(a) MT(a) ET(a) se Metals besheet Forging Yes Yes annel Head Forging Yes Yes Plate Yes Casting Yes Yes condary Shell and Head Forgings Yes Yes Plate Yes bes Yes Yes zzles (Forgings) Yes Yes fe ends Yes Yes lds annel head if fabricated Yes Yes ssure boundary, longitudinal if fabricated Yes Yes ssure boundary, circumferential Yes Yes mary nozzles to fabricated head Yes Yes mary nozzles to forged head Yes Yes nways to fabricated head or shell Yes Yes nways to forged head or shell Yes Yes am and feedwater nozzles to fabricated shell Yes Yes am and feedwater nozzles to forged shell Yes Yes pport brackets Yes be to tubesheet Yes trument connections (secondary) Yes mporary attachments after removal Yes er hydrostatic test (all major pressure boundary welds Yes d complete cast channel head where accessible) ld deposit on primary nozzles Yes Yes fe end to nozzle Yes Yes dding besheet Yes(b) Yes annel head Yes Yes dding (channel head-tubesheet joint cladding Yes Yes toration) s:

RT - Radiographic, UT - Ultrasonic, PT - Dye penetrant, MT - Magnetic particle, ET - Eddy current.

Flat surfaces only 5.4-73 Revision 1

actor Coolant Loop Piping Design Pressure (psig) 2485 Design Temperature (°F) 650 actor Inlet Piping Inside Diameter (ID) 22 Nominal Wall Thickness 2.56 actor Outlet Piping Inside Diameter (ID) 31 Nominal Wall Thickness 3.25 ssurizer Surge Line Design Pressure (psig) 2485 Design Temperature (°F) 680 ssurizer Surge Line Piping Nominal Pipe Size 18 Nominal Wall Thickness 1.78 ssurizer Safety Valve and ADS Valve Inlet Line Design Pressure (psig) 2485 Design Temperature (°F) 680 her Rector Coolant Branch Lines Design Pressure (psig) 2485 Design Temperature (°F) 650 5.4-74 Revision 1

RT(a) UT(a) PT(a) e (Forged Seamless) Yes Yes ings Yes Yes ldments Circumferential Butt Welds Yes Yes Branch Nozzle Connections Yes(b) Yes Fillet Weld Instrument Connections Yes s:

RT - Radiographic; UT - Ultrasonic; PT - Dye Penetrant No RT is required for branch nozzle connections of 4 inch nominal size smaller.

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sign pressure (psig) 2485 sign temperature (°F) 680 rge line nozzle nominal diameter (in.) 18 ray line nozzle nominal diameter (in.) 4 fety valve nozzle nominal diameter (in.) 14 ernal volume (ft3) 2100 5.4-76 Revision 1

tage (Vac) 480 quency (Hz.) 60 wer Capacity (kW)

Control Group 370 Backup Group A 245 Backup Group B 245 Backup Group C 370 Backup Group D 370 5.4-77 Revision 1

Base Load Mode (Psig) drostatic test pressure 3106 sign pressure 2485 fety valves (begin to open) 2485 h pressure reactor trip 2385 h pressure alarm 2310 ssurizer spray valves (full open) 2310 ssurizer spray valves (begin to open) 2260 portional heaters (begin to operate) 2250 erating pressure 2235 portional heater (full operation) 2220 ckup heaters on 2210 w pressure alarm 2210 w pressure safeguards actuation 1795 5.4-78 Revision 1

RT(a) UT(a) PT(a) MT(a) ads Forged head Yes Cladding Yes Yes ell Forgings Yes Yes Cladding Yes Yes aters Tubing Yes(b) Yes Centering of element Yes zzle (Forgings) Yes Yes(c) Yes(c) ldments Shell, circumferential Yes Yes Nozzle to head (if fabricated) Yes Yes Cladding Yes Yes Nozzle safe end Yes Yes Instrument nozzle Yes Temporary attachments Yes (after removal)

Boundary welds Yes (after shop hydrostatic tests)

Support brackets Yes s:

RT - Radiographic, UT - Ultrasonic, PT - Dye Penetrant, MT - Magnetic Particle.

Eddy current testing can be used in lieu of UT.

MT or PT.

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S initiation, hours after reactor shutdown 4 S initial pressure (psig) 450 S initial temperature (°F) 350 S Design Temperature (°F)(a) 95 oldown time, (hours after shutdown) 96 S temperature at end of cooldown (°F) 125 The maximum CCS temperature during cooldown is 110°F.

5.4-80 Revision 1

rmal RHR Pumps (per pump) nimum Flow Required for Shutdown Cooling (gpm) 1400 nimum Flow Required for Low Pressure Makeup (gpm) 1100 sign Flow (gpm) 1500 sign Head (ft) 360 rmal RHR Heat Exchangers nimum UA Required for Shutdown Cooling (BTU/hr-°F) 2.2 x 106 sign Heat Removal Capacity (BTU/hr)(1) 23 x 106 Tube Side Shell Side sign Flow (lb/hr) 750,000 1,405,000 et Temperature (°F) 125 87.5 tlet Temperature (°F) 94 104 id Reactor Coolant CCS Design heat removal capacity is based on decay heat at 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after reactor shutdown.

5.4-81 Revision 1

sign pressure (psig) 2485 operational plant hydrotest (psig) 3106 sign temperature (°F)

Reactor coolant system 650 Pressurizer safety valves and ADS valves 680 5.4-82 Revision 1

Normal P (PSIG)(a) Design P (PSIG)

OPEN CLOSE OPEN CLOSE st Stage ADS Valves 2235 2235(b,c) 2485 2485 CS-PL-V001A & B) st Stage ADS Isolation Valves 2235 2235 2485 2485 CS-PL-V011A & B) cond Stage ADS Valves 1200 100(b) 2485 1200 CS-PL-V002A & B) cond Stage ADS Isolation Valves 1200 100 2485 1200 CS-PL-V012A & B) rd Stage ADS Valves 500 100 2485 1200 CS-PL-V003A & B) rd Stage ADS Isolation Valves 500 100 2485 1200 CS-PL-V013A & B) urth Stage ADS Isolation Valves N/A(e) 0 200(e) 200 CS-PL-V014A & B)

S Purification Isolation Valves 2235 2235 2485 2485 VS-PL-V001,-V002,-003) rmal RHR Inner/Outer Isolation 450 450 600 600 ves NS-PL-V001A,B -V002A,B)(d) s:

Normal expected operating pressures.

Valves are prevented from closing until ADS signal is reset.

First stage ADS valve can be manually actuated for controlled depressurizations or gas venting.

Valves are administratively blocked from opening at the motor control center.

Fourth stage ADS block valves are normally open.

5.4-83 Revision 1

mber 2 nimum required relieving capacity per valve (lb/hr) 750,000 at 3% accumulation t pressure (psig) 2485 +/-25 psi sign temperature (°F) 680 id Saturated steam ckpressure Normal (psig) 3 to 5 Expected maximum during discharge (psig) 500 vironmental conditions Ambient temperature (°F) 50 to 120 Relative humidity (percent) 0 to 100 Residual Heat Removal Relief Valve - Design Parameters mber 1 minal relieving capacity per valve, ASME flowrate (gpm) 850 minal set pressure (psig) 500*

l-open pressure, with accumulation (psig) 550*

sign temperature (°F) 400 id Reactor coolant ckpressure Normal (psig) 3 to 5 Expected maximum during discharge (psig) 21 vironmental conditions Ambient temperature (°F) 50 to 120 Relative humidity (percent) 0 to 100 See text (Subsection 5.4.9.3) for discussion of set pressure 5.4-84 Revision 1

stem design pressure, psig 2485 stem design temperature, °F 650 mber of remotely-operated valves 4 nt line, nominal diameter, inches 1 ad vent capacity, lbm/sec (assuming a single failure, RCS pressure at 1250 psia) 8.2 5.4-85 Revision 1

Figure 5.4-1 Reactor Coolant Pump 5.4-86 Revision 1

Figure 5.4-2 Steam Generator 5.4-87 Revision 1

Figure 5.4-3 Support Plate Geometry (Trifoil Holes) 5.4-88 Revision 1

Figure 5.4-4 Surge Line 5.4-89 Revision 1

Figure 5.4-5 Pressurizer 5.4-90 Revision 1

Figure 5.4-6 Normal Residual Heat Removal System 5.4-91 Revision 1

WLS 1&2 - UFSAR Figure 5.4-7 Normal Residual Heat Removal System Piping and Instrument Diagram 5.4-92 Revision 1

Figure 5.4-8 Reactor Vessel Head Vent System 5.4-93 Revision 1