ML18079A445

Korea Hydro-Nuclear Power Co., Ltd (Design Control Document) Rev.2 - Tier2 Chapter05-Reactor Coolant System and Connecting Systems

ML18079A445
Person / Time
Site:	05200046
Issue date:	03/08/2018
From:	Kim H Korea Hydro & Nuclear Power Co, Ltd
To:	Office of New Reactors
Ward W
References
KOREAHYDRONUC, KOREAHYDRONUC.SUBMISSION.8, APR1400.DCD.NS, APR1400.DCD.NS.3
Download: ML18079A445 (371)

Text

APR1400 DESIGN CONTROL DOCUMENT TIER 2 CHAPTER 5 REACTOR COOLANT SYSTEM AND CONNECTING SYSTEMS APR1400-K-X-FS-14002-NP REVISION 2 FEBRUARY 2018

2018 KOREA ELECTRIC POWER CORPORATION KOREA HYDRO & NUCLEAR POWER CO., LTD All Rights Reserved This document was prepared for the design certification application to the U.S. Nuclear Regulatory Commission and contains technological information that constitutes intellectual property of Korea Hydro & Nuclear Power Co., Ltd.

Copying, using, or distributing the information in this document in whole or in part is permitted only to the U.S. Nuclear Regulatory Commission and its contractors for the purpose of reviewing design certification application materials. Other uses are strictly prohibited without the written permission of Korea Electric Power Corporation and Korea Hydro & Nuclear Power Co., Ltd.

Rev. 2

APR1400 DCD TIER 2 CHAPTER 5 - REACTOR COOLANT SYSTEM AND CONNECTING SYSTEMS TABLE OF CONTENTS NUMBER TITLE PAGE CHAPTER 5 - REACTOR COOLANT SYSTEM AND CONNECTING SYSTEMS5.1-1 5.1 Summary Description .......................................................................................... 5.1-1 5.1.1 Schematic Flow Diagram ........................................................................ 5.1-3 5.1.2 Flow Diagram .......................................................................................... 5.1-3 5.1.3 Elevation Drawings ................................................................................. 5.1-5 5.1.4 Combined License Information ............................................................... 5.1-5 5.1.5 References ............................................................................................... 5.1-5 5.2 Integrity of the Reactor Coolant Pressure Boundary ....................................... 5.2-1 5.2.1 Conformance with Codes and Code Cases .............................................. 5.2-1 5.2.1.1 Conformance with 10 CFR 50.55a ......................................... 5.2-1 5.2.1.2 Compliance with Applicable Code Cases............................... 5.2-2 5.2.2 Overpressure Protection .......................................................................... 5.2-2 5.2.2.1 Design Bases .......................................................................... 5.2-3 5.2.2.2 Design Evaluation .................................................................. 5.2-6 5.2.2.3 Flow Diagrams ....................................................................... 5.2-9 5.2.2.4 Equipment and Component Description ................................ 5.2-9 5.2.2.5 Mounting of Pressure-Relief Devices .................................. 5.2-12 5.2.2.6 Applicable Codes and Classification .................................... 5.2-14 5.2.2.7 Material Specifications ......................................................... 5.2-15 5.2.2.8 Process Instrumentation........................................................ 5.2-15 5.2.2.9 System Reliability ................................................................ 5.2-15 5.2.2.10 Testing and Inspection .......................................................... 5.2-16 5.2.3 Reactor Coolant Pressure Boundary Materials...................................... 5.2-17 5.2.3.1 Material Specification .......................................................... 5.2-17 5.2.3.2 Compatibility with Reactor Coolant ..................................... 5.2-18 5.2.3.3 Fabrication and Processing of Ferritic Materials.................. 5.2-25 i Rev. 2

APR1400 DCD TIER 2 5.2.3.4 Fabrication and Processing of Austenitic Stainless Steel ...................................................................................... 5.2-27 5.2.3.5 Prevention of Primary Water Stress-Corrosion Cracking for Nickel-Base Alloys.......................................... 5.2-32 5.2.3.6 Threaded Fasteners ............................................................... 5.2-32 5.2.4 Inservice Inspection and Testing of the Reactor Coolant Pressure Boundary ............................................................................................... 5.2-33 5.2.4.1 Inservice Inspection and Testing Program............................ 5.2-33 5.2.4.2 Preservice Inspection and Testing Program .......................... 5.2-39 5.2.5 Reactor Coolant Pressure Boundary Leakage Detection....................... 5.2-40 5.2.5.1 Leakage Detection Methods ................................................. 5.2-40 5.2.5.2 Leakage Instrumentation in the Main Control Room ........... 5.2-45 5.2.5.3 Maximum Allowable Total Leakage .................................... 5.2-47 5.2.5.4 Intersystem Leakage ............................................................. 5.2-47 5.2.5.5 Sensitivity and Response Time ............................................. 5.2-49 5.2.5.6 Operability Testing and Calibration ..................................... 5.2-49 5.2.5.7 Limits for Reactor Coolant Leakage Rates within the RCPB .................................................................................... 5.2-49 5.2.6 Combined License Information ............................................................. 5.2-49 5.2.7 References ............................................................................................. 5.2-51 5.3 Reactor Vessel ....................................................................................................... 5.3-1 5.3.1 Reactor Vessel Materials ......................................................................... 5.3-1 5.3.1.1 Material Specifications ........................................................... 5.3-1 5.3.1.2 Special Process Used for Manufacturing and Fabrication .............................................................................. 5.3-2 5.3.1.3 Special Methods for Nondestructive Examinations ............... 5.3-3 5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels....................................................................................... 5.3-5 5.3.1.5 Fracture Toughness ................................................................. 5.3-6 5.3.1.6 Material Surveillance.............................................................. 5.3-7 5.3.1.7 Reactor Vessel Fasteners ...................................................... 5.3-15 5.3.2 Pressure-Temperature Limits, Pressurized Thermal Shock, and Charpy Upper Shelf Energy Data and Analyses .................................... 5.3-16 ii Rev. 2

APR1400 DCD TIER 2 5.3.2.1 Pressure-Temperature Limitation Curves ............................. 5.3-16 5.3.2.2 Operating Procedures ........................................................... 5.3-25 5.3.2.3 Pressurized Thermal Shock .................................................. 5.3-25 5.3.2.4 Upper-Shelf Energy .............................................................. 5.3-26 5.3.3 Reactor Vessel Integrity......................................................................... 5.3-27 5.3.3.1 Design ................................................................................... 5.3-27 5.3.3.2 Materials of Construction ..................................................... 5.3-30 5.3.3.3 Fabrication Methods ............................................................. 5.3-30 5.3.3.4 Inspection Requirements ...................................................... 5.3-31 5.3.3.5 Shipment and Installation ..................................................... 5.3-32 5.3.3.6 Operating Conditions............................................................ 5.3-32 5.3.3.7 Inservice Surveillance .......................................................... 5.3-33 5.3.3.8 Threaded Fasteners ............................................................... 5.3-35 5.3.4 Combined License Information ............................................................. 5.3-35 5.3.5 References ............................................................................................. 5.3-35 5.4 Reactor Coolant System Component and Subsystem Design .......................... 5.4-1 5.4.1 Reactor Coolant Pumps ........................................................................... 5.4-1 5.4.1.1 Pump Flywheel Integrity ........................................................ 5.4-1 5.4.1.2 Description ............................................................................. 5.4-4 5.4.1.3 Evaluation ............................................................................... 5.4-7 5.4.1.4 Tests and Inspections ............................................................ 5.4-10 5.4.2 Steam Generators .................................................................................. 5.4-11 5.4.2.1 Steam Generator Materials ................................................... 5.4-12 5.4.2.2 Steam Generator Program .................................................... 5.4-23 5.4.2.3 Tests and Inspections ............................................................ 5.4-29 5.4.3 Reactor Coolant Piping ......................................................................... 5.4-29 5.4.3.1 Design Basis ......................................................................... 5.4-29 5.4.3.2 Description ........................................................................... 5.4-30 5.4.3.3 Materials ............................................................................... 5.4-30 5.4.3.4 Tests and Inspections ............................................................ 5.4-31 5.4.3.5 Design Features for Minimization of Contamination ........... 5.4-31 5.4.4 [Reserved] ............................................................................................. 5.4-37 iii Rev. 2

APR1400 DCD TIER 2 5.4.5 [Reserved] ............................................................................................. 5.4-37 5.4.6 Reactor Core Isolation Cooling System (Boiling Water Reactors Only) ...................................................................................................... 5.4-37 5.4.7 Shutdown Cooling System .................................................................... 5.4-37 5.4.7.1 Design Bases ........................................................................ 5.4-37 5.4.7.2 System Design ...................................................................... 5.4-42 5.4.7.3 Performance Evaluation ....................................................... 5.4-57 5.4.7.4 Tests and Inspections ............................................................ 5.4-61 5.4.8 Reactor Water Cleanup System (Boiling Water Reactors Only) ........... 5.4-65 5.4.9 [Reserved] ............................................................................................. 5.4-66 5.4.10 Pressurizer ............................................................................................. 5.4-66 5.4.10.1 Design Bases ........................................................................ 5.4-66 5.4.10.2 System Description ............................................................... 5.4-67 5.4.10.3 Design Evaluation ................................................................ 5.4-70 5.4.10.4 Test and Inspection ............................................................... 5.4-71 5.4.11 Pressurizer Relief Tank .......................................................................... 5.4-71 5.4.11.1 Design Bases ........................................................................ 5.4-71 5.4.11.2 System Description ............................................................... 5.4-72 5.4.11.3 Performance Evaluation ....................................................... 5.4-72 5.4.11.4 Instrumentation ..................................................................... 5.4-72 5.4.12 Reactor Coolant System High Point Vents ............................................ 5.4-73 5.4.12.1 Design Bases ........................................................................ 5.4-73 5.4.12.2 System Design ...................................................................... 5.4-74 5.4.12.3 Performance Evaluation ....................................................... 5.4-79 5.4.12.4 Inspection and Testing Requirements ................................... 5.4-80 5.4.12.5 Instrumentation Requirements.............................................. 5.4-80 5.4.13 Main Steamline Flow Restrictor............................................................ 5.4-81 5.4.13.1 Design Basis ......................................................................... 5.4-81 5.4.13.2 Design Description ............................................................... 5.4-81 5.4.13.3 Design Evaluation ................................................................ 5.4-81 5.4.13.4 Tests and Inspections ............................................................ 5.4-81 5.4.14 Safety and Relief Valves ........................................................................ 5.4-81 iv Rev. 2

APR1400 DCD TIER 2 5.4.14.1 Design Basis ......................................................................... 5.4-81 5.4.14.2 Description ........................................................................... 5.4-82 5.4.14.3 Evaluation ............................................................................. 5.4-82 5.4.14.4 Tests and Inspections ............................................................ 5.4-83 5.4.15 Component Supports ............................................................................. 5.4-83 5.4.15.1 Design Basis ......................................................................... 5.4-83 5.4.15.2 Description ........................................................................... 5.4-83 5.4.15.3 Evaluation ............................................................................. 5.4-85 5.4.16 Intersystem Loss of Coolant Accidents ................................................. 5.4-86 5.4.17 Combined License Information ............................................................. 5.4-86 5.4.18 References ............................................................................................. 5.4-87 APPENDIX 5A - EVALUATION OF THE APR1400 DESIGN TO INTERSYSTEM LOCA CHALLENGES ..................................... 5A-1 v Rev. 2

APR1400 DCD TIER 2 LIST OF TABLES NUMBER TITLE PAGE Table 5.1.1-1 Reactor Coolant System Design Parameters ....................................... 5.1-6 Table 5.1.1-2 Process Data Point Tabulation ............................................................. 5.1-7 Table 5.1.1-3 Reactor Coolant System Volumes ....................................................... 5.1-8 Table 5.2-1 Reactor Coolant System Pressure Boundary Code Requirements ..................................................................................... 5.2-55 Table 5.2-2 Reactor Coolant System Materials and Weld Materials .................... 5.2-56 Table 5.2-3 SCS Suction Line Relief Valves (SI-179 and SI-189) Design Parameters .......................................................................................... 5.2-62 Table 5.2-4 ASME Section III Code Cases .......................................................... 5.2-63 Table 5.2-5 Reactor Coolant Preoperation Operating Specifications ................... 5.2-64 Table 5.2-6 Reactor Coolant Plant Shutdown Operating Specifications .............. 5.2-65 Table 5.2-7 Reactor Coolant Detailed Plant Startup Operation Specifications ..................................................................................... 5.2-66 Table 5.2-8 Reactor Coolant Detailed Power Operation Specifications ............... 5.2-67 Table 5.3-1 Total Quantity of Specimens ............................................................. 5.3-39 Table 5.3-2 Type and Quantity of Specimens for Baseline Tests ......................... 5.3-40 Table 5.3-3 Type and Quantity of Specimens for Irradiated Tests ....................... 5.3-41 Table 5.3-4 Type and Quantity of Specimens Contained in Each Irradiation Capsule Assembly............................................................ 5.3-42 Table 5.3-5 Material for Neutron Threshold Detectors......................................... 5.3-43 Table 5.3-6 Composition and Melting Points of Candidate Materials for Temperature Monitors ....................................................................... 5.3-44 Table 5.3-7 Capsule Assembly Removal Schedule .............................................. 5.3-45 Table 5.3-8 Inspection Plan for Reactor Vessel Materials .................................... 5.3-46 Table 5.3-9 Inspection Plan for Reactor Vessel Welds......................................... 5.3-47 Table 5.3-10 RTPTS for the APR1400 Reactor Vessel Materials at EOL (60 Years) ................................................................................................. 5.3-48 Table 5.4.1-1 Reactor Coolant Pump Parameters .................................................... 5.4-90 vi Rev. 2

APR1400 DCD TIER 2 Table 5.4.2-1 Steam Generator Design Parameters ................................................. 5.4-91 Table 5.4.7-1 Shutdown Cooling System Design Parameters ................................. 5.4-93 Table 5.4.7-2 SCS Failure Modes and Effects Analysis .......................................... 5.4-96 Table 5.4.10-1 Pressurizer Design Parameter .......................................................... 5.4-109 Table 5.4.10-2 Pressurizer Tests .............................................................................. 5.4-110 Table 5.4.12-1 Reactor Coolant Gas Vent System - Active Valve List .................. 5.4-111 Table 5.4.14-1 Pilot-Operated Safety Relief Valve Parameters............................... 5.4-112 Table 5.4.14-2 Main Steam Safety Valve Parameters ............................................. 5.4-113 vii Rev. 2

APR1400 DCD TIER 2 LIST OF FIGURES NUMBER TITLE PAGE Figure 5.1.1-1 Reactor Coolant System Schematic Flow Diagram ............................. 5.1-9 Figure 5.1.2-1 Reactor Coolant System Flow Diagram ............................................ 5.1-10 Figure 5.1.2-2 Reactor Coolant Pump Flow Diagram ............................................... 5.1-11 Figure 5.1.2-3 Pressurizer and POSRV Flow Diagram ............................................. 5.1-12 Figure 5.1.3-1 Reactor Coolant System Arrangement Plan ...................................... 5.1-13 Figure 5.1.3-2 Reactor Coolant System Arrangement Elevation .............................. 5.1-14 Figure 5.2.2-1 Optimized Pressurizer POSRV Capacity........................................... 5.2-68 Figure 5.2.2-2 Steam Generator Pressure Normalized to Design Pressure vs.

Time for the Worst-Case Loss-of-Load Event .................................. 5.2-69 Figure 5.2.2-3 Primary Pressure Normalized to Design Pressure vs. Time for the Worst-Case Loss-of-Load Event ................................................. 5.2-70 Figure 5.2.2-4 Reactor Power Normalized to 100 % of Rated Power vs.

Time for the Worst-Case Loss-of-Load Event .................................. 5.2-71 Figure 5.2.3-1 pH Control Program (307.2 ºC) ......................................................... 5.2-72 Figure 5.3-1 Typical Surveillance Capsule Assembly ........................................... 5.3-49 Figure 5.3-2 Upper Compartment Assembly ......................................................... 5.3-50 Figure 5.3-3 Center Compartment Assembly......................................................... 5.3-51 Figure 5.3-4 Lower Compartment Assembly ......................................................... 5.3-52 Figure 5.3-5 Location of Surveillance Capsule Assemblies (Plan View) .............. 5.3-53 Figure 5.3-6 Location of Surveillance Capsule Assemblies (Elevation View) ................................................................................................. 5.3-54 Figure 5.3-7 Pressure-Temperature Limit Curve (60 years) .................................. 5.3-55 Figure 5.3-8 Reactor Vessel Assembly .................................................................. 5.3-56 Figure 5.4.1-1 Reactor Coolant Pump ..................................................................... 5.4-114 Figure 5.4.1-2 Flow Diagram for Reactor Coolant Pump Shaft Seal System ......... 5.4-115 Figure 5.4.2-1 Steam Generator .............................................................................. 5.4-116 Figure 5.4.2-2 Steam Generator Economizer and Lower Tube Bundle Region .............................................................................................. 5.4-117 viii Rev. 2

APR1400 DCD TIER 2 Figure 5.4.2-3 Steam Generator Cold Side Recirculating Fluid Entrance Region .............................................................................................. 5.4-118 Figure 5.4.2-4 Steam Generator Tube Eggcrate Support ........................................ 5.4-119 Figure 5.4.2-5 Steam Generator Tube Vertical Supports ........................................ 5.4-120 Figure 5.4.7-1 Shutdown Cooling System; Two Train Cooldown .......................... 5.4-121 Figure 5.4.7-2 Shutdown Cooling System; One Train Cooldown .......................... 5.4-122 Figure 5.4.7-3 Shutdown Cooling System Flow Diagram; Shutdown Cooling Mode .................................................................................. 5.4-123 Figure 5.4.7-4 Shutdown Cooling Pump Characteristic Curve (Typical) ............... 5.4-125 Figure 5.4.7-5 Shutdown Cooling System Mode Diagram ..................................... 5.4-126 Figure 5.4.7-6 Pressurizer Level vs. Time for NCC Transient ............................... 5.4-128 Figure 5.4.7-7 Steam Generator Pressure vs. Time for NCC Transient .................. 5.4-129 Figure 5.4.7-8 Reactor Coolant Temperatures vs. Time for NCC Transient .......... 5.4-130 Figure 5.4.7-9 Pressurize Pressure vs. Time for NCC Transient ............................ 5.4-131 Figure 5.4.7-10 Hot Leg Subcooling Margin vs. Time for NCC Transient .............. 5.4-132 Figure 5.4.7-11 RVUH Water Volume vs. Time for NCC Transient ....................... 5.4-133 Figure 5.4.7-12 Integrated Auxiliary Feedwater Usage vs. Time for NCC Transient .......................................................................................... 5.4-134 Figure 5.4.10-1 Pressurizer........................................................................................ 5.4-135 Figure 5.4.10-2 Pressurizer Level Setpoint Program ................................................ 5.4-136 Figure 5.4.10-3 Temperature Control Program ......................................................... 5.4-137 Figure 5.4.10-4 Pressurizer Level Error Program ..................................................... 5.4-138 Figure 5.4.10-5 Pressurizer Pressure Control Program ............................................. 5.4-139 Figure 5.4.12-1 Reactor Coolant Gas Vent System Flow Diagram .......................... 5.4-140 Figure 5.4.14-1 Pilot Operated Safety Relief Valve Schematic Diagram ................. 5.4-141 Figure 5.4.15-1 Reactor Coolant System Arrangement and Support Points ............. 5.4-142 Figure 5.4.15-2 Reactor Vessel Support.................................................................... 5.4-143 Figure 5.4.15-3 Steam Generator Supports ............................................................... 5.4-144 Figure 5.4.15-4 Reactor Coolant Pump Supports ...................................................... 5.4-145 ix Rev. 2

APR1400 DCD TIER 2 ACRONYM AND ABBREVIATION LIST ACP auxiliary charging pump ADV atmospheric dump valve ALMS acoustic leak monitoring system ANS American Nuclear Society ANSI American National Standards Institute ART adjusted reference temperature ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials ATM atmosphere BABT boric acid bating tank BAC boric acid corrosion BLPB branch line pipe break BTP Branch Technical Position CCW component cooling water CCWS component cooling water system CEDM control element drive mechanism CFR Code of Federal Regulations CIV containment isolation valve CM condition monitoring CMTR certified material test report COL combined license CSAS containment spray actuation signal CSP containment spray pump CSS containment spray system CVCS chemical and volume control system CVN Charpy V-notch DBE design basis event DCD Design Control Document DO dissolved oxygen x Rev. 2

APR1400 DCD TIER 2 DVI direct vessel injection EDT equipment drain tank EOL end of life EPRI Electric Power Research Institute ERVC external reactor vessel cooling ESF engineered safety feature FCAW flux cored arc welding FEI fluid elastic instability GDC general design criteria (of 10 CFR Part 50, Appendix A)

GL Generic Letter GTAW gas tungsten arc weld GWMS gaseous waste management system HAZ heat-affected zone HJTC heated junction thermocouple HT holdup tank HX heat exchanger ICI in-core instrumentation IEEE Institute of Electrical and Electronics Engineers IHA integrated head assembly IPS information processing system IRWST in-containment refueling water storage tank ISI inservice inspection ISLOCA intersystem loss of coolant accident IST inservice testing ITAAC inspections, tests, analyses, and acceptance criteria IWSS in-containment water storage system LBB leak before break LOCA loss of coolant accident LOCV loss of condenser vacuum LST lowest service temperature xi Rev. 2

APR1400 DCD TIER 2 LTOP low temperature overpressure protection LWMS liquid waste management system MCR main control room MFHX miniflow heat exchanger MOV motor-operated valve MRP material reliability program MSSV main steam safety valve NCC natural circulation cooldown NDE nondestructive examination NEI Nuclear Energy Institute NEMA National Electrical Manufacturers Association NPS nominal pipe size NPSH net positive suction head NRC Nuclear Regulatory Commission OA operational assessment OD outside diameter OM operators module PCPS pool cooling purification system PIV pressure isolation valves POSRV pilot-operated safety relief valve PSA probabilistic safety assessment PSI preservice inspection P-T Limit pressure-temperature limitation PTLR pressure and temperature limits report PTS pressurized thermal shock PVRC Pressure Vessel Research Committee PWR pressurized water reactor PWSCC primary water stress corrosion cracking PZR pressurizer QIAS qualified indication and alarm system xii Rev. 2

APR1400 DCD TIER 2 RCGVS reactor coolant gas vent system RCP reactor coolant pump RCPB reactor coolant pressure boundary RCS reactor coolant system RDT reactor drain tank RG Regulatory Guide RMWT reactor makeup water tank RPS reactor protection system RSR remote shutdown room RTD resistance temperature detector RTE random turbulent excitation RTNDT reference temperature for nil-ductility transition RV reactor vessel RVI reactor vessel internal RVUH reactor vessel upper head SAFDL specified acceptable fuel design limit SAW submerged arc welding SCC stress corrosion cracking SCP shutdown cooling pump SCS shutdown cooling system SDCHX shutdown cooling heat exchanger SFP spent fuel pool SG steam generator SIAS safety injection actuation signal SIP shutdown injection pump SIS safety injection system SIT safety injection tank SMAW shielded metal arc weld SRP Standard Review Plan SS sampling system xiii Rev. 2

APR1400 DCD TIER 2 SSC structure, system, and component SSE safe shutdown earthquake SWMS solid waste management system TEMA tubular exchanger manufacturers association TMI Three Mile Island TNDT nil-ductility transition temperature TT thermally treated USE upper-shelf energy VCT volume control tank WPS welding procedure specification WRC Welding Research Council xiv Rev. 2

APR1400 DCD TIER 2 CHAPTER 5 - REACTOR COOLANT SYSTEM AND CONNECTING SYSTEMS 5.1 Summary Description The reactor is a pressurized water reactor (PWR) with two coolant loops. The reactor coolant system (RCS) circulates water in a closed cycle, removing heat from the reactor core and internals and transferring it to a secondary system. The reactor vessel, steam generators, reactor coolant pumps, pressurizer, and associated piping are the major components of the RCS. Two parallel heat transfer loops, each containing one steam generator and two reactor coolant pumps, are connected to the reactor vessel, and one pressurizer is connected to one of the reactor vessel hot legs. All RCS components are located inside the containment building. Table 5.1.1-1 shows the principal parameters of the RCS. The reactor coolant pressure boundary (RCPB) components are consistent with 10 CFR 50.2 (Reference 1) and 10 CFR 50.55a (Reference 2). Applicable codes and standards of RCS components are listed in Table 3.2-1. The reactor vessel (RV) is equipped with suitable provision for connecting the head vent that meets the requirements of 10 CFR 50.34(f)(2)(vi) (Reference 3) (Three Mile Island [TMI] Action Item II.B.1).

The functions of the RCS are as follows:

a. Energy transfer from the reactor core to the steam generator (SG) where steam is produced for use in the turbine generator

b. Secondary barrier to the release of fission products from the reactor core to the environment

c. Sufficient cooling during all normal plant operations and expected transients to preclude significant fuel damage

d. Reactor coolant circulation with the required chemistry and boron concentration

e. System pressure control to a moderate extent through sprays

f. Rapid depressurization of the RCS by manual operation of the pressurizer pilot operated safety relief valves (POSRVs)

g. Venting of steam and noncondensable gases from RV closure head and pressurizer steam space 5.1-1 Rev. 2

APR1400 DCD TIER 2 The major components of the RCS are as follows:

a. Reactor vessel: The reactor vessel contains fuel bundles, control rods, and other internals necessary for core support and flow direction. The six reactor coolant nozzles, two outlet and four inlet, are located with their centerlines on a common horizontal plane. The reactor vessel is a vertical right cylinder with two hemispherical heads. The lower head is welded to the reactor vessel shell and contains 61 in-core instrumentation penetrations. The upper closure head can be removed to provide access to the reactor vessel internals. The head is penetrated by 103 control element drive mechanism (CEDM) nozzles: eight of the nozzles are capped-off CEDM spares, and two are used for heated junction thermocouples (HJTCs). The reactor vessel is described in Section 5.3.

b. Steam generators: The steam generators provide the interface between the RCS and the main steam system. The steam generators are vertical U-tube heat exchangers with an integral economizer in which heat is transferred from the reactor coolant to the main steam system. Reactor coolant is prevented from mixing with the secondary steam by the steam generator tubes and the steam generator tube sheet, making the RCS a closed system that serves as a barrier to the release of radioactive materials from the core of the reactor to the secondary system and the containment building. The steam generators are described in Subsection 5.4.2.

c. Reactor coolant pumps: The four identical reactor coolant pumps (RCPs) are vertical single-stage, bottom suction, horizontal discharge, motor-driven centrifugal pumps designed to overcome the system flow resistances and circulate the reactor coolant at the flow rate required for design power operation. A flywheel on the shaft above the motor provides rotating inertia to increase the RCP coastdown time and reduce the rate of decay of reactor coolant flow if electrical power to the RCP motors is lost. The RCPs are described in Subsection 5.4.1.

d. Reactor coolant piping: Each of the heat transfer loops contains five pipe assemblies: one 106.7 cm (42 in) internal diameter pipe assembly between the reactor vessel outlet nozzle and SG inlet nozzle, two 76.2 cm (30 in) internal diameter pipe assemblies from the SGs two outlet nozzles to the RCP suction nozzles, and two 76.2 cm (30 in) internal diameter pipe assemblies from the RCP discharge nozzles to the reactor vessel inlet nozzles. The pipe assemblies are 5.1-2 Rev. 2

APR1400 DCD TIER 2 referred to as the hot leg, suction legs, and pump discharge legs. The pressurizer surge line is a 30 cm (12 in) schedule 160 pipe assembly located between the pressurizer and the hot leg in Loop 2. The reactor coolant piping is described in Subsection 5.4.3, and a typical arrangement of the piping is shown in Figures 5.1.3-1 and 5.1.3-2.

e. Pressurizer: The pressurizer is a vertical cylindrical vessel with a hemispherical top and bottom head. Electric heaters are installed vertically through the bottom head, and the spray nozzle and POSRV nozzles are mounted on the top head.

The pressurizer is connected to the hot leg in RCS Loop 2 by the surge line. RCS pressure is controlled by the pressurizer where steam and water are maintained in thermal equilibrium. Steam is formed by energizing immersion heaters in the pressurizer or is condensed by the pressurizer spray to limit pressure variations caused by the contraction or expansion of the reactor coolant. The average temperature of the reactor coolant varies with power level changing the pressurizer water level as the fluid expands or contracts. The charging control valves and letdown orifice isolation valves in the chemical and volume control system (CVCS) are used to maintain a programmed pressurizer water level. The pressurizer is described in Subsection 5.4.10.

f. Pressurizer POSRVs: Overpressure protection for the reactor coolant pressure boundary is provided by four POSRVs connected to the top of the pressurizer.

These valves discharge to the in-containment refueling water storage tank where the steam is released under water to be condensed and cooled. Pressurizer POSRVs are described in Subsection 5.4.14.

5.1.1 Schematic Flow Diagram The schematic flow diagram of the RCS is shown in Figure 5.1.1-1. The principal pressures, temperatures, and design minimum flow rates of the RCS under normal steady-state, full-power operating conditions are provided in Table 5.1.1-2. The RCS volumes at cold conditions are shown in Table 5.1.1-3.

5.1.2 Flow Diagram The flow diagram of the RCS is shown in Figure 5.1.2-1. The entire RCS is located within the containment. Fluid systems that are connected to the RCS and within the limits of the reactor coolant pressure boundary, as defined in ANSI/ANS 51.1 (Reference 4), are 5.1-3 Rev. 2

APR1400 DCD TIER 2 identified and the relevant piping and instrument diagrams are referenced in other sections.

The flow diagrams for the reactor coolant pumps and the pressurizer are provided in Figures 5.1.2-2 and 5.1.2-3, respectively.

The major components of the system are an RV, two parallel heat transfer loops, each containing one SG and two RCPs, and a pressurizer connected to the hot leg in RCS Loop 2.

All of these major system components are located inside the containment building.

During normal operation, the reactor coolant is circulated through the RV and SGs by the RCPs. The reactor coolant is heated by fission energy produced in the core as it passes through the RV and is cooled in the SGs as it gives up heat to the secondary system.

The reactor coolant also serves as a neutron absorber (boron) for reactivity control.

Except for some local boiling in the hottest channels in the core, the reactor coolant remains in a subcooled condition by maintaining a high system pressure. The RCS provides a barrier against the uncontrolled release of reactor coolant and radioactive materials to the containment.

RCS pressure is controlled by the pressurizer, where steam and water are maintained in thermal equilibrium. Steam is formed by energizing immersion heaters in the pressurizer, or is condensed by the pressurizer spray to limit pressure variations caused by contraction or expansion of the reactor coolant.

Overpressure protection for the RCS is provided by four POSRVs connected to the top of the pressurizer. These valves discharge to the in-containment refueling water storage tank, where the steam is released under water to be condensed and cooled. If the steam discharge exceeds the capacity of the in-containment refueling water storage tank, it is vented to the containment atmosphere.

The RCS is interfaced with a number of auxiliary systems, including the main steam supply system, CVCS, SCS, SIS, CCWS, and sampling system.

The isolation valves are connected in series to the RCS and are a part of the RCPB. The isolation valves are designed to meet the exclusion requirements of 10 CFR 50.55a(c).

5.1-4 Rev. 2

APR1400 DCD TIER 2 5.1.3 Elevation Drawings The RCS arrangement plan and elevation drawings are provided as Figures 5.1.3-1 and 5.1.3-2, respectively.

Major components of the RCS are surrounded by concrete structures that provide support plus shielding and missile protection as needed. General arrangement drawings illustrating principal dimensions of the RCS in relationship to the surrounding building structures are presented in Figures 1.2-2 through 1.2-8 in Section 1.2.

5.1.4 Combined License Information No COL information is required with regard to Section 5.1.

5.1.5 References

1. 10 CFR 50.2, Definitions, U.S. Nuclear Regulatory Commission.

2. 10 CFR 50.55a, Codes and Standards, U.S. Nuclear Regulatory Commission.

3. 10 CFR 50.34, Contents of Applications; Technical Information, U.S. Nuclear Regulatory Commission.

4. ANSI/ANS 51.1-1983, American National Standard Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plant, American Nuclear Society, 1983.

5.1-5 Rev. 2

APR1400 DCD TIER 2 Table 5.1.1-1 Reactor Coolant System Design Parameters Parameter Value Design thermal power, MWt 4,000 (including net heat addition from pumps)

Design pressure, kg/cm2A (psia) 175.8 (2,500)

Design temperature (except pressurizer), °C (°F) 343.3 (650)

Pressurizer design temperature, °C (°F) 371.1 (700)

Coolant flow rate, kg/hr (lbm/hr) 75.6 x 106 (166.6 x 106)

Cold leg temperature, operating, °C (°F) 290.6 (555)

Average temperature, operating, °C (°F) 307.2 (585)

Hot leg temperature, operating, °C (°F) 323.9 (615)

Normal operating pressure, kg/cm2A (psia) 158.2 (2,250)

System water volume, m3 (ft3) (with pressurizer) 453.4 (16,011) 3 3 Pressurizer water volume, m (ft ) (full power) 33.2 (1,171) 3 3 Pressurizer steam volume, m (ft ) (full power) 35.7 (1,260) 5.1-6 Rev. 2

APR1400 DCD TIER 2 Table 5.1.1-2 Process Data Point Tabulation (1)

Steam Reactor Steam Generator 1 Vessel Generator 2 Pressurizer Midpoint Pump Suction Pump Outlet Midpoint Hot Leg Midpoint Parameter (2) (2) (2) (2) (2) (2) (2)

Pressure, 158.2 157.5 156.1 163.8 161.7 158.9 157.5 kg/cm2A (psia) (2,250) (2,240) (2,220) (2,330) (2,300) (2,260) (2,240)

Temperature, °C (°F) 344.8 307.2 290.6 290.6 308.8 323.9 307.2 (652.7) (585.0) (555.0) (555.0) (587.8) (615.0) (585.0)

Mass flow rate, N/A 37.8 x 106 18.9 x 106 18.9 x 106 75.6 x 106 37.8 x 106 37.8 x 106 kg/hr (lbm/hr) (83.3 x 106) (41.65 x 106) (41.65 x 106) (166.6 x 106) (83.3 x 106) (83.3 x 106)

Volumetric flow rate, N/A 885,707 421,854 421,854 1,778,538 940,076 885,707 L/min (gpm) (233,979) (111,442) (111,442) (469,840) (284,342) (233,979)

(1) For steady state, 100 % power conditions (2) See Figure 5.1.1-1 for data points 5.1-7 Rev. 2

APR1400 DCD TIER 2 Table 5.1.1-3 Reactor Coolant System Volumes Component Volume (1)

RV, m3 (ft3) 164.48 (5,808.7)

Steam generators, m3 (ft3) 86.81 (3,065.7) (each),

without tube plugging RCPs, m3 (ft3) 3.26 (115) (each) 3 3 Pressurizer, m (ft ) 67.96 (2,400)

Piping:

Hot leg, m3 (ft3) 3.84 (135.6) (each)

Cold leg, m3 (ft3) 6.23 (219.9) (each)

Surge line, m3 (ft3) (nominal) 1.17 (41.2) 3 3 Spray line, m (ft ) 0.45 (15.8)

(1) Volumes determined at cold 21 °C (70 °F) conditions 5.1-8 Rev. 2

APR1400 DCD TIER 2 RDT Pressurizer PZR Spray IRWST POSRVs Control Valves Reactor Coolant Gas Vent Subsystem (RCGVS) Auxiliary Spray PRESSURIZER RCP 1B RCP 2A Main LOOP 1B Main LOOP 2A Steam Steam Steam Letdown Steam Generator Generator (CVCS) No. 1 Surge Line No. 2 RCGVS RDT LOOP 1 Reactor LOOP 2 RDT Vessel Shutdown Shutdown RDT Cooling Cooling RDT LOOP 1A Safety Injection &

LOOP 2B Safety Injection Shutdown Cooling Safety Injection RCP 1A RCP 2B Charging Line (CVCS)

Figure 5.1.1-1 Reactor Coolant System Schematic Flow Diagram (NRC DC)

Figure 5.1.1-1 Reactor Coolant System Schematic Flow Diagram 5.1-9 Rev. 2

APR1400 DCD TIER 2 CV:RDT CV:RDT SHEET 5 SHEET 5 PDT PDT 1C 1E I I PDT PDT 1D 1F I I TEW SPRAY LINE TEW TEW 4 6 8

IT TEW I RAL IR IT 25 8 26 I RAL I

RG:REACTOR COOLANT SHEET 1 XE XE GAS VENT SYSTEM REACTOR REACTOR 9I 9J COOLANT PUMP 1B COOLANT PUMP 2A AH XE XE AH CV:LETDOWN LINE ALM 9A 9D ALM SHEET 1 XE AH AH XE 10D ALM 10D ALM LPM AH AH LPM REACTOR COOLANT REACTOR COOLANT SI:SAFETY SI:SAFETY LOOP 2A LOOP 1B XE INJECTION LINE 4 INJECTION LINE 3 XE STEAM 10B SHEET 3 SHEET 4 10C STEAM GENERATOR 1 AH LPM LPM AH GENERATOR 2 PDT PDT 3 PX LO V212 3 I SHEET 1 I XE XE SURGE LINE 9L 9M CV:RDT CV:RDT AH ALM AH SHEET 5 SHEET 5 ALM TEW XE TEW TEW TEW XE 5 9B 4 XE 6 5 9E 9G ALM IRAH AH IR IR IRAH AH ALM AH REACTOR ALM VESSEL RV01 XE LET LET 10A 41 41 AH IRAHL IRAHL LPM LT 40 IAHL PDT PDT 2 2 LT I PT 40 I 11 IAHL IAH PDT PDT 2 2 I I SI:SAFETY INJECTION LINE 2 PDT 403 PDT 2 2 SI:SAFETY INJECTION LINE 1 FC S I I PDT

& SHUTDOWN COOLING SHEET 3 PDT 3 3

PDT I PDT 2 I 2

& SHUTDOWN COOLING SHEET 4 I I SHEET 5 CV:RDT REFULING WATER IT REFULING WATER LEVEL IT REACTOR REACTOR 24 LEVEL 27 COOLANT PUMP 1A COOLANT PUMP 2B I I TEW XE TEW XE TEW TEW 7 9C 4 9F 7 6 IAHL AH IR AH IAHL I XE ALM XE 9H ALM 9K ALM AH AH ALM REACTOR COOLANT XE XE REACTOR COOLANT LOOP 1A 10D 10D LOOP 2B LPM AH CV:RDT AH LPM SI:SHUTDOWN COOLING LINE 1 SHEET 5 CV:CHARGING LINE SI:HOT LEG INJECTION SI:HOT LEG INJECTION SI:SHUTDOWN SPRAY LINE SHEET 3 PDT PDT SHEET 1 SHEET 4 SHEET 4 SHEET 3 1A 1G COOLING LINE 2 I I PDT PDT 1B 1H I I SHEET 5 SHEET 5 CV:RDT PT PT CV:RDT 42A 42B IR I Figure 5.1.2-1 Reactor Coolant System Flow Diagram 5.1-10 Rev. 2

APR1400 DCD TIER 2 VET 26 FT UU 35A IRAHL RC PUMPS CONTROLLED 430 MOTOR OIL COOLER M BLEEDOFF PT FE 36A 156 IRAHL LET 26 IAHL LET 24A UPPER TEW LIS OIL 34A SS RESERVOIR IRAH 26 TE 26 OIL COMPONENT COOLING RAH RESERVOIR 1A WATER RETURN LG MOTOR STATOR TEMP 007 AIR COOLER LET 26 PT STRAINER IAHL 25A COMPONENT COOLING IRAHL WATER SUPPLY VET 26 UU LUBE OIL COOLER MOTOR LOWER JOURNAL BEARING TE SET SET 26 30A IRAH 31A FS FLEXIBLE 159 COUPLING ACCUMULATOR LET 26 IAL UPPER JOURNAL PT BEARING 33A IRAHL UPPER THRUST PS PDS BERING 157 LUBE OIL 158 COOLER TE LOWER JOURNAL 26 BEARING OIL LIFT RAH VET OIL LIFT PUMP PUMP FILTER 26 UU VET 26 UU RDT RIGID COUPLING 3 TE PUMP 37A SEALS 2 IRAH 1

MOTOR STAND DRAIN PUMP CASING VENT LEAKAGE SEAL SPIRAL HOUSING GASKET DRAIN TE 32A IRAH RDT CYCLONE FILTER HP COOLER RC PUMP SEAL 446 450 M M REACTOR INJECTION PUMP DISCHARGE COOLANT PUMP 1A JET PUMP LO LO DISCHARGE NOZZLE PRESSURE TAP SUCTION NOZZLE PRESSURE TAP COMPONENT COOLING COMPONENT COOLING WATER SUPPLY WATER RETURN PUMP SUCTION Figure 5.1.2-2 Reactor Coolant Pump Flow Diagram 5.1-11 Rev. 2

APR1400 DCD TIER 2 RG SYSTEM TEW TEW TEW TEW TEW TEW ZL ZL ZL 38A 38B 38C ZL 38D TEW TEW 38G TEW TEW 38J TEW TEW 38E 38F 201B 38H 38I 202C 38L 203D 200A IAH 38K IAH IAH IAH IAH IAH IAH IAH IAH IAH IAH IAH PRIMARY SAMPLING SYSTEM P P P P 200 201 202 203 AI BI ZL ZL ZL ZL ZL ZL ZL ZL 310A 311C 312B 313D 314A 315C 316B 317D V310 V311 TEW V312 TEW V314 V315 TEW V316 V317 TEW V2300 LO LO LO LO LO 39A LO 39B LO 39C LO 39D LO ZL ZL IAH ZL ZL IAH ZL ZL IAH ZL ZL IAH 131 133 135 300A 300 301C 301 302B 302 303D 303 304A 304 305C 305 306B 306 307D 307 137 M

LC,FL M LC,FL M LC,FL M LC,FL AI DII AI DII AI DII AI DII 120 121 130 122 132 125 134 126 127 136 LC,FL LC,FL LC,FL LC,FL LO,FL LO,FL LO,FL LO,FL LO,FL LO,FL LO,FL M M M M M M M M M M LO,FL M M 123 124 CI DII M TO S/G COMPARTMENT CI DII 385 CI DII V237 TO S/G CV:AUXILIARY M COMPARTMENT SPRAY LINE TEW 386 SHEET 1 36A 442 100F IAL CI DII M

RC:COLD LEG LOOP 2A SHEET 1 V244 LO FC V241 TEW 36B 443 100E IAL M

RC:COLD LEG LOOP 2B SHEET 1 LO FC V240 1401 PT PT PT PT PT PT 13 12 16 16 12 13 V236 I I IS IS I I 1403 PRESSURIZER PT PTR PT 12 13 15 PT PTR PT 1402 1404 15 13 12 I IR IAH IAH IR I LT LT 40A 40A LGS LGS I I 40B 40B TEW AHL AHL 19C I

PT 17 SHEET 1 SHEET 1 RAHL TEW SHEET 1 SHEET 1 PT TEW 20 19A PT TEW PT 21B RC RC I 20 19B 17 I I TEW IL I RAHL RC RC 21A LT LTI 18 REFULING WATER 14 I LEVEL I

REFULING WATER IRAHL (NOTE 23)

LEVEL LTI 14 BACK-UP PROPORTIONAL HEATERS HEATERS IRAHL SPARGER SPARGER SPARGER SPARGER XE 9N AH ALM SPARGER SPARGER SPARGER SPARGER SPARGER SPARGER SPARGER SPARGER PX SHEET 1 IRWST TEW 21C I

RC:RC LOOP 2 SHEET 1 Figure 5.1.2-3 Pressurizer and POSRV Flow Diagram 5.1-12 Rev. 2

APR1400 DCD TIER 2 Security-Related Information - Withhold Under 10 CFR 2.390 Figure 5.1.3-1 Reactor Coolant System Arrangement Plan 5.1-13 Rev. 2

APR1400 DCD TIER 2 Security-Related Information - Withhold Under 10 CFR 2.390 Figure 5.1.3-2 Reactor Coolant System Arrangement Elevation 5.1-14 Rev. 2

APR1400 DCD TIER 2 5.2 Integrity of the Reactor Coolant Pressure Boundary This section describes the measures that provide and maintain the integrity of the reactor coolant pressure boundary (RCPB) throughout the facilitys design life. The RCPB is defined in accordance with 10 CFR 50.2 (Reference 1). The RCPB includes all pressure-containing components such as pressure vessels, piping, pumps, and valves that are:

a. Part of the reactor coolant system (RCS)

b. Connected to the RCS, up to and including the following:

1) The outermost containment isolation valve in piping that penetrates the containment

2) The second of two valves normally closed during reactor operation in piping that does not penetrate the containment

3) The reactor coolant system safety and relief valves.

5.2.1 Conformance with Codes and Code Cases 5.2.1.1 Conformance with 10 CFR 50.55a RCPB components are designed and fabricated as Class 1 components in accordance with ASME Section III (Reference 2), except for the components that meet the exclusion requirements of 10 CFR 50.55a(c) (Reference 3). RCPB components that meet the exclusion requirements are classified as Quality Group B in accordance with U.S.

Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.26 (Reference 4) and are fabricated as Class 2 components in accordance with ASME Section III. The classification of RCPB components conforms with the requirements of 10 CFR Part 50, Appendix A, General Design Criteria (GDC) 1 (Reference 5). The remaining safety-related components are classified as Quality Group C in accordance with NRC RG 1.26 and are fabricated as Class 3 components in accordance with ASME Section III.

Subsection 5.2.4 and Section 6.6 provide a description of the application of ASME Section XI (Reference 6) to the RCPB. Subsection 3.9.6 provides a description of the application of the ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code) (Reference 7) to the RCPB.

5.2-1 Rev. 2

APR1400 DCD TIER 2 The components and code classes that are listed in Table 5.2-1 are in accordance with the provisions of 10 CFR 50.55a. Subsection 3.12.2.1 provides a description of the application of ASME Section III for safety-related piping system in accordance with 10 CFR 50.55a. Table 3.2-1 provides the component classifications of pressure vessels, piping, pumps, valves, and storage tanks, along with the applicable component codes. The proposed inspections, tests, analyses, and acceptance criteria (ITAAC), as required by 10 CFR 52.47(b)(1) (Reference 8), are addressed in Tier 1 of the APR1400 DCD based on the selection criteria in Section 14.3.

5.2.1.2 Compliance with Applicable Code Cases RCPB components are designed and fabricated in accordance with ASME Section III.

The applicable ASME Section III Code Cases that are in conformance with the requirements of GDC 1 and 10 CFR 50.55a and that are used in the plant design and manufacturing are listed in Table 5.2-4. Subsection 3.12.2.2 and Section 6.0 provide descriptions of the application of ASME Section III Code Cases for safety-related piping systems and ESF components, respectively. Subsection 5.2.4 and Section 6.6 provide descriptions of the application of ASME Section XI Code Cases that are in conformance with the requirements of 10 CFR 50.55a and that are invoked for the ISI program.

Subsection 3.9.6 provides descriptions of the application of the ASME OM Code Cases that are in conformance with the requirements of 10 CFR 50.55a and that are invoked for operation and maintenance activities. NRC RGs 1.84 (Reference 9), 1.147 (Reference 10),

and 1.192 (Reference 11) are used in determining the applicable ASME Code Cases. The COL applicant is to address the addition of ASME Code Cases that are approved in NRC RG 1.84 at the time of the application (COL 5.2(1)). The COL applicant is to address the ASME Code Cases approved in NRC RG 1.147 at the time of the application and invoked for the ISI program of a specific plant (COL 5.2(2)). The COL applicant is to address the ASME Code Cases approved in NRC RG 1.192 at the time of the application and invoked for operation and maintenance activities of a specific plant (COL 5.2(3)).

5.2.2 Overpressure Protection Overpressure protection systems include all pressure-relieving devices for the following systems:

a. Reactor coolant system (RCS) 5.2-2 Rev. 2

APR1400 DCD TIER 2

b. Primary side of auxiliary or emergency systems connected to the RCS

c. Secondary side of steam generators (SGs) 5.2.2.1 Design Bases 5.2.2.1.1 Design Bases for Overpressure Protection of the Reactor Coolant System The functional design of the overpressure protection is in conformance with the requirements of GDC 15 and GDC 31.

Overpressurization of the RCS and steam generators is precluded by operation of the pressurizer POSRVs and main steam safety valves (MSSVs) and by the reactor protection system (RPS). Pressure relief capacity for the RCS and steam generators is conservatively sized to satisfy the overpressure requirements of ASME Section III, Division 1, NB 7000.

The pressurizer POSRVs, MSSVs, and RPS are designed to maintain the RCS pressure below 110 percent of design pressure during the worst-case loss-of-load event with a delayed reactor trip. The MSSVs are sized conservatively to release steam flow equal to the full power level. Steam generator pressure is limited to less than 110 percent of steam generator design pressure during the worst-case transient (Reference 38).

In order to determine the appropriate pressurizer POSRV capacity, a sensitivity study was performed with the worst-case initial condition and nuclear parameters to conservatively evaluate the effect of valve capacity on the maximum RCS pressure during the design basis event. As shown in Figure 5.2.2-1, the design POSRV capacity is determined at the point where an additional increase in the capacity has a negligible effect on reducing the maximum RCS pressure during the loss-of-load transient.

At the onset of a loss-of-load transient, the reactor coolant and main steam systems are at maximum rated output plus a 2 percent uncertainty margin. No credit is taken for plant control systems such as letdown, charging, pressurizer spray, turbine bypass, reactor power cutback, and feedwater addition (main and auxiliary) after turbine trip in the loss-of-load analysis. A reactor scram is assumed to be initiated by the second safety grade signal from the RPS.

Peak reactor coolant and steam generator pressures are limited to less than 110 percent of design pressures during the worst-case transient (Figures 5.2.2-2, 5.2.2-3, and 5.2.2-4).

5.2-3 Rev. 2

APR1400 DCD TIER 2 Reasonable assurance of reliable overpressure protection is provided by the pressurizer POSRVs, the MSSVs, and the RPS.

Pressurizer sizing is described in Subsection 5.4.10.

5.2.2.1.2 Design Bases for Low Temperature Overpressure Protection Each shutdown cooling system (SCS) suction line relief valve (SI-179 or SI-189) is designed to protect the RCS in a failure that initiates a pressure transient. The use of either SCS suction line relief valve provides sufficient pressure relief capacity to mitigate the most limiting low temperature overpressure protection (LTOP) events during low-temperature conditions.

The maximum pressure for low temperature overpressure protection is limited to 43.9 kg/cm2A (625 psia), 20 percent of RCS hydraulic test pressure (219.7 kg/cm2A

[3,125 psia]), which is the maximum RCS pressure allowed under the minimum operating temperature required in Appendix G of ASME Section III. The SCS suction line relief valves are designed in accordance with LTOP requirements.

The LTOP is designed in accordance with Branch Technical Position (BTP) 5-2 (Reference 12). Overpressure protection of the RCS during low-temperature conditions is provided by the relief valves, SI-179 and SI-189, located in the SCS suction lines.

Subsection 5.4.7 provides a description of the SCS. The SCS is schematically shown on the SCS flow diagram (Figure 5.4.7-3), RCS flow diagram (Figure 5.1.2-1) and safety injection system (SIS) flow diagram (Figure 6.3.2-1). The SCS suction line relief valves are shown in Figure 6.3.2-1 and described in Subsection 5.4.7.2.2.

Alignment of the SCS suction line relief valve to the RCS is specified by plant procedures to provide reasonable assurance of RCS overpressure protection for all temperatures below the temperature for which LTOP is required, called the LTOP temperature and designated as TLTOP. Pressure-temperature (P-T) Limit curves are provided in the Pressure and Temperature Limits Report (PTLR) (Reference 13). For temperatures above the LTOP temperature, overpressure protection is provided by the pressurizer POSRVs, which is described in Subsection 5.2.2.4.1.

5.2-4 Rev. 2

APR1400 DCD TIER 2 5.2.2.1.2.1 Design Criteria The criteria considered in the design of the overpressure mitigating system to provide LTOP for the RCS are provided in Subsections 5.2.2.1.2.2 through 5.2.2.1.2.5.

5.2.2.1.2.2 Credit for Operator Action No credit is taken for operator action in the limiting transient analyses described in Subsection 5.2.2.2.2.1. In the analysis, overpressure protection is provided by the SCS suction line relief valves.

5.2.2.1.2.3 Single Failure In the LTOP mode, each SCS suction line relief valve is designed to protect the reactor vessel given a single failure in addition to the event that initiates the pressure transient.

The event initiating the pressure transient is considered to result from either an operator error or equipment malfunction. The SCS suction line relief valve is independent of a loss of offsite power. Each SCS suction line relief valve is a self-actuating, spring-loaded liquid relief valve, which does not require control circuitry. The relief valve opens when the RCS pressure exceeds its setpoint.

The redundant SCS suction lines between the RCS and the SCS suction line relief valves meet the single failure criteria as described in Table 5.4.7-2. No single failure of an isolation valve or its associated interlock will prevent one relief valve from performing its intended function.

5.2.2.1.2.4 Testability Periodic testing of the SCS LTOP relief valves and suction line isolation valves is defined in Subsections 3.4.11 and 3.4.13 in Technical Specifications (Chapter 16).

5.2.2.1.2.5 Seismic Design and IEEE Standards 308 and 603 Criteria The SCS suction line relief valves, isolation valves, associated interlocks, and instrumentation are designed to seismic Category I requirements and are addressed in Subsections 3.2.1 and 5.4.7.2.4 and Table 3.2-1. The interlocks and instrumentation associated with the SCS suction line isolation valves are described in Subsections 5.4.7, 7.6.1, and 7.6.1.1 and Table 7.6-1. The interlocks satisfy the applicable portions of IEEE Standards 279, 308, and 603 criteria.

5.2-5 Rev. 2

APR1400 DCD TIER 2 5.2.2.2 Design Evaluation 5.2.2.2.1 Design Evaluation for Overpressure Protection of the Reactor Coolant System Section 15.2 provides the functional design evaluation of the overpressurization protection system. The analysis demonstrates the adequacy of the overpressure protection system to maintain secondary and primary operating pressures within their respective pressure limits.

The analytical model used in the analysis is addressed in Chapter 15.

The assumptions that are used in the analysis are provided in Chapter 15. The assumptions were chosen to maximize the required pressure-relieving capacity of the primary and secondary sides. The analysis for the most severe anticipated transient demonstrates that sufficient relieving capacity is provided to prevent the pressure from exceeding 110 percent of the design pressure when acting in conjunction with the reactor protective system.

5.2.2.2.2 Design Evaluation for Low Temperature Overpressure Protection The information in the following subsections is provided to demonstrate that the SCS suction line relief valves meet the criteria provided in Subsection 5.2.2.1.2.

5.2.2.2.2.1 Limiting Transients Transients during the low-temperature operating mode are more severe when the RCS is operated in the water-solid condition. Addition of mass or energy to an isolated water-solid system produces increased system pressure. The severity of the pressure transients depends upon the rate and total quantity of mass or energy addition. The choice of the limiting LTOP transients is based on evaluations of the potential transients. The most limiting transients initiated by a single operator error or equipment failure are:

a. An inadvertent safety injection actuation and one charging pump operation (mass addition)

b. A start of one reactor coolant pump (RCP) when a positive temperature difference (T) between the steam generator secondary-side water and the reactor coolant exists (energy addition) 5.2-6 Rev. 2

APR1400 DCD TIER 2 The most limiting transients are determined by the conservative analyses, which maximize mass and energy additions to the RCS. In addition, the RCS is assumed to be in a water-solid condition at the time of the transient; such a condition has been noticed to exist infrequently during plant operation because the operator is instructed to avoid water-solid conditions whenever possible.

The maximum T for energy addition transient is assumed to be 139 °C (250 °F), which is greater than the value allowed by Subsections 3.4.6 and 3.4.7 in Technical Specifications (Chapter 16) during the LTOP mode. However, the operational procedures direct the operator to maintain the T below approximately 11.1 °C (20 °F).

The analyses demonstrate that the SCS suction line relief valve (SI-179 or SI-189) provides sufficient pressure relief capacity to mitigate the most limiting LTOP events identified above.

5.2.2.2.2.2 Provision for Overpressure Protection The LTOP pressure is defined to be the SCS suction line relief valve setpoint pressure adjusted to provide a margin to avoid lifting and to compensate for pressure measuring inaccuracies during plant normal operation. During heatup, the RCS pressure is maintained below the LTOP pressure until the RCS cold leg temperature exceeds the LTOP disable temperature. During cooldown, the RCS pressure is maintained below the LTOP pressure once the RCS cold leg temperature reaches the LTOP enable temperature.

An LTOP enable temperature is defined in BTP 5-2, Overpressurization Protection of Pressurized Water Reactors While Operating at Low Temperatures. The definition is based on measuring the degree of protection provided by the LTOP system against violations of the pressure-temperature limitations (P-T Limits) in terms of the RTNDT of the reactor vessel beltline material at either the 1/4t or 3/4t location, depending upon which P-T Limit curve is most limiting.

Given the implicit assumptions in the P-T Limit analysis described in Subsection 5.3.2.1.2, the 3/4t location is the controlling beltline P-T Limit for heatup, and the 1/4t location is controlling for cooldown. LTOP disable temperature for heatup and LTOP enable temperature for the controlling cooldown (isothermal) is specified in the PTLR.

The RCS is protected at elevated temperatures by the pressurizer POSRVs, which have a set pressure of 173.7 kg/cm2A (2,470 psia) as indicated in Table 5.4.14-1.

5.2-7 Rev. 2

APR1400 DCD TIER 2 Whenever the SCS suction line relief valves are aligned to the RCS to provide LTOP, an increase in RCS pressure above the maximum SCS alignment pressure of 31.6 kg/cm2A (450 psia) will cause an LTOP transient alarm in the main control room to alert the operator that a pressure transient is occurring. Operator actions taken in response to an LTOP transient alarm are described in Subsection 5.4.7.2.6. Either SCS suction line relief valve will terminate inadvertent pressure transients occurring while RCS temperature is below the LTOP disable temperature. For temperatures above the LTOP disable temperature specified in the PTLR for heatup, overpressure protection is provided by the pressurizer POSRVs.

During cooldown, whenever the RCS cold leg temperature is below the LTOP enable temperature specified in the PTLR, the SCS suction line relief valves provide the necessary overpressure protection. If the SCS is not aligned to the RCS before the cold leg temperature is decreased below the LTOP enable temperature, an alarm will notify the operator to open the SCS suction line isolation valves. However, the SCS cannot be aligned to the RCS until the RCS pressure is below the SCS entry pressure.

The LTOP conditions described above are within the SCS operating range. Subsection 3.4.11 in Technical Specifications (Chapter 16) requires the SCS suction line isolation valves to be open when operating in the LTOP mode. This Technical Specification also provides reasonable assurance that appropriate action is taken if one or more SCS suction line relief valves are out of service during the LTOP mode of operation.

Either SCS suction line relief valve provides sufficient relief capacity to prevent any pressure transient from exceeding the controlling P-T Limit.

5.2.2.2.2.3 Administrative Controls Administrative controls necessary to implement the LTOP provisions are limited to controls that are necessary to open the SCS suction line isolation valves.

During cooldown, when the temperature of the RCS is above that corresponding to the intersection of the controlling P-T Limit and the pressurizer POSRV setpoint, overpressure protection is provided by the pressurizer POSRVs, and no administrative procedural controls are necessary. RCS pressure is decreased to below the LTOP pressure before entering the low temperature region for which LTOP is necessary. The LTOP pressure is equal to the maximum allowable pressure for SCS operation. Once the SCS is aligned, no further specific administrative procedural controls are needed to provide reasonable 5.2-8 Rev. 2

APR1400 DCD TIER 2 assurance of proper overpressure protection. The SCS remains aligned whenever the RCS is at low temperatures and the reactor vessel head is secured or until an adequate vent has been established. The SCS suction line isolation valve position is indicated.

During heatup, the SCS suction line isolation valves remain open at least until the LTOP disable temperature is reached. Once the RCS temperature reaches the temperature corresponding to the intersection of the controlling P-T Limit and the pressurizer POSRV setpoint, overpressure protection is provided by the pressurizer POSRVs. The SCS can be isolated, and no further actions are necessary.

5.2.2.3 Flow Diagrams The flow diagram, showing the pressurizer POSRVs and their discharge lines, is given in Figure 5.1.2-3. The flow diagram showing the in-containment refueling water storage tank (IRWST) is given in Figure 6.8-3. The main steam safety valves are discussed in Section 10.3.

The SCS suction line relief valves (SI-179 and SI-189), used to provide LTOP are addressed in Subsection 5.4.7 and shown in the SIS/SCS flow diagrams in Figure 6.3.2-1 and Table 5.2-3.

5.2.2.4 Equipment and Component Description 5.2.2.4.1 Pressurizer Pilot-Operated Safety Relief Valves The pressurizer POSRVs are pilot-operated, forged-steel valves. These valves are mounted on the top of the pressurizer. Further description of these valves is provided in Subsection 5.4.14. A schematic drawing of the pressurizer POSRVs is given in Figure 5.4.14-1. Valve parameters are given in Table 5.4.14-1.

Open and closed indications of each POSRV are provided in accordance with the recommendations of TMI Action Plan Item II.D.3 in 10 CFR 50.34(f)(2)(xi).

5.2.2.4.1.1 Pressurizer Pilot-Operated Safety Relief Valves Operation Four pressurizer POSRVs are connected to the top of the pressurizer by separate inlet lines.

There are two main discharge lines to the IRWST. The steam from two POSRVs is discharged through one common discharge line. Each pressurizer POSRV provides the 5.2-9 Rev. 2

APR1400 DCD TIER 2 overpressure protection function with a main valve and two spring-loaded pilot valve assemblies.

Each assembly consists of a motor-operated isolation valve, a spring-loaded pilot valve, a floating device, and a manual isolation valve. The spring-loaded pilot valve of each POSRV acts as a safety valve in the closed position during normal operation and opens automatically if the system pressure increases to the POSRV set pressure, thus opening the floating device and the main valve.

Motor-operated isolation valves are normally open but are manually closed by an operator to isolate the discharge from the POSRVs when the spring-loaded pilot valves fail to close.

Manual isolation valves are normally open but are closed manually by an operator during maintenance or a setpoint test.

Each pressurizer POSRV inlet nozzle is designed to pass a maximum steam flow in consideration of the maximum pressure drop from the pressurizer to the POSRV.

5.2.2.4.1.2 Transients The pressurizer POSRVs are designed to withstand the consequences of the design transients of Table 3.9-1 without failure or malfunction.

5.2.2.4.1.3 Environment The pressurizer POSRVs are designed to operate in normal and accident conditions.

Normal and accident environmental conditions refer to environmental categories B and A in Table 3.11-2, respectively.

5.2.2.4.2 Main Steam Safety Valves The main steam safety valves are direct-acting, spring-loaded, carbon steel valves. The valves are mounted on each of the main steam lines upstream of the main steam isolation valves outside the containment. The valve parameters are given in Table 5.4.14-2.

Additional description of overpressure protection equipment and components for the main steam system is provided in Subsection 10.3.2.

5.2-10 Rev. 2

APR1400 DCD TIER 2 5.2.2.4.2.1 Main Steam Safety Valve Operation Main steam safety valve operation is characterized by a sharp opening at the set pressure.

The sharp opening is produced by two stages of reactions working together to produce a continuous action. The initial lift is produced when the steam pressure under the disc exceeds the spring force. The escaping steam reacts against the upper guide ring and pushes the disc up to a high lift. The reaction of the deflected steam against the underside of the disc lifts it higher on an accumulation of pressure. The valve reaches a lift in excess of full bore lift within an accumulation of 3 percent above the set pressure. As the system pressure drops, the valve disc settles to a moderate lift and closes quickly after blowing down to a pressure within 5 percent of set pressure.

5.2.2.4.2.2 Transients The main steam safety valves are designed to withstand the consequences of the design transients of Table 3.9-1 without failure or malfunction.

5.2.2.4.2.3 Environment The main steam safety valves are designed to operate in the normal and accident conditions.

Normal and main steam line break conditions refer to environmental categories L and M in Table 3.11-2, respectively.

5.2.2.4.3 Shutdown Cooling System Suction Line Relief Valves (SI-179 and SI-189)

The SCS suction line relief valves that are used to provide LTOP are self-actuating, spring-loaded liquid relief valves with sufficient capacity to mitigate the most limiting overpressurization event. Control circuitry is not required because the valves open when RCS pressure exceeds the setpoint.

5.2.2.4.3.1 Shutdown Cooling System Suction Line Relief Valves (SI-179 and SI-189) Operation The relief valves installed in the two SCS suction lines (one per train) provide LTOP for RCS when the SCS is aligned to the RCS during plant cooldown and heatup operations.

The valves open up to 100 percent at 110 percent pressure of the setpoint.

5.2-11 Rev. 2

APR1400 DCD TIER 2 5.2.2.4.3.2 Transients Transients are described in Subsection 5.2.2.2.2.1.

5.2.2.4.3.3 Environment The SCS suction line relief valves are designed to operate in normal and accident conditions. Normal and accident environmental conditions refer to environmental categories B and A, respectively, and are addressed in Table 3.11-2.

5.2.2.5 Mounting of Pressure-Relief Devices 5.2.2.5.1 Configuration of Pressure Relief Devices The POSRVs and MSSVs are mounted to provide overpressure protection for the primary side and secondary side, respectively.

The design basis for the assumed loads for the primary and secondary side pressure relief devices are described in Subsection 3.9.3.

The POSRVs are shown in Figure 5.4.14-1. They discharge to the IRWST.

5.2.2.5.2 Design Bases for Mounting of Reactor Coolant Pressure Boundary Pressure Relief Devices The RCPB pressure relief devices are mounted and installed as follows:

a. Each discharge pipe is supported to transfer transient discharge load to the pressurizer or adjacent structure in order to stay within the allowable pressurizer nozzle loads.

b. There is no rigid restraint in the vertical directions. The piping system moves up or down with the pressurizer during heat up or cool down. The weight of the piping system is carried by spring supports.

c. Each POSRV discharge piping is supported so that forces and moments during operating plant conditions (normal, upset, emergency, and faulted) will not jeopardize the integrity of the valves, the inlet lines to the valves or the nozzles on the pressurizer.

5.2-12 Rev. 2

APR1400 DCD TIER 2

d. Pipe breaks are postulated in the high-energy piping between the pressurizer nozzle and the valve flange joint. Pipe breaks are not postulated in the POSRV discharge piping (i.e., piping from the valve discharge flange to the IRWST).

This piping is not considered high-energy piping because it operates for less than 2 percent of the normal plant operating time. Discharge piping is classified as moderate-energy piping. Through-wall cracks are not postulated because this piping is adequately separated from other safety-related active systems subject to impairment by such failures.

Dynamic analysis for seismic and valve discharge loadings are performed to verify the design of the support configuration.

5.2.2.5.3 Pressurizer Pilot-Operated Safety Relief Valve Analysis - Loading Criteria and Methods of Analysis 5.2.2.5.3.1 Loading Conditions Loading combinations for upstream Class 1 piping is shown in Table 3.9-10.

5.2.2.5.3.2 Pressure Pressure loading is in accordance with the applicable ASME Code. The design pressure is 175 kg/cm2G (2,485 psig) for Class 1 piping and 49.21 kg/cm2G (700 psig) for non-ASME Section III piping.

5.2.2.5.3.3 Weight A weight analysis is performed on the complete piping system. Hydrotest conditions are also considered in the analysis.

5.2.2.5.3.4 Seismic The structural response due to the loadings is analyzed as discussed in Subsection 3.7.2.

5.2.2.5.3.5 Thrust 5.2.2.5.3.5.1 Hydraulic Thrust Forces The POSRV and connecting piping are subjected to hydraulic thrust forces that are the result of changes in direction of the fluid and change in flow rate and from different fluid 5.2-13 Rev. 2

APR1400 DCD TIER 2 states such as vapor, liquid, and mixed vapor and liquid. The piping and valve supporting system is designed to withstand these thrust loads.

5.2.2.5.3.5.2 Structural Analysis of Thrust The dynamic structural solution for the thrust loading is obtained using a modified predict-corrector integration technique and normal mode theory. PIPESTRESS (Reference 14) is used in the piping design (refer to Subsection 3.9.1.2.1).

RELAP5/MOD3.3 (Reference 15) is used to predict the transient flows resulting from the actuation of a POSRV. It also predicts the resulting piping loads used as dynamic forcing functions for structural design of discharge piping and its supporting components.

The computation is based on finite difference solutions by the method of characteristics.

The computed transient pressure, velocity, and density are then used to calculate loads on bends and pipe runs.

5.2.2.5.4 Main Steam Safety Valve Analysis 5.2.2.5.4.1 Valve Forces and Reaction Load Paths Two conditions are considered in the stress analysis of the safety valve installations: the dynamic effects of the safety valve opening and the steady-state flow condition reached after the valve has opened and is exhausting into the stack. During the valve opening period, dynamic forces due to the hydraulic transients in the valve are compensated by the reaction forces of the header supports through the header. When the valve has opened and the steam is exhausting into the stack, the discharge thrust is compensated by the reaction forces of the stack support structure.

5.2.2.5.4.2 Loading Conditions Refer to Table 3.9-10 for loading combinations for piping upstream of the main steam safety valves.

5.2.2.6 Applicable Codes and Classification The applicable codes and classifications for the overpressurization protection equipment are contained in Table 3.2-1. The applicable codes and classifications for the main steam safety valves are identified in Subsection 10.3.2.

5.2-14 Rev. 2

APR1400 DCD TIER 2 5.2.2.7 Material Specifications RCPB material specifications are described in Subsection 5.2.3.

5.2.2.8 Process Instrumentation Process instrumentation for the overpressure protection equipment associated with the RCS is shown on Figure 5.1.2-3 and described in Chapter 7. Instrumentation associated with the pressurizer relief discharge is described in Subsection 6.8.3.

Open and closed indications of each POSRV are provided in accordance with the recommendations of TMI Action Plan Item II.D.3 in 10 CFR 50.34(f)(2)(xi).

The SCS suction line relief valves, isolation valves, associated interlocks, and instrumentation are addressed in Subsections 3.2.1 and 5.4.7.2.2 and Table 3.2-1. The interlocks and instrumentation associated with the SCS suction line isolation valves are addressed in Subsections 5.4.7, 7.6.1, and 7.6.1.1 and Table 7.6-1.

5.2.2.9 System Reliability The pressurizer POSRVs are pilot-operated mechanisms and cannot fail closed if the setpoint pressure is exceeded. The force of the spring on the main valve disc area is designed to resist the inward pressure force of 2.0 kg/cm2 D (29 psid). The minimum RCS pressure must be higher than or equal to 2.0 kg/cm2 D (29 psid) for the main valve to remain open. In addition, the minimum RCS pressure required to open the main valve from the closed position is 10.2 kg/cm2 D (145 psid).

The spring-loaded pilot valves are designed in accordance with the requirements of ASME Section III. Two spring-loaded pilot valves in parallel provide single-failure protection against failure to open the pressurizer POSRVs. A motor-operated isolation valve installed upstream of each spring-loaded pilot valve and operated by electrical actuator with normal and safety grade powers provides protection against failure to close the pressurizer POSRVs. In addition, all pilot valves and main valves have temperature indicators in the discharge line to detect a leak in any valve. The indicators show inadvertent openings of the pressurizer POSRVs. The operator can close the valves by actuating the motor-operated isolation valves. Subsection 15.6.1 presents an analysis of the inadvertent opening of a POSRV.

5.2-15 Rev. 2

APR1400 DCD TIER 2 Reasonable assurance of the operational reliability of the pressurizer POSRVs is provided by:

a. Conformance with ASME OM Code for safety valves

b. Conservative design criteria (actual pressurizer POSRV steam flow exceeds the analysis flow rate)

c. Testing and surveillance prescribed by the Technical Specifications The main steam safety valves have active and spring-actuated mechanisms that cannot maintain a closed position when the setpoint pressure is exceeded. Reasonable assurance of the operational reliability of the main steam safety valves is provided by the same methods as the pressurizer POSRVs.

The SCS suction line relief valves (SI-179 and SI-189) are independent of a loss of offsite power. No single failure of an isolation valve or its associated interlock prevents one relief valve from performing its intended function. If the SCS suction line relief valves are not aligned to the RCS before the cold leg temperature is reduced to below the maximum RCS cold leg temperature requiring LTOP, an alarm notifies the operator to open the SCS suction line isolation valves (SI-651, SI-652, SI-653, and SI-654). Each SCS suction line relief valve is a self-actuating, spring-loaded liquid relief valve that does not require control circuitry. Reasonable assurance of the SCS suction line relief valves is provided by design according to ASME Section III-NC, conservative design criteria, and periodic testing of the Technical Specifications.

5.2.2.10 Testing and Inspection Preservice testing of the pressurizer POSRVs and main steam safety valves includes testing as specified in Chapter 14. The testing and inspection requirements are in conformance with ASME OM Code and ASME Section XI including the recommendations of TMI Action Plan Item II.D.1 in 10 CFR 50.34(f)(2)(x). The tests listed below are performed for preservice and inservice testing of the pressurizer POSRVs. No separate inservice testing requirements are to be applied to the operability of the POSRV floating device because it is actuated automatically by a spring-loaded pilot valve, and the POSRV floating device operability can be verified by testing the main valve as follows:

a. Opening setpoint verification test for the spring-loaded pilot valves 5.2-16 Rev. 2

APR1400 DCD TIER 2

b. Operability (including opening time) test for the main valves by use of the spring-loaded pilot valves

c. Operability test for the motor-operated isolation valves

d. Seat leak tight test for each valve

e. Operability test for the position indication of each valve

f. Operability (including closing time) test for the main valves by the use of spring-loaded pilot valves Inservice inspection and testing of the main steam safety valves are governed by ASME OM Code and ASME Section XI.

Preservice and inservice testing of the SCS suction line relief valves (SI-179 and SI-189) setpoint are performed according to the ASME OM Code.

5.2.3 Reactor Coolant Pressure Boundary Materials 5.2.3.1 Material Specification This subsection describes material issues common to the reactor coolant pressure boundary (RCPB) components. RCPB materials are fabricated in accordance with the requirements of GDC 1 and GDC 30 of 10 CFR Part 50, Appendix A; NRC RG 1.84; and 10 CFR 50.55a.

A list of specifications for the principal ferritic materials, austenitic stainless steels, bolting and weld materials, which are part of the RCPB, is given in Table 5.2-2. The COL applicant is to address the list of material specifications, which are not shown in Table 5.2-2, as necessary (COL 5.2(4)). The materials used in the RCPB meet the applicable material requirements of ASME Section III and conform to the applicable ASME Section II (Reference 16) material specifications or ASME Code Cases permitted or approved by the NRC. The COL applicant is to address the addition of ASME Code Cases that are approved in NRC RG 1.84 at the time of the application (COL 5.2(1)).

Austenitic stainless steel base materials for RCPB applications are solution-heat-treated to prevent sensitization and primary water stress corrosion cracking (SCC). Alloy 600 base metal and Alloy 82/182 weld metal are not used in RCPB applications. Only alloy 690 base metal and Alloy 52/52M/152 weld metals are used for RCPB applications. Alloy 5.2-17 Rev. 2

APR1400 DCD TIER 2 690 base metals are thermally treated to enhance their resistance to primary water stress corrosion cracking (PWSCC).

All carbon and low alloy steel materials including weld materials used within the RCPB are limited to maximum sulfur (S) content of equal to or less than 0.010 wt%.

Studies referenced in NRC RG 1.99, Revision 02 (Reference 17), have shown that irradiation-induced mechanical property changes of SA-508 materials can depend significantly on the amount of residual elements present in the compositions (i.e., copper, nickel, phosphorous, and vanadium). Residual sulfur has also been found to affect the initial toughness of SA-508 materials. Controls are placed on the residual chemistry of RV materials and the as-deposited welds used to join these materials to limit the maximum predicted increase in the RTNDT, which is described in Subsections 5.3.1.6 and 5.3.2.1.1, and to limit the extent of the RV beltline. The beltline is defined in Appendix G of 10 CFR Part 50 (Reference 18).

SA-508 Grade 3, Class 1 material, which is used in the RV beltline and the as-deposited welds, contains no greater than the following weight percent of residual elements:

Copper (in welds) 0.05 Phosphorous 0.012 Copper (in forgings) 0.03 Sulfur 0.010 Nickel (in forgings) 1.00 Vanadium 0.030 Nickel (in welds) 0.10 5.2.3.2 Compatibility with Reactor Coolant 5.2.3.2.1 Reactor Coolant Chemistry Controlled water chemistry is maintained within the RCS. RCS water chemistry is specified to minimize corrosion. RCS water chemistry specifications are shown in Table 5.2-5 through Table 5.2-8.

The chemistry control parameters, action levels values and hold limits presented herein are appropriate for protecting primary system pressure boundary integrity and/or fuel integrity.

Three Action Levels in the Tables 5.2-7 and 5.2-8 are defined for remedial actions to be taken when control parameters are confirmed to be outside the control values. Depending on the specific control parameter, some or all of these Action Levels are assigned to 5.2-18 Rev. 2

APR1400 DCD TIER 2 specific impurity concentrations. The associated actions, as each Action Level is exceeded, increase in severity from 1 through 3. Corrective actions in response to exceeding an Action Level must in all cases be consistent with plant Technical Specifications.

Action Level 1 The Action Level 1 value of a parameter represents the threshold value, beyond which plant or research data or engineering judgment indicates that long-term system reliability may be affected, thereby warranting an improvement of operating practices.

Actions to be taken if a parameter exceeds the Action Level 1 value:

a. Efforts shall be made to bring the parameter to below the Action Level 1 value within seven days.

b. If the parameter has not been restored to below the Action Level 1 value within seven days, a technical review shall be performed and a program for implementing corrective measures instituted. Such a program may require equipment additions or modifications over the long term.

Action Level 2 The Action Level 2 value of a parameter represents the threshold value, beyond which plant or research data or engineering judgment indicates significant damage could be done to the system in the short term, thereby warranting a prompt correction of the abnormal condition.

Actions to be taken if a parameter exceeds the Action Level 2 value:

a. Efforts shall be made to bring the parameter to below the Action Level 2 value within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. If the parameter has not been restored to below the Action Level 2 value within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, an orderly shutdown shall be initiated and the plant shall be brought to a coolant temperature < 98.9 ºC (210 ºF) as quickly as safe plant operation permits.

If chemistry is improved to below the Action Level 2 value prior to plant shutdown, full power operation may be resumed.

5.2-19 Rev. 2

APR1400 DCD TIER 2

c. Following an Action Level 2 event, a technical review of the incident shall be performed and appropriate corrective measures taken before the plant is restarted.

Action Level 3 The Action Level 3 value of a parameter is the threshold value, beyond which plant or research data or engineering judgment indicates that it is inadvisable to continue to operate the plant.

Actions to be taken if a parameter exceeds the Action Level 3 value:

a. An orderly plant shutdown shall be initiated immediately, with reduction of coolant temperature to < 98.9 ºC (210 ºF) as rapidly as safe plant constraints permits.

b. Following an Action Level 3 event, a technical review of the incident shall be performed and appropriate corrective measures taken before the plant is restarted.

Water chemistry limits are determined at a level comparable to the guidelines in the Electric Power Research Institutes (EPRIs) PWR Water Chemistry Guidelines (Reference 19) that are to be implemented. The COL applicant will review and confirm at the time of COL submittal based on the latest revision of EPRI PWR Primary Side Water Chemistry Guidelines (COL 5.2(5)). Control of the reactor coolant chemistry is a function of the chemical and volume control system (CVCS), which is addressed in Subsection 9.3.4.

The CVCS is designed to perform the following functions:

a. Maintain the chemistry including pH and purity of the reactor coolant during prestartup testing, startups, normal operation, and during shutdowns

b. Scavenge oxygen from the coolant before heat-up

c. Control radiolysis reactions involving hydrogen, oxygen, and nitrogen during normal operation The pH control is accomplished using lithium hydroxide monohydrate where the lithium is in the form of a lithium-7 isotope that is enriched to greater than 99.9%. This chemical is chosen for its compatibility with the water chemistry of borated water/stainless steel/zirconium/Inconel systems. The lithium-7 hydroxide solution is prepared in the 5.2-20 Rev. 2

APR1400 DCD TIER 2 laboratory and transferred to the chemical addition tank. Reactor makeup water is then used to flush the solution to the suction header of the charging pumps. If the concentration of lithium-7 hydroxide exceeds the specified range, a mixed-bed ion exchanger is employed in the letdown line in series operation with the mixed-bed ion exchanger to maintain the proper concentration.

Two chemicals (hydrazine and hydrogen) are added to the reactor coolant to control dissolved oxygen (DO).

Preoperational oxygen scavenging is accomplished by the addition of hydrazine. During preoperation, 30 to 50 ppm of hydrazine is maintained in the reactor coolant whenever the reactor coolant temperature is below 65.6 ºC (150 ºF). This prevents halide-induced attack, which could occur if significant quantities of fluorides or chlorides and significant amounts of DO are present. It is important to establish a DO limit prior to reaching 121.1 ºC (250 ºF). If DO in excess of 0.1 ppm is present at temperatures above 121.1 ºC (250 ºF) it will be necessary either to a) degas the RCS while feeding and bleeding, or b) cooldown to less than 121.1 ºC (250 ºF) to add hydrazine at 1.5 times the oxygen concentration. During cooldown from operating temperatures, a hydrazine residual of 30 to 50 ppm must be established with RCP circulation, while reactor coolant temperature is between 65.6 ºC (150 ºF) and 176.7 ºC (350 ºF). To minimize thermal decomposition, hydrazine should not be added until coolant temperature is less than 204.4 ºC (400 ºF).

During startup and shutdown, any DO is scavenged by the hydrazine, eliminating the potential for general corrosion. DO should be monitored and hydrazine added to 1.5 times the DO concentration before exceeding 65.6 ºC (150 ºF). When the reactor coolant temperature exceeds 121.1 ºC (250 ºF), either DO must be less than 0.1 ppm, or a hydrazine residual of 1.5 times the DO concentration must be present.

At power operation, DO concentration is limited by maintaining the excess dissolved hydrogen in the coolant. To minimize the effect of crud deposition on the reactor core heat transfer surfaces, lithium-7 hydroxide is added. Lithium-7 hydroxide produces pH conditions within the reactor coolant at operating temperatures that reduce the corrosion product solubility and hence the dissolved crud inventory in the circulating reactor coolant. The lithium concentration is maintained as shown in Table 5.2-7, Table 5.2-8, and Figure 5.2.3-1. Subsection 9.3.4 provides additional information on the water chemistry limits applicable to the RCS.

5.2-21 Rev. 2

APR1400 DCD TIER 2 During the preoperation, the boron will range from near zero to 4,400 ppm, and lithium from 0 to 3.5 ppm. Thus, for the given range, the pH may be 4.2 to 10.7. Boron will range from near zero at end of cycle to 4,400 ppm at refueling. Lithium, the alkalizing additive employed, will vary from 0.2-3.5 ppm. Considering all ranges above, the expected pH range is approximately 4.2-10.7. Fuel designer also judge that it is reasonable for fuel integrity to increase lithium concentration up to 3.5 ppm because the possibility of crud occurrence followed by low pHT (< 6.9) operation may increase if lithium concentration limit is not raised during high boron concentration. Generic principles for optimization of RCS pH is based on EPRI PWR Primary Water Chemistry Guidelines. The range of optimum high pH value is 6.9-7.4 at 307.2 ºC (6.0-7.3 at 25 ºC (77 ºF)) during power operations.

Figure 5.2.3-1 illustrates lithium/boron programs that reflect beginning-of-cycle operation at the highest pHT possible within fuel vendor constraints and no greater than 3.5 ppm lithium (except for brief periods with fuel vendor concurrence), then operating at a constant pHT = 7.2 through the cycle. This approach to pH control (the Elevated pHT regime), is thought to reduce early-cycle corrosion product release rated and deposition onto the core, and has been adopted at several US PWRs experiencing axial offset anomalies or whose objectives are to minimize crud deposition and reduce radiation fields in ex-core regions.

In general, field experience along with laboratory testing has shown that operation with pHT = 7.1, 7.2 or even 7.4 results in lower out-of-core radiation fields than at pHT = 6.9 (Figure 5.2.3-1 shows the operation with pHT = 7.2). In addition there are very recent data which tend to indicate that higher concentrations of suspended CRUD activity may result from operation for a whole cycle at pHT = 6.9. However, the most important aspect is to avoid operation at lower pHT (i.e., less than 6.9). Such operation produces heavier core deposits which can restrict coolant flow, elevate core differential pressure and result in higher out-of-core radiation fields.

During plant startup, the dissolved oxygen and chloride limits presented in Table 5.2-7 of 0.1 ppm and 0.15 ppm, respectively, were established from the relationships between oxygen and chloride concentrations and their effect on the susceptibility to stress corrosion cracking of austenitic stainless steel. Current industry data reveals that no chloride stress corrosion occurs at oxygen concentrations below approximately 0.8 ppm. The dissolved oxygen limit was reduced to give a conservative concentration of 0.1 ppm oxygen. The maximum amount of oxygen from air dissolved in water at 25 ºC (77 ºF) is approximately 8 ppm. At this concentration, a chloride concentration of less than approximately 1.5 ppm 5.2-22 Rev. 2

APR1400 DCD TIER 2 would preclude the possibility of chloride stress corrosion. This limit was reduced to provide a conservative chloride limit of 0.15 ppm.

The fluoride limit of 0.15 ppm for reactor coolant is the result of the fluoride ion being identified as causing intergranular corrosion of sensitized austenitic stainless steels. Based on this, it is essential to minimize fluoride ions in the reactor coolant. Therefore, the concentration chosen as the maximum limit is the lowest concentration which can be both:

(1) readily detected in bulk water and (2) maintained by the action of the purification ion exchanger.

One of the most common impurities is ammonia. Ammonia increases both RCS pH and conductivity above that expected for the lithium and boron content. Since hydrazine decomposes to generate ammonia at high temperature (above 204 ºC (400 ºF)), and since ammonia and boric acid together in quantity may cause release of chloride ions from ion exchange beds, the amount of hydrazine added must be minimized.

Boron in the chemical form of boric acid is added to the RCS for long-term reactivity control of the core.

Suspended solid (corrosion product particles) and other impurity concentrations are maintained below specified limits by controlling the chemical quality of makeup water and chemical additives and by purification of the reactor coolant through the CVCS.

Silica may be present in the reactor coolant as a result of makeup water, refueling water, or boric acid. Increasing silica concentrations in the RCS have been primarily associated with the degradation of material in the spent fuel racks, but another source of increasing silica is the practice of recycling boric acid. The highest concentrations of silica are generally observed at the beginning of cycle.

In the presence of zeolite forming cations such as aluminum, magnesium and calcium, silica can precipitate with these cations to form various silicates which, owing to their negative temperature coefficients of solubility, will deposit preferentially on hot fuel surfaces. Magnesium is the most limiting cation species with respect to silicate precipitation. To address the potential for core deposit densification and the potential impact on Zircaloy-4 corrosion, industry guidelines currently recommend monitoring silica as a diagnostic parameter and reducing RCS silica to 1 ppm or less during full power operation. While recognized as a diagnostic parameter, many PWR operators have adopted this limit, particularly in plants where silica concentrations have been increasing.

5.2-23 Rev. 2

APR1400 DCD TIER 2 The 1 ppm limit derives from the observation that there are no data that suggest silica concentrations below 1 ppm and in the absence of hardness cations (Al, Mg, Ca) will precipitate silicates. If RCS silica levels are expected to exceed 1ppm, maintaining low aluminum, calcium and magnesium concentrations in the makeup water is considered prudent.

The most rapid and reliable measurement of water quality is conductivity. As makeup water system ion exchangers become exhausted, conductivities rise rapidly and into the abnormal range. As is true for all waters of this purity, conductivity can be measured only via an in-line cell. The process of taking a grab sample will always allow dissolution of sufficient carbon dioxide to increase conductivity significantly.

5.2.3.2.2 Materials of Construction Compatibility with Reactor Coolant The construction materials used in the RCPB that are in contact with the reactor coolant are designated in Table 5.2-2. These materials are selected to minimize corrosion and have demonstrated satisfactory performance in existing operating reactor plants. The materials used for the RCPB conform with the requirements of GDC 4 of 10 CFR Part 50, Appendix A. Conformance of the fabrication and processing of austenitic stainless steels with NRC RG 1.44 (Reference 20) is shown in Subsection 5.2.3.4.1. Stainless steel or nickel-chromium-iron cladding is applied for corrosion resistance to all ferritic low-alloy and carbon steel surfaces that come into contact with the reactor coolant.

The joints between the austenitic safe ends and low alloy or carbon steel nozzles are made by welding with Alloy 690 equivalent weld materials. Austenitic stainless steel and A690 base materials that are used for primary pressure-retaining applications are supplied in the solution-annealed and thermally treated condition, respectively.

Cobalt content is restricted to as low a level as practicable in metallic materials that are in contact with reactor coolant and that are in stainless steel or nickel-based alloy components with a large wetted surface area. Cobalt-based alloys are avoided except when no proven alternative exists. The cobalt-based alloys used in RCS components are Haynes 36 alloy for the link and latch of CEDMs, Stellite 6 for the pins in CEDM motor assembly, and Stellite 6 alloy for hardfacing materials in the valve seats and other parts, such as valve stems.

5.2-24 Rev. 2

APR1400 DCD TIER 2 These cobalt-based alloys are used to provide wear resistance and have good operating history in OPR1000 plants (Hanbit Units 3,4,5&6, Hanul Units 3,4,5&6, Shin-Kori Units 1&2 and Shin-Wolsung Units 1&2) and several CE type plants.

Spiral wound gaskets, which contain nonmetallic material, are used for primary manways of steam generators and pressurizer. Generally, the spiral wound gasket is made of flexible graphite and Inconel X-750. Field experience shows that the gaskets have compatibility with reactor coolant.

5.2.3.2.3 Compatibility with External Insulation and Environmental Atmosphere All metallic insulation used in the plant is stainless steel reflective, which minimizes insulation contamination in the event of chemical solution spillage. All non-metallic insulation used in the plant is designed to meet the requirements of NRC RG 1.36 (Reference 21), Non-metallic Thermal Insulation for Austenitic Stainless Steel.

Conforming with the NRC RG provides reasonable assurance that non-metallic insulation is designed in a manner that minimizes the potential for stress corrosion of stainless steel due to leaching of chloride or fluoride ions onto the stainless steel surfaces.

5.2.3.3 Fabrication and Processing of Ferritic Materials Fracture toughness requirements for reactor coolant pressure boundary components are established in accordance with ASME Section III and NRC SRP BTP 5-3 (Reference 22).

Fracture toughness testing of base, weld and heat-affected zone materials is conducted in accordance with the ASME Code. Data from these tests are available after the required testing has been performed and are examined upon request at the appropriate manufacturing facility. The RCPB also conforms with the requirements of GDC 14 and 31 of 10 CFR Part 50, Appendix A, and 10 CFR Part 50, Appendix G, Fracture Toughness Requirements.

Consideration is given to the effects of irradiation on material toughness properties in the core beltline region of the reactor vessel to provide reasonable assurance of adequate fracture toughness for the service life of the vessel. Subsection 5.3.1.6 addresses the prediction of irradiation effects and the material surveillance program.

Testing and measuring equipment for fracture toughness tests for the reactor vessel, steam generators, pressurizer, piping, and reactor coolant pumps are calibrated in accordance with ASME Section III, NB-2360.

5.2-25 Rev. 2

APR1400 DCD TIER 2 The COL applicant is to address the actual, as-procured, fracture toughness data of the RCPB materials to the staff at a predetermined time by an appropriate method (e.g., ITAAC)

(COL 5.2(6)).

Welding of ferritic materials conforms with the recommendations of NRC RG 1.50 (Reference 23), Control of Preheat Temperature for Welding of Low Alloy Steel, as described below.

Paragraph C.1. of NRC RG 1.50 implies that the qualification materials are an infinite heat sink that would instantaneously dissipate the heat input from the welding process. The qualification procedure consists of starting the welding at the minimum preheat temperature.

Welding is continued until the maximum interpass temperature is reached. The test material is then permitted to cool to the minimum preheat temperature and the welding is restarted. Preheat temperatures utilized for low alloy steel are in accordance with ASME Section III Appendix D (Reference 24). Generally, the maximum interpass temperature utilized is 260 °C (500 °F). The minimum preheat temperature and maximum interpass temperature to be specified in the welding procedure specification are equal to the temperatures used during procedure qualification.

Hydrogen is removed either by maintaining preheat until post-weld heat treatment is performed or by post heating at a temperature and time sufficient to preclude the effects of hydrogen assisted cracking if post-weld heat treatment is required by ASME Code.

In the event that Paragraphs C.1., C.2., and C.3. of NRC RG 1.50 are not met, the soundness of the weld is demonstrated by an examination that meets the acceptance criteria specified in ASME Section III.

With regard to NRC RG 1.43 (Reference 25), major components are fabricated with corrosion resistant cladding on internal surfaces exposed to reactor coolant. The major portion of the material protected by cladding from exposure to reactor coolant is SA-508 Grade 3, Class 1, which is resistant to underclad cracking.

NRC RG 1.34 (Reference 26) recommends that control be applied during welding using the electroslag process. The electroslag process is not used in the fabrication of any RCPB components. Therefore, the recommendations in NRC RG 1.34 are not applicable.

The APR1400 conforms with the recommendations of NRC RG 1.71 (Reference 27) for the performance qualifications of personnel welding under conditions of limited accessibility.

5.2-26 Rev. 2

APR1400 DCD TIER 2 The nondestructive examination requirements for tubular products are specified by ASME Section III. For major components, additional testing and inspection are explained in Subsections 5.3.1.3, 5.4.1.4, 5.4.2.3, 5.4.3.4, and 5.4.10.4.

5.2.3.4 Fabrication and Processing of Austenitic Stainless Steel 5.2.3.4.1 Avoidance of Stress Corrosion Cracking of Reactor Coolant Pressure Boundary Components Fabrication of RCPB components is consistent with the recommendations of NRC RG 1.44 as described below. ASTM A262 (Reference 28) Practice A or E is used to demonstrate freedom from sensitization in fabricated, unstabilized stainless steel.

a. Solution heat treatment requirements All raw austenitic stainless steel material, both wrought and cast, used in the fabrication of RCPB components is supplied in the annealed condition as specified by the pertinent ASME Code.

Solution heat treatment is not performed on completed or partially fabricated components. Rather, the extent of chromium carbide precipitation is controlled during all stages of fabrication as described in Items b, c, and d below.

b. Material inspection program Extensive testing on stainless steel mockups, fabricated using production techniques, has been conducted to determine the effect of various welding procedures on the susceptibility of unstabilized Type 300 series stainless steels to sensitization induced intergranular corrosion. Only the procedures and/or practices demonstrated not to produce a sensitized structure are used in the fabrication of RCPB components. ASTM A262 Practices A or E is the criterion used to determine susceptibility to intergranular corrosion. The test has shown excellent correlation with a form of localized corrosion peculiar to sensitized stainless steels. As such, ASTM A262 Practice A or E is used as a go/no-go standard for acceptability.

5.2-27 Rev. 2

APR1400 DCD TIER 2 As a result of the above test, a relationship was established between the carbon content of Type 304 stainless steel and weld heat input. This relationship is used to avoid weld-heat-affected-zone sensitization as described in Item d below.

c. Unstabilized austenitic stainless steel The unstabilized grades of austenitic stainless steels with carbon content of more than 0.03 percent used for components of the RCPB are Type 304 and Type 316.

These materials are furnished in the solution-annealed condition. Completed or partially fabricated components are not exposed to temperatures from 427 °C (800 °F) to 816 °C (1,500 °F).

CF8M, CF8 Cast stainless steel: delta ferrite 8 percent to 30 percent, 8 percent to 20 percent for normal operating temperature above 250 °C (482 °F), 14 percent maximum for static cast stainless steel of CF8M for normal operating temperature above 250 °C (482 °F)

Type 308, 309, 312, 316 Singly and combined stainless steel weld filler metals:

delta ferrite controlled to 8FN-15FN (8FN-16FN for Type 309 (L)) with no reading below 5FN as deposited

d. Avoidance of sensitization Exposure of unstabilized austenitic Type 300 series stainless steels to temperatures ranging from 427 to 816 °C (800 to 1,500 °F) results in carbide precipitation.

The degree of carbide precipitation, or sensitization, depends on the temperature, the amount of time at that temperature, and the carbon content. Severe sensitization is defined as a continuous grain boundary chromium-iron carbide network. This condition induces susceptibility to intergranular corrosion in oxygenated aqueous environments, as well as those containing fluorides. Such a metallurgical structure rapidly fails the ASTM A262 Practice A or E Test.

Discontinuous precipitates (i.e., an intermittent grain boundary carbide network) are not susceptible to intergranular corrosion in a PWR environment.

Weld-heat-affected-zone sensitized austenitic stainless steels are minimized by carefully controlling:

5.2-28 Rev. 2

APR1400 DCD TIER 2

1) Weld heat input to less than 23.6 kJ/cm (60 kJ/in)

2) Interpass temperature to 176.7 °C (350 °F) maximum

3) Carbon content to 0.065 percent maximum Homogeneous or localized heat treatment in the temperature range from 427 to 816 °C (800 to 1,500 °F) is prohibited for unstabilized austenitic stainless steel with a carbon content greater than 0.03 percent used in components of the RCPB. When stainless steel safe ends are required on component nozzles, fabrication techniques and sequencing require that the stainless steel piece be welded to the component after final stress relief. This is accomplished by welding a NiCrFe buttering on the end of the nozzle. Following final stress relief of the component, the stainless steel safe end is welded to the NiCrFe buttering, using NiCrFe weld metals of SFA-5.11 ENiCrFe-7 or SFA-14 ERNiCrFe-7(A).

5.2.3.4.2 Cleaning and Contamination Protection Specific requirements for cleanliness and contamination protection are included in the equipment specifications for components fabricated with austenitic stainless steel. The provisions described below indicate the type of procedures used for RCPB components to provide contamination control during fabrication, shipment, and storage as required by NRC RG 1.28 (Reference 29). The cleanness classification of RCPB components that is graded based upon the safety function and operational environment of RCPB components is complied with guidance of NQA-1, Part III, Subpart 3.2, Appendix 2.1.

Contamination of austenitic stainless steel series by compounds that can alter the physical or metallurgical structure and/or properties of the material is avoided during all stages of fabrication. Type 300 series stainless steels are not painted. Grinding is accomplished with resin or rubber-bounded aluminum oxide or silicon carbide wheels that were not previously used on materials other than austenitic alloys that could contribute to intergranular corrosion or SCC.

Outside storage of partially fabricated components is avoided and in most cases prohibited.

Exceptions are made for certain components provided they are dry, completely covered with a waterproof material, and kept above ground.

Internal surfaces of completed components are cleaned to produce an item that is clean to the extent that grit, scale, corrosion products, grease oil, wax, gum, adhered or embedded 5.2-29 Rev. 2

APR1400 DCD TIER 2 dust, or extraneous materials are not visible to the unaided eye. Substances used for cleaning include solvents (acetone or isopropyl alcohol) and inhibited water (hydrazine or tri-sodium phosphate). Water conforms to the following requirements:

Chloride (ppm) < 0.60 Fluoride (ppm) < 0.40 Conductivity (S/cm) < 5.0 pH 6.0-8.0 Visual clarity No turbidity, oil, or sediment To prevent halide-induced intergranular corrosion, which can occur in an aqueous environment with significant quantities of dissolved oxygen, flushing water is inhibited by adding hydrazine or trisodium phosphate. Tests have shown these inhibitors to be effective. Operational chemistry specifications restrict concentrations of halide and oxygen, both precursors of intergranular attacks (refer to Subsection 9.3.4).

5.2.3.4.3 Characteristics and Mechanical Properties of Cold-Worked Austenitic Stainless Steels for RCPB Components Cold-worked austenitic stainless steel is not used for components of the RCPB. The COL applicant is to submit the actual, as-procured yield strength of the austenitic stainless steel materials used in RCPB to the staff at a predetermined time agreed-upon by the regulatory body (COL 5.2(7)).

5.2.3.4.4 Control of Welding RCPB components are designed as follows:

a. NRC RG 1.31 (Reference 30)

In order to preclude microfissuring in austenitic stainless steel welds, RCPB components are consistent with the recommendations of NRC RG 1.31 as follows:

The delta ferrite content of each lot and/or heat of weld filler metal used for welding of austenitic stainless steel code components is determined for each process to be used in production. Delta ferrite of consumable inserts, electrodes, rod, or wire filler metal used with the gas tungsten arc welding process, and deposits made with the plasma arc welding process may be determined by either of 5.2-30 Rev. 2

APR1400 DCD TIER 2 the alternative methods of magnetic measurement or chemical analysis described in ASME Section III.

Delta ferrite content is verified for all other processes by tests using the magnetic measurement method on undiluted weld deposits described by ASME Section III.

The average ferrite content shall meet the acceptance limits of 8FN to 15FN (8FN to 16FN for Type 309 (L)) with no reading below 5FN.

b. NRC RG 1.34 NRC RG 1.34 is addressed in Subsection 5.2.3.3.

c. NRC RG 1.71 NRC RG 1.71 is addressed in Subsection 5.2.3.3.

5.2.3.4.5 Toughness of Cast Austenitic Stainless Steels or Welds Reasonable assurance of the fracture toughness of cast stainless steels is provided by limiting the delta ferrite, determined using the Hulls equivalent factor, in the materials as follows:

a. For normal operating temperatures less than or equal to 250 °C (482 °F): 8 percent to 30 percent

b. For normal operating temperatures above 250 °C (482 °F): 8 percent to 20 percent

c. For normal operating temperature above 250 °C (482 °F), static cast stainless steel of CF3M or CF8M: 14 percent maximum Reasonable assurance of the fracture toughness of stainless steel welds is provided by limiting the delta ferrite in the weld materials as follows:

a. Singly and combined stainless steel weld filler metals: 8FN-15FN (8FN-16FN for Type 309 (L)) with no reading below 5FN as deposited.

5.2.3.4.6 Nondestructive Examination Nondestructive examinations of austenitic stainless steel tubular products for components of RCPB are carried out in accordance with ASME Section III, Subsection NB-2500, under 5.2-31 Rev. 2

APR1400 DCD TIER 2 their construction, and Section XI during inservice inspections. Additional testing and inspection for major components are explained in Subsections 5.3.1.3, 5.4.1.4, 5.4.2.3, 5.4.3.4, and 5.4.10.4.

5.2.3.5 Prevention of Primary Water Stress-Corrosion Cracking for Nickel-Base Alloys Thermally treated Alloy 690 (690TT) and Alloys 52/52M and 152 weld metals are used for the APR1400 design, which have performed well against PWSCC in field operations and laboratory experiments. Alloy 600 and Alloys 82/182 are not used. The resistance of Alloy 690, 52/52M, and 152 to PWSCC in pressurized water reactors is described in EPRI Report MRP-111, Resistance to Primary Water Stress Corrosion Cracking of Alloys 690, 52, and 152 in Pressurized Water Reactors (Reference 31). At present, there were no reports of the cracking of Alloy 690 base and weld metals. A boric acid corrosion (BAC) prevention program or an ISI program is applied to provide reasonable assurance of the integrity of 690TT base and weld metals.

5.2.3.6 Threaded Fasteners Pressure-retaining threaded fasteners used for RCPB components are fabricated in accordance with ASME Section III, Subsection NB. A description of the design of threaded fasteners except for the reactor vessel stud bolts and nuts is provided in Section 3.13.

The stud bolting material of the APR1400 reactor vessel satisfies NRC RG 1.65 (Reference 32). Nondestructive examination of the stud bolting material is performed according to NB-2580 of ASME Section III. Other mechanical tests such as tensile and Charpy V-notch (CVN) impact tests are performed for the threaded fastener materials.

More information is described in Subsection 5.3.1.7.

Threaded fasteners for the other pressure retaining parts of Class 1 components are made of SA-540 Grade B24, SA-193 Grade B7, or SA-194 Grade 4 or 7 low-alloy steel bolting materials. SB-637 N07718 precipitation hardening nickel-based alloy bolting is also used for pressure retaining parts of Class 1 components. CVN tests are performed to confirm that the materials conform with ASME Section III NB-2330 fracture toughness requirements, if required by the Code. Actual fracture toughness test results are provided to the NRC staff at a predetermined time.

5.2-32 Rev. 2

APR1400 DCD TIER 2 5.2.4 Inservice Inspection and Testing of the Reactor Coolant Pressure Boundary 5.2.4.1 Inservice Inspection and Testing Program The inservice inspection (ISI) and testing program for Quality Group A components of the RCPB (ASME Section III, Class 1 components) comforms with the regulatory requirements of 10 CFR 50.55a and GDC 32 of 10 CFR Part 50, Appendix A. The program reflects the principles and intent of ASME Section XI and OM Code. The purpose of the inservice inspection program is to periodically monitor the systems or components requiring inservice inspection in order to identify the systems or components that do not meet acceptance standards and to make the necessary repairs.

The COL applicant is to prepare the inservice inspection and testing program. The COL applicant is to provide and develop the implementation milestones for the inservice inspection and testing program for the RCPB, in accordance with ASME Section XI and 10 CFR 50.55a (COL 5.2(8)).

The ISI and inservice testing (IST) programs consist of the following three subprograms:

a. The component inspection program, which includes nondestructive inspection of major components, piping system and support system

b. The pump and valve inservice testing program, which requires operability testing of selected pumps and valves

c. The hydrostatic testing program The NSSS design provides reasonable assurance that the reactor coolant pressure boundary has an accessibility to perform the preservice and inservice inspections. The pump and valve inservice testing is described in Subsections 3.9.6.2 and 3.9.6.3. Dissimilar metal welds and austenitic welds in piping will be ultrasonically examined from both sides.

When ultrasonic examination from both sides is not possible, procedures, equipment and personnel qualified for single-sided ultrasonic examination in accordance with the ASME code,Section XI, Appendix VIII, with all flaws on the opposite side of the weld, are used to examine the required volume.

5.2-33 Rev. 2

APR1400 DCD TIER 2 5.2.4.1.1 System Boundary Subject to Inspection The reactor pressure vessel, pressurizer, primary side of the steam generator and associated piping, pumps, valves, and bolting, and their component supports, including RCPB (reactor coolant pressure boundary) components are subject to inspection.

All ASME Code Class 1 pressure-retaining components are subject to inspection.

The high-energy system piping between containment isolation valves receives an augmented ISI as described in Subsection 6.6.8.

5.2.4.1.2 Arrangement of Systems and Components to Provide Accessibility Accessibility to equipment for maintenance, testing, and inspection is a basic element of the APR1400 design process. The layout and arrangement of the plant provide adequate working space and access for inspection and for repair and maintenance of specific areas of Class 1 components of the RCPB in accordance with ASME Section XI IWA 1500. All Class 1 components shall be designed for and provided with access to enable the performance of ASME Section XI inspections in the installed conditions. Systems and components are designed such that design, materials, and geometry do not restrict inspections required by ASME Section XI.

The COL applicant is to address the accessibility of Class 1 components for ISI if the design of the APR1400 Class 1 component is changed from the DCD design (COL 5.2(9)).

The provisions for access for examination of the RCPB are as follows:

a. Reactor vessel and closure head

1) From inside the vessel:

All internals of the reactor vessel, which is an open structure offering insignificant impediment to access, are removable making the entire inner surface of the vessel, including the beltline welds and the weld zones of the internal load-carrying structure attachments, available for the required surface and volumetric inspections. Provisions are made in the plant design to allow for the removal and storage of all vessel internals (except the flow skirt) during inservice inspection. The surveillance capsules assemblies are located to allow an essentially 100 percent ultrasonic testing for reactor vessel 5.2-34 Rev. 2

APR1400 DCD TIER 2 circumferential welds. For interim inspections of the vessel, nozzle-to-shell welds and inner radii of the outlet nozzles are accessible from inside the reactor vessel by using remote automated equipment without removal of the vessel internals.

2) From outside the vessel:

The bottom head of the reactor vessel is manually examined from the outside surface and an access tunnel is provided to allow personnel into the area below the bottom head. Insulation is provided by removable panels over the bottom head weld seams.

3) Closure head The closure head is available for inspection when it is removed and its removal makes available the vessel closure flange, upper shell-to-intermediate shell weld, closure stud holes and ligaments, and closure studs and nuts.

Each control element drive mechanism is removable as a unit through a closure at the top of its housing. Because many of the reactor vessel closure head examinations are conducted from the underside of the head, the head laydown area provides access for personnel to work under this component.

b. Reactor coolant piping Biological shielding around the reactor coolant piping in the area of the reactor vessel is designed to afford access to the circumferential and longitudinal welds, as well as the transition piece-to-nozzle welds. The volumetric examinations are performed using ultrasonic techniques.

All reactor coolant piping, as well as major components, excluding the reactor vessel, is provided with removable insulation in the areas of all welds and adjacent base metal requiring examination.

The primary coolant piping has access at each side of the welds to facilitate manual examination of the welds.

c. Steam generators 5.2-35 Rev. 2

APR1400 DCD TIER 2 Sufficient space is provided within the stay cylinder to permit inspection of the welds. A 305 x 406 mm (12 x 16 in) access opening in the steam generator support skirt is provided. The insulation in this area is removable through the support skirt opening.

The steam generators have removable insulation and access at welds requiring examination. Manways are provided for internal steam generator inspections.

Accessibility is considered to enable the ultrasonic examination for the vessel transition welds of the steam generator.

d. Pressurizer The pressurizer has sufficient clearance around the shell weld seams for manual ultrasonic examination of these welds. The insulation is removable at each weld and access is provided for ultrasonic and visual examinations in the area of the bottom head and its nozzle penetrations of the pressurizer. A manway is provided for internal inspections of the pressurizer.

e. Reactor coolant pumps The reactor coolant pumps require inside visual examination. To allow this, provisions are made in the design for the removal and storage of the RCP motors and the disassembly of the reactor coolant pumps. Access is provided to the motor flywheels for ultrasonic examination.

f. Other components All other components, including portions of the steam generators, reactor coolant pumps, pressurizer, and primary piping, are accessible for manual examination from the outside surface.

General provisions are made for removable insulation, removable shielding, installation of handling machinery, adequate personnel, and equipment access space, and laydown space for all temporarily removed or serviced components.

Storage space for the removable insulation panels is also provided. Working room for personnel is provided adjacent to each weld in order to examine all piping system welds manually.

5.2-36 Rev. 2

APR1400 DCD TIER 2 5.2.4.1.3 Examination Categories and Methods Examinations include liquid penetrant, magnetic particle, or eddy current techniques when surface examination is specified; ultrasonic or radiographic techniques when volumetric examination is specified; and visual inspection techniques that are used to determine surface condition of components and for evidence of leakage. Specific techniques, procedures and equipment, including any special techniques or equipment are in accordance with the requirements of ASME Section XI and are defined in the inservice inspection program. Preservice inspection (PSI) and subsequent inservice inspection are conducted with equivalent equipment and techniques.

The visual, surface, and volumetric examination techniques and procedures agree with the requirements of Subarticle IWA-2200, IWB-2000, and Table IWB-2500-1 of ASME Section XI. The methods, procedures, and requirements for qualification of personnel performing ultrasonic examination are in accordance with the requirements of ASME Section XI, Appendix VII. The performance demonstration for ultrasonic examination procedure, equipment, and personnel used to detect and size flaws is in accordance with the requirements of ASME Section XI, Appendix VIII. Personnel performing visual, liquid penetrant, magnetic particle, eddy current or radiographic examinations as a part of the PSI or ISI program are to be qualified in accordance with the requirements of IWA-2300 of ASME Code Section XI.

The data from the various baseline examinations, collected in accordance with the related procedures, are entered into a report with tabulated results. The report describes the scope of the inspection, the procedures utilized, the equipment utilized, names and qualifications of personnel, and all the examination results including all instrument calibration criteria in sufficient detail to provide reasonable assurance of repeatability for each examination.

The categories and requirements appropriate for each examination area follow the categories and requirements specified in Table IWB 2500-1 of ASME Section XI. An inservice inspection program that includes the examination categories is provided in accordance with ASME Section XI, IWB 2000.

The methods, procedures, and requirements for ultrasonic examination of RV welds are qualified by performance demonstration in accordance with the requirements of ASME Section XI, Appendix VIII.

5.2-37 Rev. 2

APR1400 DCD TIER 2 5.2.4.1.4 Inspection Intervals The examination program for the 10-year inspection interval is defined in the ISI plan.

The inspection period may be reduced or extended by as much as 1 year to enable an inspection to coincide with a plant outage. The ISI plan for all Class 1 systems and components is in accordance with ASME Section XI, IWA 2400 and IWB 2400.

5.2.4.1.5 Evaluation of Examination Results Evaluation of examination results for Class 1 components is conducted in accordance with IWA 3000 and IWB 3000 of ASME Section XI. Unacceptable indications are repaired in accordance with the requirements of IWA 4000 of ASME Section XI. Criteria for establishing need for repair or replacement are in accordance with IWB 3000 of ASME Section XI.

5.2.4.1.6 System Pressure Tests The leakage and hydrostatic pressure tests of the RCPB Code Class 1 components are conducted in accordance with the requirements of IWA 5000 and IWB 5000 of ASME Section XI and the Technical Specification. The requirements in the Technical Specifications (Chapter 16) on operating limits during heatup, cooldown, and system hydrostatic pressure testing are used for these tests.

5.2.4.1.7 Code Exemptions For the inservice inspection of APR1400, there are no ASME Code Class 1 components (or portions of components) that are to be exempted from ASME Code,Section XI, IWB-2500 examination requirements, except for the items allowed by ASME Code,Section XI, IWB-1220.

The COL applicant is to provide a list of ASME Section XI Code exemptions in the ISI program of the specific plants, if it exists (COL 5.2(10)).

5.2.4.1.8 Code Cases The ASME Code Cases that are expected to be used in preservice and inservice inspection programs of APR1400 are listed as follows. The COL 5.2(2) of Subsection 5.2.6 addresses the ASME Code Cases for the ISI program:

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APR1400 DCD TIER 2

1. ASME Code Cases acceptable without limitations

- N-460, N-494-4, N-508-3, N-526, N-609, N-613-1, N-624, N-663, N-665, N-706-1, N-731, and N-753

2. ASME Code Cases acceptable with additional limitations

- N-416-4, N-504-4, N-593, N-597-2, N-639, and N-648-1 The above referenced ASME Code Cases are all approved for usage by Regulatory Guide (RG) 1.147 Rev. 17 and will be incorporated into the preservice and inservice inspection program of APR1400 at the construction stage.

ASME Code Case N-729-1 (Alternative Examination Requirements for PWR Reactor Vessel Upper Heads with Nozzles having Pressure-Retaining Partial-Penetration WeldsSection XI, Division 1) is also applied with additional limitation by 10 CFR 50.55a to the preservice and inservice inspection programs of APR1400. However, ASME Code Case N-722-1 (Additional Examinations for PWR Pressure Retaining Welds in Class 1 Components Fabricated with Alloy 600/82/182 Materials,Section XI, Division 1) is not applied to APR1400 because there are no reactor coolant pressure boundary parts fabricated with Alloy 600/82/182 materials.

5.2.4.1.9 Other Inspection Program The COL applicant is to prepare and implement a boric acid corrosion (BAC) prevention program in conformance with Generic Letter 88-05 (Reference 33) (COL 5.2(11)). The BAC program includes the selection of locations of degradation caused by small leakage, identification of small leakage locations, implementation methods of inspection and evaluation, and corrective action procedures for preventing recurrences of leakage.

To ensure easy access to the joint area or surface of components for boric acid corrosion examinations, the insulations covering the joint area or surface of components, where to be inspected, are designed to be removed easily or to keep sufficient gap between insulation and surface of reactor vessel closure head for the passage of inspection tool.

5.2.4.2 Preservice Inspection and Testing Program The preservice examination program is in accordance with the requirements of Article NB-5280 of ASME Section III, Division I. The preservice inspection (PSI) program 5.2-39 Rev. 2

APR1400 DCD TIER 2 conforms with the edition and addenda of ASME Section XI, as required by 10 CFR 50.55a(b) and 10 CFR 50.55a(g)(3). ASME Code Cases listed in NRC RG 1.147 that are incorporated by reference in 10 CFR 50.55a(b) are incorporated into the program as necessary.

The PSI program provides detailed information on areas subject to examination as well as methods, acceptance criteria, and extent of preservice examinations.

The COL applicant is to prepare the preservice inspection and testing program (COL 5.2(12)).

5.2.5 Reactor Coolant Pressure Boundary Leakage Detection The reactor coolant pressure boundary (RCPB) leakage detection systems provide a means for detecting and, to the extent practical, identifying the source of reactor coolant leakage and monitoring leaks from the reactor coolant and associated systems.

The RCPB leakage detection systems are designed in accordance with NRC RG 1.29 (Reference 34), Seismic Design Classification, to identify the seismic classifications for the leakage detection systems.

The RCPB leakage detection systems conform to the guidance of NRC RG 1.45 (Reference 35), Guidance on Monitoring and Responding to Reactor Coolant System Leakage, regarding the detection, monitoring, quantifying, and identification of reactor coolant leakage.

5.2.5.1 Leakage Detection Methods 5.2.5.1.1 Unidentified Leakage Indications of unidentified coolant leakage into the containment are provided by a containment sump level and flow monitor, an airborne particulate radioactivity monitor and an atmosphere humidity monitoring system.

In normal operation, these monitors show a background level that is indicative of the normal level of unidentified leakage inside the containment. Variations in airborne radioactivity or specific humidity above the normal level signify an increase in unidentified leakage rates and signal to the plant operators that corrective action may be required.

Similarly, increases in containment sump level signify an increase in unidentified leakage.

5.2-40 Rev. 2

APR1400 DCD TIER 2 The sensitivity and response time of leakage detection equipment for unidentified leakage is such that a change in leakage rate, or its equivalent, of 1.89 L/min (0.5 gpm) can be detected in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

The methods used to detect leakage to the containment from unidentified sources are:

a. Containment sump level

b. Containment airborne particulate radioactivity

c. Containment atmosphere humidity The humidity sensor is designed to indicate a sudden and significant increase of humidity level by annunciating an alarm in the MCR due to unidentified leakage.

Additionally, temperature and pressure monitoring of the containment atmosphere are used for alarms and indirect indication of leakage to the containment. They do not quantify the reactor coolant leakage.

5.2.5.1.1.1 Inventory Methods Total leakage from the RCS can be determined by net level changes in the pressurizer and volume control tank over a measured period since the RCS and the chemical and volume control system represent a closed-loop system. Since the letdown flow and the reactor coolant pump seal controlled bleed off flow are collected and recycled back into the RCS by the CVCS, the net inventory in the RCS and CVCS under normal operating conditions is constant. Transient changes in letdown flow rate or RCS inventory are accommodated by changes in the volume control tank level. By monitoring reactor drain tank and equipment drain tank level changes within a given test period, the identified RCS leakage value can be determined. Subtracting the identified leakage value from the total leakage value (corrected for any RCS contraction) results in the RCS unidentified leak rate.

Makeup flow rate also provides a means of detecting leakage from the RCS through measurement of the net amount of makeup flow to the system. The net makeup to the system under no-leakage steady-state conditions is zero. The net makeup flow rate and the total makeup flow rate from the CVCS are continuously monitored and recorded.

Analysis of the total makeup flow rate over a period of steady-state operation can determine the abnormal leakage. An increasing trend in the amount of required makeup indicates 5.2-41 Rev. 2

APR1400 DCD TIER 2 that the abnormal leakage exists and is increasing in rate. Sudden leakage induces a step increase in the amount of makeup, which does not decrease again. Sudden leakage would be the case in a purely transient condition.

5.2.5.1.1.2 Sump Level and Flow Method Unidentified liquid leakages are routed to the containment drain sump, or incore instrumentation (ICI) cavity sump. The containment drain sump collects unidentified leakage from the containment floor drain piping. The ICI cavity sump collects unidentified leakage in the reactor cavity. Sump levels are monitored in the MCR and alarmed on high level. Additionally, the amount of leakage is calculated using the frequency and length of time the sump pumps operate. This system is addressed in NRC RG 1.45.

A change in leak rate greater than or equal to 1.89 L/min (0.5 gpm) is detectable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, with an alarm actuating in the MCR to alert the operators, consistent with Regulatory Positions 2.2 and 3.3 of NRC RG 1.45.

The sump level monitoring system is qualified for a safe shutdown earthquake.

5.2.5.1.1.3 Containment Air Particulate Radioactivity Monitoring Two containment air radiation monitors are installed in parallel to measure the unidentified RCPB leakage, as described in Subsection 11.5.2.2 and listed in Table 11.5-1. One of the two containment air radiation monitors takes continuous containment air samples and measures the particulate. High radiation alarms are displayed in the MCR as shown in Figure 11.5-1. Leakage of reactor coolant has the effect of increasing radioactive particles in the containment, thus an increase of radiation level is an indication of leakage.

Radiological monitoring is addressed in more detail in Section 11.5.

The airborne particulate radiation monitors can detect a 1.89 L/min (0.5 gpm) leakage rate within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at full power operation. The sensitivity of the containment atmosphere radiation monitors is sufficient for detection of the limiting leakage.

The containment air radiation monitor is capable of functioning when subjected to a safe shutdown earthquake (SSE).

5.2-42 Rev. 2

APR1400 DCD TIER 2 5.2.5.1.1.4 Other Methods Consistent with NRC RG 1.45 Position 2.3, containment pressure, temperature, humidity monitoring, and an acoustic leak monitoring system (ALMS) are used as indirect indications of RCS leakage to the containment. Containment air pressure is continuously monitored and is indicated and alarmed in the main control room. The pressure is measured by independent pressure transmitters located at widely separated points within the containment. Refer to Section 7.5 for information on the display instrumentation associated with containment pressure. Temperature sensors are positioned at appropriate locations throughout the containment. Containment temperature is displayed in the MCR, along with high-temperature alarms. Finally, containment humidity sensors are also provided in the MCR with displays and high alarms.

The ALMS is described in Subsection 7.7.1.5. The ALMS monitors changes in acoustic levels above a normal background with no leakage. There are 19 locations selected based on the criticality of the component or region and in some cases where leakage has occurred.

The indication is qualitative; it alerts operators to investigate and compare with other leakage monitoring methods.

5.2.5.1.2 Identified Leakage Identified leakage is defined in accordance with the guidance of NRC RG 1.45 as follows:

(1) leakage (such as pump seal or valve packing leakage) that is captured, flow-metered, and conducted to a sump, collecting tank, or collection system and (2) leakage into the containment atmosphere from a known source, which does not interfere with the operation of unidentified leakage monitoring systems and is not attributable to leakage in the RCPB.

The amount of identified leakage from the RCS can be determined by adding up the amounts from all identified paths described below. Indication and alarms associated with all of the identified leakage paths are provided in the MCR.

5.2.5.1.2.1 Pressurizer Pilot-Operated Safety Relief Valves The pressurizer POSRVs, located at the top of the pressurizer, are routed to the IRWST.

Valve leakage is monitored by resistance temperature detectors (RTDs) located on the discharge lines of each pressurizer POSRV and pilot valves. An abnormally high temperature in the discharge lines of the pressurizer POSRV and the pilot valves is an 5.2-43 Rev. 2

APR1400 DCD TIER 2 indication of valve leakage. A high temperature due to leakage is alarmed in the MCR.

Position indication for each pressurizer POSRV is also provided in the MCR.

5.2.5.1.2.2 Reactor Coolant Pump Seals Instrumentation is provided to detect abnormal seal leakage. The reactor coolant pumps are equipped with two-stage seals plus a vapor or backup seal as described in Subsection 5.4.1.2. During normal operation, the RCS pressure is decreased through the two seals to controlled bleed-off pressure.

The vapor or backup seal prevents leakage to the containment atmosphere and operates at sufficient pressure to direct the controlled bleed off to the volume control tank (VCT).

The vapor or backup seal is designed to withstand the full RCS pressure in the event the two primary seals fail. The vapor seal pressure indicator would show a decrease in pressure upon a significant leak into the containment across the vapor seal and an increased level in the reactor drain tank (RDT) would be indicated. Seal leakage through the tubes of the reactor coolant pump seal coolers to the component cooling water system (CCWS) would be indicated by an increase in temperature of the component cooling water return line from the reactor coolant pumps, by an increased water level in component cooling water surge tanks, and by increased radiation monitor readings in the CCWS.

5.2.5.1.2.3 Valves Valves inside the containment that isolate the RCS from connecting systems during normal operation are equipped with stem leakoffs at the stem packing. These leakoffs are connected by piping to the RDT. Valves in the charging and letdown system inside the containment are equipped with stem leakoffs.

5.2.5.1.2.4 Reactor Vessel Head Flange Leakage Leakage between the two metal O-rings that seal the reactor vessel head flange is routed through a leakoff line to the RDT. A normally closed, remotely activated isolation valve and a pressure indicator are installed in the leakoff line. Leakage from the reactor vessel head flange will cause pressure in this leakoff line to rise. The pressure in the leakoff line is continuously monitored to detect the presence of a leak. Any leakage is bled off to the RDT by opening the isolation valve.

5.2-44 Rev. 2

APR1400 DCD TIER 2 5.2.5.1.2.5 Leakage through Steam Generator Tubes or Tubesheet N-16 radiation monitors are installed on each main steam line to reveal reactor coolant leakage through the steam generator tubes to the secondary side. An increase in radioactivity, as indicated by the condenser vacuum vent effluent monitor, and steam generator blowdown monitors will reveal reactor coolant leakage through steam generator tubes to the secondary side. Routine analysis of steam generator secondary water samples will also indicate leakage of reactor coolant into the secondary system. Appendix 11B describes in detail the methods used for primary-to-secondary leakage detection.

5.2.5.1.2.6 Leakage to Auxiliary Systems Chapter 11 describes the design basis for process monitors used in all potentially contaminated auxiliary systems and their sensitivity.

5.2.5.2 Leakage Instrumentation in the Main Control Room 5.2.5.2.1 Pilot-Operated Safety Relief Valve Indication of POSRV leakage is provided by the temperature instruments mounted on the POSRV discharge pipes and drain lines. The signal from the temperature sensor is continuously monitored and provides an alarm in the main control room via the information processing system (IPS) and qualified indication and alarm system (QIAS) displays.

5.2.5.2.2 Primary Indicators of Reactor Coolant Unidentified Leakage The MCR indication of leakage from the RCS to the containment building is provided by indications and alarms. The primary indications of reactor coolant leakage are:

a. Containment air radiation indications as well as alarms that are initiated by abnormally high air particulate and radioactive gas levels in the containment atmosphere

b. Pumped flow from containment drain sump tank and reactor cavity sump

c. Levels of containment drain sump and reactor cavity sump

d. Acoustic leakage monitoring 5.2-45 Rev. 2

APR1400 DCD TIER 2 5.2.5.2.3 Other Indicators of Reactor Coolant Leakage Other main control room instrumentation that may indicate significant reactor coolant leakage includes:

a. Pressurizer level

b. Containment pressure, temperature, and humidity

c. Condenser vacuum vent radiation

d. Steam generator blowdown radiation

e. CVCS makeup system flow

f. Component cooling water radiation

g. RDT level, temperature, and pressure

h. Equipment drain tank pressure, temperature and level

i. VCT level

j. Reactor vessel O-ring leak-off pressure

k. Safety injection tank pressure and level

l. Safety injection line pressure

m. Pressurizer POSRV discharge temperature

n. Pressurizer POSRV position

o. Reactor coolant gas vent system pressure and temperature

p. Main steam line N-16 5.2.5.2.4 Leakage Conversion to Equivalent Procedures for converting the instrument output to a leakage rate, in accordance with NRC RG 1.45, are available to the operators as described in the following subsections.

5.2-46 Rev. 2

APR1400 DCD TIER 2 5.2.5.2.4.1 Containment Radioactive Air Particulate Monitoring Upon actuation of a high activity alarm, the operator or computer performs the appropriate action. It may not be appropriate to estimate the RCS activity level based on particulate activity because the radioactivity value could vary as a result of operating conditions.

Therefore, when the high-radiation alarms are occurred or the indication values have increased, a RCS inventory balance is performed and the quantitative measurement of the coolant unidentified leakage is performed. The measurement methods are described in Subsections 5.2.5.1.1.3.

5.2.5.2.4.2 Leakage to Containment Sumps A computer is programmed to calculate leakage rates from the rate of change of sump level.

Digital readouts are available to the operator.

A computer is also programmed to calculate leakage rates utilizing the frequency and interval of time the sump pumps operate in combination with the known pumping rate of the pumps. Digital readouts are available to the operator.

5.2.5.3 Maximum Allowable Total Leakage The maximum allowable identified and unidentified leakage and the required instrument availability to detect leakage are stated in the Technical Specifications (Chapter 16).

5.2.5.4 Intersystem Leakage 5.2.5.4.1 Safety Injection System The SIS is isolated from the RCS during normal operation. Leakage from the RCS to the SIS under normal operation is detected by SIS pressure increases and alarmed. For example, leakage into the safety injection tanks (SITs) by the two check valves isolating the tanks from the RCS is detected by an increase in pressure between the check valves. This pressure is indicated and alarmed in the MCR. Secondarily, the SIT level increases. The leakage rate is computed from the rate of change of the level.

5.2.5.4.2 Steam Generator Leakage The detection of leakage across the steam generator boundary between the primary to secondary side is addressed in Subsection 5.2.5.1.2.5. Leakage across this boundary 5.2-47 Rev. 2

APR1400 DCD TIER 2 would be quantified, after the indication of radioactivity in the N-16 radiation monitors and the condenser vacuum vent effluent radiation monitor, by performing an RCS inventory balance. If the amount of leakage is small, chemical and radioisotope analyses of both the primary and secondary sides may be necessary to determine the leakage rate. Appendix 11B describes the methods that are used to detect primary-to-secondary leakage.

5.2.5.4.3 Shutdown Cooling System The SCS is a closed system. Leakage from the RCS to SCS under normal operation, when the system is isolated from the RCS, would be detected by relief valve discharges.

5.2.5.4.4 Component Cooling Water System The CCWS cools the reactor coolant pumps (RCPs), the SCS heat exchanger, the letdown heat exchanger, and the containment spray pump and SCS pump miniflow heat exchangers.

Leakage from the RCS to the CCWS is detected by the CCW radiation monitors and/or the CCW surge tank level. The change in surge tank level is utilized to quantify any leakage.

5.2.5.4.5 Chemical and Volume Control System The chemical and volume control system (CVCS) is connected to the RCS through the letdown line, charging line, RCP seal injection line, RCP controlled bleedoff line, and the line to RDT. The letdown line, charging line, RCP seal injection line, and RCP controlled bleedoff line are directly connected to the RCS. The design pressure of the line directly connected to the RCS is not less than the RCS design pressure. Leakage from the RCS to the CVCS, when the system is isolated from the RCS, can be detected by the pressure instruments installed in low pressure letdown line and charging pump suction line. The pressure instruments provide the indication and the high pressure alarm in the main control room. Leakage from the RCS to the RDT can be detected by the pressure and level change of the RDT. In addition, when the RCP controlled bleedoff line is isolated, leakage can also be detected by the pressure and level change of the VCT and RDT.

The CVCS is connected to the SCS through the shutdown cooling purification line.

During normal operation, the shutdown cooling purification line is isolated by the isolation valves and check valves. Leakage from the CVCS to the SCS would be detected by relief valve discharges. The relief valve discharges will change the pressure or level of the equipment drain tank (EDT) or RDT.

5.2-48 Rev. 2

APR1400 DCD TIER 2 5.2.5.5 Sensitivity and Response Time For unidentified leakage, the leakage detecting system is designed to detect a minimum of 1.89 L/min (0.5 gpm) in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The sensitivity and response times meet Regulatory Positions 2.1 and 2.2 of NRC RG 1.45.

5.2.5.6 Operability Testing and Calibration Leakage monitoring systems have provisions to permit calibration and testing during plant operation, as appropriate. Periodic testing of leakage detection systems is conducted to verify the operability and sensitivity of detection equipment. These tests include installation calibrations and alignments, periodic channel calibrations, functional tests, and channel checks.

Periodic inspection of the floor drainage system to the containment sump is conducted to check for blockage and provide reasonable assurance of unobstructed pathways.

The containment humidity monitoring is also tested periodically to provide reasonable assurance of proper operation and verify sensitivity.

An inservice inspection (ISI) program for the examination of RCPB components and supports to periodically monitor the systems or components is described in Subsection 5.2.4.

5.2.5.7 Limits for Reactor Coolant Leakage Rates within the RCPB The limiting conditions for identified, unidentified, RCPB, and intersystem reactor coolant leakages are identified in the Technical Specifications (Chapter 16). Subsections 3.4.12 and 3.4.13 of the Technical Specifications address RCS operational leakage and RCS pressure isolation valve, respectively. Subsection 3.4.14 addresses RCS leakage detection instrument requirements. The COL applicant is to address and develop the milestones for the preparation and implementation of the procedure for operator responses to prolonged low-level leakage (COL 5.2(13)).

5.2.6 Combined License Information COL 5.2(1) The COL applicant is to address the addition of ASME Code Cases that are approved in NRC RG 1.84 at the time of the application.

5.2-49 Rev. 2

APR1400 DCD TIER 2 COL 5.2(2) The COL applicant is to address the ASME Code Cases approved in NRC RG 1.147 at the time of the application and invoked for the ISI program of a specific plant.

COL 5.2(3) The COL applicant is to address the ASME Code Cases approved in NRC RG 1.192 at the time of the application and invoked for operation and maintenance activities of a specific plant.

COL 5.2(4) The COL applicant is to address the material specifications, which are not shown in Table 5.2-2, as necessary.

COL 5.2(5) The COL applicant will review and confirm at the time of COL submittal based on the latest revision of EPRI PWR Primary Side Water Chemistry Guidelines.

COL 5.2(6) The COL applicant is to address the actual, as-procured, fracture toughness data of the RCPB materials to the staff at a predetermined time by an appropriate method.

COL 5.2(7) The COL applicant is to submit the actual, as-procured yield strength of the austenitic stainless steel materials used in RCPB to the staff at a predetermined time agreed-upon by the regulatory body.

COL 5.2(8) The COL applicant is to provide and develop the implementation milestones for the inservice inspection and testing program for the RCPB, in accordance with ASME Section XI and 10 CFR 50.55a.

COL 5.2(9) The COL applicant is to address the provisions to accessibility of Class 1 components for ISI if the design of the APR1400 Class 1 component is changed from the DCD design.

COL 5.2(10) The COL applicant is to provide the list of Code exemptions in the ISI program of the specific plants, if it exists.

COL 5.2(11) The COL applicant is to prepare and implement a boric acid corrosion (BAC) prevention program in conformance with Generic Letter 88-05.

COL 5.2(12) The COL applicant is to prepare the preservice inspection and testing program.

5.2-50 Rev. 2

APR1400 DCD TIER 2 COL 5.2(13) The COL applicant is to address and develop the milestones for the preparation and implementation of the procedure for operator responses to prolonged low-level leakage.

COL 5.2(14) The COL applicant is to address the portions of the later editions and addenda of ASME Code.

5.2.7 References

1. 10 CFR 50.2, Definitions, U.S. Nuclear Regulatory Commission.

2. ASME Boiler and Pressure Vessel Code,Section III, Rules for Construction of Nuclear Facility Components, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

3. 10 CFR 50.55a, Codes and Standards, U.S. Nuclear Regulatory Commission.

4. Regulatory Guide 1.26, Quality Group Classification and Standards for Water-,

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants, Rev. 4, U.S. Nuclear Regulatory Commission, March 2007.

5. 10 CFR Part 50, Appendix A, General Design Criteria for Nuclear Power Plants, U.S.

Nuclear Regulatory Commission.

6. ASME Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

7. ASME Boiler and Pressure Vessel Code, OM Code, Code for Operation and Maintenance of Nuclear Power Plants, The American Society of Mechanical Engineers, the 2004 Edition with the 2005 and the 2006 Addenda.

8. 10 CFR 52.47, Contents of Applications; technical information, U.S. Nuclear Regulatory Commission.

9. Regulatory Guide 1.84, Design, Fabrication and Materials Code Case Acceptability, ASME Section III, Rev. 36, U.S. Nuclear Regulatory Commission, August 2014.

5.2-51 Rev. 2

APR1400 DCD TIER 2

10. Regulatory Guide 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1, Rev. 17, U.S. Nuclear Regulatory Commission, August 2014.

11. Regulatory Guide 1.192, Operation and Maintenance Code Case Acceptability, ASME OM Code, Rev. 1, U.S. Nuclear Regulatory Commission, August 2014.

12. NUREG-0800, Standard Review Plan, BTP 5-2, Overpressurization Protection of Pressurized - Water Reactors while Operating at Low Temperatures, Rev. 3, U.S.

Nuclear Regulatory Commission, March 2007.

13. APR1400-Z-M-NR-14008-P, Pressure-Temperature Limits Methodology for RCS Heatup and Cooldown, Rev. 1, KHNP, January 2018.

14. DST Computer Service SA, A nuclear and non-nuclear piping analysis program, PIPESTRESS Version 3.7.0, Geneva, Switzerland, 2012.

15. NUREG/CR-5535, RELAP5/MOD3.3 Code Manual, Rev. 3, U.S. Nuclear Regulatory Commission, March 2006.

16. ASME Boiler and Pressure Vessel Code,Section II, Materials, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

17. Regulatory Guide 1.99, Radiation Embrittlement of Reactor Vessel Materials, Rev. 2, U.S. Nuclear Regulatory Commission, May 1988.

18. 10 CFR Part 50, Appendix G, Fracture Toughness Requirements, U.S. Nuclear Regulatory Commission.

19. EPRI 3002000505, Pressurized Water Reactor Primary Water Chemistry Guidelines, Rev. 7, Electric Power Research Institute, April 2014.

20. Regulatory Guide 1.44, Control of the Processing and Use of Stainless Steel, Rev. 1, U.S. Nuclear Regulatory Commission, March 2011.

21. Regulatory Guide 1.36, Nonmetallic Thermal Insulation for Austenitic Stainless Steel, Rev. 0, U.S. Nuclear Regulatory Commission, February 1973.

22. NUREG-0800, Standard Review Plan, BTP 5-3, Fracture Toughness Requirements, Rev. 2, U.S. Nuclear Regulatory Commission, March 2007.

5.2-52 Rev. 2

APR1400 DCD TIER 2

23. Regulatory Guide 1.50, Control of Preheat Temperature for Welding of Low-Alloy Steel, Rev. 1, U.S. Nuclear Regulatory Commission, March 2011.

24. ASME Section III, Appendix D, Nonmandatory Preheat Procedures, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

25. Regulatory Guide 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components, Rev. 1, U.S. Nuclear Regulatory Commission, March 2011.

26. Regulatory Guide 1.34, Control of Electroslag Weld Properties, Rev. 1, U.S. Nuclear Regulatory Commission, March 2011.

27. Regulatory Guide 1.71, Welder Qualification for Area of Limited Accessibility, Rev. 1, U.S. Nuclear Regulatory Commission, March 2007.

28. ASTM A 262, Standard Practices for Detecting Susceptibility to Intergranular Attack in Austenitic Stainless Steels, American Society for Testing and Materials, 2010.

29. Regulatory Guide 1.28, Quality Assurance Program Criteria (Design and Construction), Rev. 4, U.S. Nuclear Regulatory Commission, June 2010.

30. Regulatory Guide 1.31, Control of Ferrite Content in Stainless Steel Weld Metal, Rev. 4, U.S. Nuclear Regulatory Commission, October 2013.

31. EPRI Report MRP-111, Resistance to Primary Water Stress Corrosion Cracking of Alloys 690, 52, and 152 in Pressurized Water Reactors, March 2004.

32. Regulatory Guide 1.65, Materials and Inspections for Reactor Vessel Closure Studs, Rev. 1, U.S. Nuclear Regulatory Commission, April 2010.

33. Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants, U.S. Nuclear Regulatory Commission, March 17, 1988.

34. Regulatory Guide 1.29, Seismic Design Classification, Rev. 4, U.S. Nuclear Regulatory Commission, March 2007.

35. Regulatory Guide 1.45, Guidance on Monitoring and Responding to Reactor Coolant System Leakage, Rev. 1, U.S. Nuclear Regulatory Commission, May 2008.

5.2-53 Rev. 2

APR1400 DCD TIER 2

36. ASME Boiler and Pressure Vessel Code,Section V, Nondestructive Examination, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

37. ASME Boiler and Pressure Vessel Code,Section IX, Welding and Brazing Qualifications, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

38. APR1400-Z-A-NR-14020-P, Pressurizer Sizing and Overpressure Protection Evaluation, Rev. 0, KEPCO & KHNP, January 2018.

5.2-54 Rev. 2

APR1400 DCD TIER 2 Table 5.2-1 Reactor Coolant System Pressure Boundary Code Requirements (1), (2)

Components Codes Classes RV, steam generators (primary side), ASME Section III, NB 1 pressurizer RCP (structural portions necessary to ASME Section III, NB 1 provide reasonable assurance of the integrity of the RCPB)

RCP (high pressure cooler - cooling water ASME Section III, ND 3 side)

Pipe and valves ASME Section III, NB/NC 1/2 Pressurizer spray and pilot-operated safety ASME Section III, NB 1 relief valves Steam generators (secondary side) ASME Section III, NC 2 Control element drive mechanisms ASME Section III, NB 1 (CEDMs)

(1) The codes listed in this table are construction codes.

The ASME Code of 2007 Edition with 2008 Addenda is applicable to the APR1400 for construction.

Construction and welding of structures, systems, and components is in accordance with ASME Code,Section III. Inspections of structures, systems, and components constructed in accordance with ASME Section III are in accordance with ASME Code,Section V (Reference 36). Qualification of Welding Procedures and Welding Operators is in accordance with ASME Code,Section IX (Reference 37).

Specifications for construction base materials and welding materials are in accordance with ASME Code,Section II. In addition, the components listed in this table are designed and constructed to meet the test and inspection requirements of the ASME OM, 2004 Edition with 2005 and 2006 Addenda, and ASME Section XI, Rules for Inservice Inspection, 2007 Edition with 2008 Addenda.

(2) The COL applicant is to address the portions of the later editions and addenda of ASME Code (COL 5.2(14)).

5.2-55 Rev. 2

APR1400 DCD TIER 2 Table 5.2-2 (1 of 6)

Reactor Coolant System Materials and Weld Materials Component Material Specification Reactor Vessel Forgings SA-508 Grade 3 Class 1 (1)

Cladding Weld deposited austenitic stainless steel with 5FN- 18FN delta ferrite or NiCrFe alloy Direct vessel injection (DVI) SA-182 Grade F316 or F316LN nozzle safe ends (1)

RV head (1), (3) CEDM NiCrFe Alloy 690 (SB-166) nozzles Vessel internals (1) Austenitic stainless steel and NiCrFe alloy Flow skirt (1), (3) NiCrFe Alloy 690 (SB-168)

(1)

Fuel cladding ZIRLO (1), (3)

Instrument nozzles NiCrFe Alloy 690 (SB-166)

Closure head studs SA-540 Grade B24 Class 3 Control Element Drive Mechanism Housings Lower (1) Type 403 stainless steel according to Code Case N-4-13 with end fittings to be SB-166 (N06690) (3) and SA-182 Grade F347/F348 stainless steel Upper (1) SA-479 and SA-213 Type 316 stainless steel with end fitting of SA-479 Type 316 and vent valve ball seal of Type 440C stainless steel Pressurizer Shell SA-533 Type B Class 1 or SA-508 Grade 3 Class 1 Cladding (1) Weld-deposited austenitic stainless steel with 5 FN-18FN delta ferrite or NiCrFe alloy Forged nozzles SA-508 Grade 3 Class 1 Instrument nozzles and NiCrFe Alloy 690 (SB-166, SB-167 or SB-168) heater sleeves (1), (3)

Nozzle safe ends (1) SA-182 Grade F316, F316LN, F316N or F347 Studs and nuts SB-637 N07718 5.2-56 Rev. 2

APR1400 DCD TIER 2 Table 5.2-2 (2 of 6)

Component Material Specification Steam Generator Primary head SA-533 Type B Class 1 or SA-508 Grade 3 Class 1 Primary nozzles SA-508 Grade 3 Class 1 (1)

Primary head cladding Weld deposited austenitic stainless steel with 5FN-18FN delta ferrite or NiCrFe alloy Tubesheet SA-508 Grade 3 Class 1 or Class 2 (1)

Divider Plate SA-240 Type 410S Tubesheet stay SA-508 Grade 3 Class 1 or Class 2 Tubesheet cladding (1) SFA-5.11 [ENiCrFe-7] and SFA-5.14 [ERNiCrFe-7(A),

EQNiCrFe-7(A)]

Tube (1), (3) NiCrFe Alloy 690 (SB-163)

Tube supports ASTM A240, Type 409 Secondary shell (4) SA-533 Type B Class 1 or SA-508 Grade 3 Class 1 Secondary head (4) SA-508 Grade 1, Grade 1a or Grade 3 Class 1, or SA-533 Type B Class 1 Secondary nozzles (4) SA-508 Grade 1, Grade 1a, Grade 3 Class 1 or Grade 3 Class 2 Secondary nozzle safe ends SA-508 Grade 1 or 1a (4)

Secondary instrument SA-106 Grade B, SA-333 Grade 6 nozzles (4)

Secondary studs and nuts SA-540 Grade B24, or SA-193 Grade B7 Primary studs and nuts SB-637 N07718 Reactor Coolant Pumps Casing SA-508 Grade 3 Class 1 and clad with austenitic stainless steel Cladding (1) Weld-deposited austenitic stainless steel with 5FN-18FN delta ferrite Internals (1) SA-487 CA6MN, SA-965 F304, F304LN, F347, or austenitic stainless steel Shaft (1) SA-182 Grade F6NM 5.2-57 Rev. 2

APR1400 DCD TIER 2 Table 5.2-2 (3 of 6)

Component Material Specification Reactor Coolant Piping Pipe (30 in and 42 in ID) SA-516 Grade 70 or SA-508 Grade 1 or Grade 1a Cladding (1) Weld-deposited austenitic stainless steel with 5FN-18FN delta ferrite Piping Nozzles and Safe Ends Nozzle forgings SA-508 Grade 1, Grade 1a, or Grade 3 Class 1 (1), (3)

Instrument nozzles NiCrFe Alloy 690 (SB-166)

Nozzle safe ends (1) SA-182 Grade F316, F316N, F316LN, F347, or NiCrFe Alloy 690 (SB-166)

Motor Operated Valve (1), and Pneumatic Operated Valve (1), Manual Valve (1), Check Valve (1),

Solenoid Valve (1)

Bodies SA-351 CF3, CF3A, CF3M, CF8, CF8A CF8M SA-182 Gr.F304, F304L, F304LN Gr.F316, F316L, F316LN Bonnets/Cover SA-351 CF3, CF3A, CF3M, CF8, CF8M SA-240 Type 304, 304L, 304LN Type 316, 316L, 316LN SA-182 Gr.F304, F304L, F304LN Gr.F316, F316L, F316LN Disks SA-564 Type 630 SA-479 Type 304, 304l, 304LN Type 316, 316L, 316LN SA-351 CF3, CF3A, CF3M, CF8, CF8M SA-182 Gr.F304, F304L, F304LN Gr.F316, F316L, F316LN SB-637 UNS N07718 Stems SA-564 Type 630 SA-479 Type 304, 304l, 304LN Type 316, 316L, 316LN SB-637 UNS N07718 5.2-58 Rev. 2

APR1400 DCD TIER 2 Table 5.2-2 (4 of 6)

Component Material Specification Closure Stud Bolts SA-453 Gr.660 SA-193 Gr.B7, B16, Gr.B8, SA-564 Type 630 Closure Nuts SA-453 Gr.660 SA-194 Gr.6 , Gr.8, Gr. 8M Relief Valve (1)

Base SA-479 Type 316L Cylinder SA-351 CF3, CF3M, CF8, CF8M Lap Joint Stub End/Lab Joint SA-479 Type 316L Flange Disc Insert SA-479 Type 316L Spindle SA-479 Type 316L Spring Ni base alloy Alloy X-750 Spring Washer/Adjust Bolt SA-479 Type 316L Surge line (1) SA-312 TP347 or TP316N (piping)

SA-403 WP347 or WP316N (elbows)

DVI and shutdown lines SA-312 TP316 or TP304 inside containment Other RCS Piping (1)

PZR spray lines including SA-312 Grade TP316 auxiliary spray line RCS drain lines SA-312 Grade TP316 RCGVS lines SA-312 Grade TP316 Sampling lines SA-312 Grade TP316, SA-213 Grade TP316 RCP CBO lines SA-312 Grade TP304 Charging and letdown lines SA-312 Grade TP316 or TP304 5.2-59 Rev. 2

APR1400 DCD TIER 2 Table 5.2-2 (5 of 6)

Base Base Material Material Type (5) Type (5) Type of Weld Material Example of Use Weld Materials for Reactor Coolant Pressure Boundary Components P-1 P-1 a. SFA 5.1 E-7018, E-7016 Primary piping straight to primary

b. SFA 5.18 ER70S-6 piping elbows

c. SFA 5.23, EA-3(N)

P-1 P-3 a. SFA 5.1 E-7018, E-7016 Primary piping straight to the RV

b. SFA 5.5 E-8018-C3, primary nozzle E-8018-G, E-8016-G

c. SFA 5.23 EA3(N)

d. SFA 5.18 ER70S-6 P-1 P-8 a. NiCrFe filler metal Primary piping surge nozzle to (SFA 5.11 ENiCrFe-7, surge nozzle safe end SFA 5.14 ERNiCrFe-7(A))

b. SFA 5.4 E309L-16

c. SFA 5.9 ER309L P-1 P-43 a. NiCrFe filler metal Buttering (NiCrFe filler metal) of (SFA 5.11 ENiCrFe-7, J-grooves in hot leg pipe SFA 5.14 ERNiCrFe-7(A))

P-3 P-3 a. SFA 5.5 (2) E-8016-C3, RV upper shell to RV flange E-8018-G, E-8016-G

b. SFA 5.23 EA3(N) (2)

P-3 P-8 a. NiCrFe filler metal POSRV nozzle to POSRV safe (SFA 5.11 ENiCrFe-7, end SFA 5.14 ERNiCrFe-7(A))

b. SFA 5.4 E309L-16

c. SFA 5.9 ER309L P-3 P-43 a. NiCrFe filler metal Buttering (NiCrFe filler metal) of (SFA 5.11 ENiCrFe-7, J-grooves in RV closure head SFA 5.14 ERNiCrFe-7(A))

P-8 P-8 a. SFA 5.4 E308, E308L, Surge line piping to surge line E308L-16, E309, E309L- elbows 16, E316, E347

b. SFA 5.9 ER308, ER308L, ER309, ER309L, ER316, ER347 5.2-60 Rev. 2

APR1400 DCD TIER 2 Table 5.2-2 (6 of 6)

Base Base Material Material Example Type (5) Type (5) Type of Weld Material of Use Weld Materials for Reactor Coolant Pressure Boundary Components (cont.)

P-8 P-43 a. NiCrFe filler metal Pressurizer instrument nozzles to (SFA 5.11 ENiCrFe-7, pressurizer instrument nozzle SFA 5.14 ERNiCrFe-7(A)) safe ends P-43 P-43 a. NiCrFe filler metal RV CEDM nozzles to J-groove (SFA 5.11 ENiCrFe-7, buttering (NiCrFe filler metal)

SFA 5.14 ERNiCrFe-7(A))

Stainless steel cladding (1) a. SFA 5.4 E308, E308L, -

E308L-16, E309, E309L, E309L-16

b. SFA 5.9 ER308, ER308L, ER 309, ER309L

c. SFA 5.22 E308LT1-1, E309LT1-1 Nickel alloy cladding (1) a. NiCrFe filler metal -

(SFA 5.11 ENiCrFe-7, SFA 5.14 ERNiCrFe-7(A))

(1) Materials exposed to reactor coolant (2) Special weld wire with low residual elements of copper, nickel and phosphorous as specified when used in the RV core beltline region (3) Material to be provided in the thermally treated condition (4) SG secondary side pressure boundary materials including weld materials contain no greater than 0.010 wt% of sulfur (S)

(5) P-number designations are per the ASME Section IX, Table QW-422 5.2-61 Rev. 2

APR1400 DCD TIER 2 Table 5.2-3 SCS Suction Line Relief Valves (SI-179 and SI-189) Design Parameters Parameter Value Design pressure, kg/cm2G (psig) 63.3 (900)

Design temperature, °C (°F) 204.4 (400)

Fluid Reactor coolant 2

Nominal setpoint, kg/cm G (psig) 37.3 (530) (1)

Accumulation 10 %

Capacity, L/min (gpm) 29,337 (7,750)

(@ 10 % accumulation)

Inlet line size, cm (in) 20.3 (8)

Outlet line size, cm (in) 25.4 (10)

(1) Pressure measured at the valve inlet 5.2-62 Rev. 2

APR1400 DCD TIER 2 Table 5.2-4 ASME Section III Code Cases Code Case Title N-4-13 Special Type 403 Modified Forgings or Bars,Section III, Division 1, Class 1 and CS N-60-5 (1), (2) Materials for Core Support Structures,Section III, Division 1 N-71-18 (1), (3) Additional Materials for Subsection NF, Classes 1, 2, 3, and MC Component Supports Fabricated by Welding,Section III, Division 1 N-249-14 (1), (4) Additional Materials for Subsection NF, Class 1, 2, 3, and MC Component Supports Fabricated without Welding,Section III, Division 1 N-759-2 Alternative Rules for Determining Allowable External Pressure and Comprehensive Stress for Cylinders, Cones, Spheres, and Formed Heads,Section III, Division 1 (1) The conditions as stated in NRC RG 1.84 will be used for the conditionally accepted Code Cases.

(2) SA-193 Grade B8M Cl.2 for Reactor vessel internals (3) ASTM A 588 Grade A for Integrated head assembly (IHA)

ASTM A 148 Grade 90/60 for Support skirt on reactor coolant pump, Upper support bracket of steam generator support, and Clevis of reactor coolant pump support ASTM A 500 Grade B for Pipe supports in contact with the piping which is not RCPB ASTM A 514 Grade E or Q for Base sliding support of steam generator ASTM A 572 Grade 50 for Lateral support of reactor vessel (4) AISI 4340 for Steam generator support 5.2-63 Rev. 2

APR1400 DCD TIER 2 Table 5.2-5 Reactor Coolant Preoperation Operating Specifications (1), (5)

Analysis Preoperation pH @ 25 ºC (77 ºF) 4.2-10.7 Chloride, ppm 0.15 Fluoride, ppm 0.15 Dissolved oxygen, ppm 0.1 (2)

Boron, ppm 4,400 Ammonia, ppm (3) 50 Suspended solids, ppm (4) 0.35 2 ppm max. (4)

Sulfate, ppm 0.15 (1) The parameters and values are subject to change based on technical evaluation as the water chemistry technology is developed.

(2) This applies when reactor coolant temperature is greater than 121.1 ºC (250 ºF).

(3) This parameter is used for problem diagnosis.

(4) The abnormal condition of 0.35 to 2.0 ppm is permitted for up to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> to allow for crud burst conditions.

(5) This is a typical specification. The COL applicant will review and confirm at the time of COL submittal based on the latest revision of EPRI PWR Primary Side Water Chemistry Guidelines (COL 5.2(5)).

5.2-64 Rev. 2

APR1400 DCD TIER 2 Table 5.2-6 Reactor Coolant Plant Shutdown Operating Specifications (1), (5)

Plant Shutdown Analysis (including Refueling)

Chloride, ppm 0.15 Fluoride, ppm 0.15 Boron, ppm 4,400 Ammonia, ppm (2) 2.0 Hydrogen, cc (STP)/kg H2O < 5 (3)

Suspended solids, ppm (4) 0.35 Sulfate, ppm 0.15 (1) The parameters and values are subject to change based on technical evaluation as the water chemistry technology is developed.

(2) This parameter is used for problem diagnosis.

(3) Hydrogen should be less than 5 cc (STP)/kg (H2O) prior to cold shutdown .

(4) The abnormal condition of 0.35 to 2.0 ppm is permitted for up to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> to allow for crud burst conditions.

(5) This is a typical specification. The COL applicant will review and confirm at the time of COL submittal based on the latest revision of EPRI PWR Primary Side Water Chemistry Guidelines (COL 5.2(5)).

5.2-65 Rev. 2

APR1400 DCD TIER 2 Table 5.2-7 Reactor Coolant Detailed Plant Startup Operation Specifications (1), (6)

Range Action Level Analysis Normal 1 2 3 pH @ 25 ºC (77 ºF) 4.6 - 7.3 - < 4.6, > 7.3 -

Hydrazine, ppm 1.5 x O2 ppm - - -

(max. 20 ppm)

Ammonia, ppm (2) 2.0 - - -

Lithium, ppm 0.2 - 3.5 - - -

Hydrogen, cc (STP)/kg H2O 15 - 25 - - -

(5) (3)

Dissolved oxygen, ppm 0.1 - > 0.1 > 1.0 Suspended solids, ppm 0.35 (4) - - -

Chloride, ppm (5) 0.15 - > 0.15 > 1.5 Fluoride, ppm (5) 0.15 - > 0.15 > 1.5 Boron, ppm 2,500 - - -

Sulfate, ppm (5) 0.15 - > 0.15 > 1.5 (1) The parameters and values are subject to change based on technical evaluation as the water chemistry technology is developed.

(2) This parameter is used for problem diagnosis.

(3) This dissolved oxygen concentration is applicable when reactor coolant temperature is 121.1 ºC (250 ºF). Hydrazine is added if O2 > 0.1 ppm prior to increasing primary coolant temperature. The dissolved specification is set at 0.1 ppm based on stress corrosion cracking concerns.

(4) The abnormal condition of 0.35 to 2.0 ppm is permitted for up to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> to allow for curd burst conditions.

(5) Sampling frequency should be at least once in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

(6) This is a typical specification. The COL applicant will review and confirm at the time of COL submittal based on the latest revision of EPRI PWR Primary Side Water Chemistry Guidelines (COL 5.2(5)).

5.2-66 Rev. 2

APR1400 DCD TIER 2 Table 5.2-8 Reactor Coolant Detailed Power Operation Specifications (1), (5)

Range Action Level Analysis Normal 1 2 3 pH @25 ºC (77 ºF) 6.0 - 7.3 - < 6.0, > 7.3 -

(2) (2) (2) (2)

Conductivity, S/cm Lithium, ppm 0.2 - 3.5 - - -

Hydrogen, cc (STP)/kg H2O 25 - 50 < 25, > 50 15 5 Dissolved oxygen, ppm (4) 0.005 > 0.005 > 0.1 > 1.0 Chloride, ppm (4) 0.05 > 0.05 > 0.15 > 1.5 (4)

Fluoride, ppm 0.05 > 0.05 > 0.15 > 1.5 Boron, ppm 2,500 - - -

(4)

Sulfate, ppm 0.05 > 0.05 > 0.15 > 1.5 (1) The parameters and values are subject to change based on technical evaluation as the water chemistry technology is developed.

(2) Consistent with pH additive concentrations.

(3) Consistent with plant lithium management program.

(4) Sampling frequency should be at least once in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

(5) This is a typical specification. The COL applicant will review and confirm at the time of COL submittal based on the latest revision of EPRI PWR Primary Side Water Chemistry Guidelines (COL 5.2(5)).

5.2-67 Rev. 2

APR1400 DCD TIER 2 1.100 1.095 Maximum RCS Pressure Normalized to Design Pressure 1.090 1.085 Design POSRV capacity 1.080 1.075 1.070 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 Pressurizer POSRV Capacity Normalized to Design Capacity Figure 5.2.2-1 Optimized Pressurizer POSRV Capacity 5.2-68 Rev. 2

APR1400 DCD TIER 2 1.15 At 7.46 sec., 1st bank MSSVs open At 9.14 sec., 2nd bank MSSVs open 1.10 At 13.20 sec., 3rd bank MSSVs open SG Pressure Normalized to Design Pressure 1.05 1.00 0.95 0.90 0.85 0.80 0 2 4 6 8 10 12 14 16 18 20 Time, Seconds Figure 5.2.2-2 Steam Generator Pressure Normalized to Design Pressure vs. Time for the Worst-Case Loss-of-Load Event 5.2-69 Rev. 2

APR1400 DCD TIER 2 1.2 1.1 Primary Pressure Normalized to Design Pressure 1.0 RCP discharge pressure Pressurizer pressure 0.9 0.8 At 7.00 sec., POSRVs open At 6.54 sec., reactor trip is initiated At 5.59 sec., reactor trip condition is reached 0.7 0 2 4 6 8 10 12 14 16 18 20 Time, Seconds Figure 5.2.2-3 Primary Pressure Normalized to Design Pressure vs. Time for the Worst-Case Loss-of-Load Event 5.2-70 Rev. 2

APR1400 DCD TIER 2 1.2 1.0 Reactor Power Normalized to 100% of Rated Power 0.8 0.6 At 6.54 sec., reactor trip is initiated 0.4 0.2 0.0 0 2 4 6 8 10 12 14 16 18 20 Time, Seconds Figure 5.2.2-4 Reactor Power Normalized to 100 % of Rated Power vs. Time for the Worst-Case Loss-of-Load Event 5.2-71 Rev. 2

APR1400 DCD TIER 2 Figure 5.2.3-1 pH Control Program (307.2 ºC) 5.2-72 Rev. 2

APR1400 DCD TIER 2 5.3 Reactor Vessel 5.3.1 Reactor Vessel Materials The APR1400 reactor vessel materials meet the following requirements:

a. General Design Criteria (GDC) 1 and 30 in Appendix A of 10 CFR Part 50 (Reference 1) as related to quality standards for design, fabrication, erection, and testing of structures, systems, and components

b. GDC 4 as related to the compatibility of components with environmental conditions

c. GDC 14 as related to the prevention of rapidly propagating fractures of the reactor coolant pressure boundary (RCPB)

d. GDC 31 as related to material fracture toughness

e. GDC 32 as related to the requirements for a materials surveillance program

f. 10 CFR 50.55a (Reference 2) as related to quality standards for design and determination and monitoring of fracture toughness

g. 10 CFR 50.60 (Reference 3) as related to RCPB fracture toughness

h. 10 CFR Part 50, Appendix B, Criterion XIII (Reference 4) as related to onsite material cleaning control

i. 10 CFR Part 50, Appendix G (Reference 5) as related to materials testing and acceptance criteria for fracture toughness

j. 10 CFR Part 50, Appendix H (Reference 6) as related to the determination and monitoring of fracture toughness 5.3.1.1 Material Specifications The principal ferritic materials used in the reactor vessel are listed in Table 5.2-2. These materials are in accordance with ASME Section III. Ferritic reactor vessel pressure boundary materials satisfy the fracture toughness requirements of 10 CFR Part 50, Appendix G and NRC SRP BTP 5-3 (Reference 7).

5.3-1 Rev. 2

APR1400 DCD TIER 2 The physical and mechanical properties of the reactor vessel material and the effects of radiation on the materials are described in Subsection 5.3.2.1.1.

5.3.1.2 Special Process Used for Manufacturing and Fabrication The reactor vessel is fabricated in accordance with ASME Section III (Reference 8),

NB-4000, and its materials satisfy the requirements of ASME Section III, NB-2000.

Application of the appropriate Code Symbol and completion of a data report are in accordance with ASME Section III, NCA-8000. No special manufacturing methods that could compromise the integrity of the vessel are used. The reactor vessel is a vertically mounted cylindrical vessel with a hemispherical lower head welded to the vessel and a removable hemispherical upper closure head. The construction consists of forged rings, forged hemispherical heads, forged flanges on the closure head, and forged nozzles.

Pressure boundary reactor vessel forgings are made of ASME SA-508 Grade 3, Class 1, low-alloy steel. The forgings are supplied in a quenched and tempered condition.

Vacuum degassing, to lower the hydrogen level and to improve the quality of the steel, is applied to the forgings. The forgings in the reactor vessel beltline and the as-deposited welds contain no greater than the weight percent of residual elements described in Subsection 5.2.3.1. The internal surfaces that are in contact with the reactor coolant and vessel flange surface are clad with austenitic stainless steel or NiCrFe alloy.

The reactor vessel except for the closure head consists of three shell sections (upper, intermediate, and lower) and a lower head. The upper shell section is forged to have a flange with a machined ledge on the inside surface to support the core support barrel, which in turn supports the reactor internals and the core. The length of each shell is adjusted not to include the welds within the effective core region. The vessel flange is drilled and tapped to receive the closure studs and is machined to provide a mating surface for the reactor vessel closure seals. Each shell consists of one 360-degree forged ring. The lower head is constructed of a single hemispherical forging. The three shell sections and the lower head forging are joined by welding, along with 4 inlet nozzle forgings, 2 outlet nozzle forgings, 4 direct vessel injection (DVI) nozzle forgings, and 61 in-core instrument nozzles to form a complete vessel assembly.

The closure head is fabricated separately since it is joined to the reactor vessel by bolting.

The closure head consists of a head flange and a dome. The head flange is a forged ring.

The flange is drilled to match the vessel flange stud hole locations, and the lower surface of the flange is machined to provide a mating surface for the vessel closure seals. The dome 5.3-2 Rev. 2

APR1400 DCD TIER 2 is constructed of a single hemispherical forging. The dome and flange are welded together to form the closure head, and the control element drive mechanism (CEDM) nozzles are welded into the head to complete the assembly.

Welding materials for the reactor vessel conform to ASME Sections II and III, or satisfy requirements for other welding materials as permitted in ASME Section IX. Table 5.2-2 shows the welding material specifications for the APR1400 RCS application.

Welding of the pressure boundary parts of the reactor vessel is performed in accordance with the welding procedure specifications (WPSs), which satisfy the requirements of ASME Sections III and IX.

Welding processes such as submerged arc welding (SAW), flux cored arc welding (FCAW),

and gas tungsten arc welding (GTAW) are applied for stainless steel or nickel-based alloy cladding of reactor vessel internal surfaces. Welding processes such as GTAW and shielded metal arc welding (SMAW) are applied to dissimilar welds by buttering.

Welding processes such as SMAW and SAW are applied to the reactor vessel dome and flange weld, flange-shell-head welds, and other girth seam welds. The build-up application uses primarily the SMAW process. Electroslag welding is not used in the reactor vessel.

Welding of low-alloy steel pressure boundary welds conforms with the recommendations of NRC RG 1.50 (Reference 9). Preheat temperatures utilized for low alloy steel are in accordance with ASME Section III, Appendix D. The maximum interpass temperature utilized is generally 260 °C (500 °F). In the event that the requirements in Paragraphs C.1, C.2, and C.3 of NRC RG 1.50 are not met, the soundness of the weld is demonstrated by an examination that meets the acceptance criteria specified in ASME Section III. Hydrogen is removed either by maintaining preheat until post-weld heat treatment is performed or by post-heating at a temperature and for the length of time that are sufficient to preclude the effects of hydrogen-assisted cracking.

Post-weld heat treatment temperature and time for welds of low alloy steels are in accordance with ASME Section III, NB-4620.

5.3.1.3 Special Methods for Nondestructive Examinations Prior to, during, and after fabrication of the reactor vessel, nondestructive tests based on ASME Section III are performed on all welds and forgings as required. The 5.3-3 Rev. 2

APR1400 DCD TIER 2 nondestructive examination requirements including calibration methods, instrumentation, sensitivity, reproducibility of data, and acceptance standards are in accordance with the requirements of ASME Section III (see Table 5.2-1). These methods, procedures, and requirements are compatible with ASME Section XI (Reference 10) so that the results of the preservice inspections can be correlated with inservice inspections. Strict quality control is maintained in critical areas such as calibration of test instruments.

All full-penetration, pressure-containing welds are 100 percent radiographed to the standards of ASME Section III. Weld preparation areas, back-chip areas, and final weld surfaces are magnetic-particle or liquid-penetrant examined. Other pressure-containing welds, such as those used for the attachments of nonferrous nickel-chromium-iron CEDM nozzles and vent and instrument nozzles to the reactor vessel and head, are inspected by liquid-penetrant tests of the root pass (the lesser of half of the thickness or each 12.7 mm (0.5 in) of weld deposit and the final surface). Additionally, the base metal weld preparation area is magnetic-particle and is examined prior to overlay with nickel-chromium-iron weld metal.

All forgings are inspected by ultrasonic testing using longitudinal beam techniques. In addition, ring forgings are tested using shear wave techniques.

All carbon-steel and low alloy forgings and ferritic welds are also subjected to magnetic-particle examination after stress relief.

All vessel bolting material is examined using ultrasonic and magnetic-particle examination during the manufacturing process. The bolting material receives a straight-beam, longitudinal and radial-scan, ultrasonic examination with a search unit area not exceeding 645 mm2 (1 in2).

All hollow material excluding stud, nut, and washer material receives second ultrasonic examination using angle-beam in circumferential direction with a search unit area not exceeding 645 mm2 (1 in2). A reference specimen of the same composition and thickness containing a notch (located on the inside surface) of 25.4 mm (1 in) in length and a depth of 3 percent of nominal section thickness, or 6 mm (1/4 in), whichever is less, is used for calibration. Use of these techniques provides reasonable assurance that no materials that have unacceptable flaws, observable cracks, or sharply defined linear defects are used.

The magnetic-particle inspection is performed both before and after threading of the studs.

5.3-4 Rev. 2

APR1400 DCD TIER 2 Upon completion of all post-weld heat treatments, the reactor vessel is hydrostatically tested, and all accessible ferritic weld surfaces, including those used to repair material, are magnetic-particle inspected in accordance with ASME Section III.

Clad surfaces that are subject to high load conditions and carrying load of attachments are ultrasonically tested as necessary to provide reasonable assurance of the bond required for the intended service. In all other areas, the cladding is also ultrasonically inspected for lack of bond, transverse to the direction of welding.

Tables 5.3-8 and 5.3-9 summarize the nondestructive examination methods that are used for the reactor vessel base materials and welds, respectively.

5.3.1.4 Special Controls for Ferritic and Austenitic Stainless Steels Subsection 5.2.3 describes details concerning controls for welding of ferritic and austenitic stainless steels. Applicable NRC Regulatory Guides (RGs) for the reactor vessel for this purpose and subsections describing conformance to the RGs are identified as follows:

a. NRC RG 1.31, Control of Ferrite Content in Stainless Steel Weld Metal (Reference 11), is addressed in Subsection 5.2.3.4.4.

b. NRC RG 1.34, Control of Electroslag Weld Properties (Reference 12), is addressed in Subsection 5.2.3.3.

c. NRC RG 1.28, Quality Assurance Program Criteria (Design and Construction)

(Reference 13), is addressed in Subsection 5.2.3.4.2.

d. NRC RG 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components (Reference 14), is addressed in Subsection 5.2.3.3.

e. NRC RG 1.44, Control of the Processing and Use of Stainless Steel (Reference 15), is addressed in Subsection 5.2.3.4.1.

f. NRC RG 1.50, Control of Preheat Temperature for Welding of Low-Alloy Steel, is addressed in Subsection 5.2.3.3.

g. NRC RG 1.71, Welder Qualification for Areas of Limited Accessibility (Reference 16), is addressed in Subsection 5.2.3.3.

5.3-5 Rev. 2

APR1400 DCD TIER 2

h. NRC RG 1.99, Radiation Embrittlement of Reactor Vessel Materials (Reference 17), is addressed in Subsection 5.3.1.6.7.

i. NRC RG 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence (Reference 18), is addressed in Subsection 4.3.3.3.

Tools used in abrasive work operations on austenitic stainless steel, such as grinding or wire brushing, do not contain and are not contaminated with ferritic carbon steel or other materials that could contribute to intergranular cracking or stress corrosion cracking (SCC).

5.3.1.5 Fracture Toughness In accordance with 10 CFR Part 50, Appendix G, Paragraph IV A, the reactor vessel beltline materials have minimum upper-shelf energy of 102 Joules (75 ft-lbs) as determined from Charpy V-notch tests on unirradiated specimens in accordance with ASME Section III, NB-2320. In addition, the reactor vessel beltline materials satisfy the requirements of NRC SRP BTP 5-3. The detailed information on the upper shelf energy of the reactor vessel beltline materials is described in Subsection 5.3.2.4. Charpy impact tests are performed on transversely (weak direction) oriented specimens from the beltline forgings to establish RTNDT as required by 10 CFR Part 50, Appendix G.

The RTNDT of reactor vessel materials is determined based on a nil-ductility transition temperature (TNDT) obtained through a drop weight test and the results of Charpy V-notch tests which are carried out at temperatures not greater than TNDT + 33 °C (TNDT + 60 °F).

The TNDT is the RTNDT when the Charpy V-notch test results exhibit at least 0.89 mm (35 mils) lateral expansion and not less than 68 J (50 ft-lb) absorbed energy. Test coupons, test specimens, testing procedures, testing requirements, and acceptance criteria for RTNDT determination are fabricated, established, or applied in accordance with ASME Section III, NB-2300.

An initial RTNDT for the reactor vessel active core region base material, the girth seam between the intermediate and lower shell courses, and the girth seam between the lower shell courses and bottom head is -23.3 °C (-10 °F). An initial RTNDT for the remaining material of the reactor vessel pressure boundary is -12.2 °C (10 °F).

As a result of fast neutron irradiation in the region of the core, RTNDT of irradiated material increases with operation. The effect of neutron irradiation is taken into account in accordance with NRC RG 1.99.

5.3-6 Rev. 2

APR1400 DCD TIER 2 5.3.1.6 Material Surveillance The irradiation surveillance program for the APR1400 is conducted to assess the neutron-induced changes in the RTNDT (reference temperature) and mechanical properties of the reactor vessel materials. Changes in the impact and mechanical properties of the material are evaluated by the comparison of pre-irradiation and post-irradiation test results. The capsules containing the surveillance test specimens used for monitoring the neutron-induced property changes of the reactor vessel materials are irradiated under conditions that represent, as closely as practical, the irradiation conditions of the reactor vessel.

The APR1400 reactor vessel surveillance program satisfies the ASTM E185 (Reference 19) requirements for surveillance tests in light water cooled nuclear power reactor vessels, and the requirements of Appendix H of 10 CFR Part 50 and NRC SRP BTP 5-3. The COL applicant is to provide a reactor vessel material surveillance program for a specific plant (COL 5.3(1)).

5.3.1.6.1 Test Material Selection Materials selected for the surveillance program are those judged most likely to be controlling with regard to radiation embrittlement according to the recommendations of NRC RG 1.99.

Surveillance test materials are prepared from the actual materials used in fabricating the beltline region of the reactor vessel. The test materials are processed so they are representative of the materials in the completed reactor vessel. Specimens are prepared from three metallurgically different materials, including base metal, weld metal, and heat-affected zone (HAZ) material.

Base metal test material is from a section of the shell course forging that is selected from the beltline of the reactor vessel. Selection is based on an evaluation of initial toughness (characterized by an index temperature such as RTNDT) and the estimated effect of chemical composition and neutron fluence on the toughness during reactor operation. Normally, the forging with the highest adjusted reference temperature at end-of-life is selected as the surveillance base metal test material.

Weld metal test material, representative of the controlling reactor pressure vessel weld, is produced by welding together sections of forgings from the beltline of the reactor vessel.

The HAZ test material is manufactured from a section of the same forgings used for base 5.3-7 Rev. 2

APR1400 DCD TIER 2 metal surveillance test material. The weld metal test material is produced from the same heat of weld wire or rod and lot of flux used in the beltline of the reactor vessel. Welding parameters duplicate those used for the beltline welds.

Two additional sets of test specimens for each material are provided as representative stock (archival material) with documentation and identification.

5.3.1.6.2 Test Specimens 5.3.1.6.2.1 Type and Quantity Drop weight, standard and precracked Charpy impact, tensile test, and compact tension fracture toughness specimens are provided for unirradiated baseline tests. Drop weight tests are conducted in accordance with ASTM E208 (Reference 20). Charpy impact tests are conducted in accordance with ASTM E23 and A370 (References 21 and 22, respectively). Tensile tests are conducted in accordance with ASTM E8/8M and E21 (References 23 and 24, respectively). Static fracture toughness tests are performed in accordance with ASTM E1820 and/or E1921 (References 25 and 26, respectively).

Correlation of drop weight and Charpy impact tests to establish RTNDT is made in accordance with ASME Section III, NB-2300. Standard and precracked Charpy impact, tensile test, and compact tension fracture toughness specimens are provided for post-irradiation tests.

The total quantity of specimens furnished for carrying out the overall requirements of this program is presented in Table 5.3-1.

Type and quantity of specimens for baseline testing are shown in Table 5.3-2, and for irradiation encapsulation are shown in Table 5.3-3.

5.3.1.6.2.2 Baseline Specimens The type and quantity of test specimens provided for establishing the properties of the unirradiated reactor vessel materials are presented in Table 5.3-2. The data from tests of these specimens provide the basis for determining the neutron-induced property changes of the reactor vessel materials.

Twelve drop weight test specimens are provided for each base metal (transverse), weld metal, and HAZ material for establishing the nil-ductility transition temperature (TNDT) of 5.3-8 Rev. 2

APR1400 DCD TIER 2 the unirradiated surveillance materials. These data form the basis for RTNDT determination. RTNDT is the reference temperature from which subsequent neutron-induced changes are determined.

Twenty-four standard Charpy test specimens are provided for each base metal (longitudinal and transverse), weld metal, and HAZ material. This quantity exceeds the minimum number of test specimens recommended by ASTM E185 for developing a Charpy impact energy transition curve and is intended to provide a sufficient number of data points for establishing accurate Charpy impact energy transition temperatures for these materials.

These data, together with the drop weight TNDT, are used to establish an RTNDT for each material.

Twelve precracked Charpy impact test specimens are provided for each base metal (longitudinal and transverse) and weld metal in addition to the standard Charpy impact specimens. This quantity is sufficient to determine fracture toughness properties (critical stress intensity factors under dynamic loading) over the range extending from linear elastic to elastic-plastic fracture.

Twelve tensile test specimens are provided for each base metal (longitudinal and transverse) and weld metal. This quantity also exceeds the minimum number of test specimens recommended by ASTM E185 and is intended to permit a sufficient number of tests for accurately establishing the tensile properties for these materials at a minimum of three test temperatures.

Eight 1T compact tension test specimens and four 1/2T compact tension test specimens are provided for each base metal (transverse) and weld metal. For base metal (longitudinal),

four 1T and four 1/2T compact tension test specimens are provided. These specimens are for augmenting the fracture toughness data determined from the precracked Charpy tests.

This quantity of specimens is sufficient to determine fracture toughness properties over the range extending from linear elastic to elastic-plastic fracture behavior.

5.3.1.6.2.3 Irradiated Specimens Specimens for the tensile test, standard and precracked Charpy impact test, and 1/2T compact tension test are used for determining changes in the strength and static and dynamic toughness properties of the materials due to neutron irradiation. A total of 360 standard Charpy impact, 162 precracked Charpy impact, 72 1/2T compact tension, and 54 tensile test specimens are provided. The type and quantity of test specimens provided for 5.3-9 Rev. 2

APR1400 DCD TIER 2 establishing the properties of irradiated materials over the 60 years life of the vessel are presented in Table 5.3-3. Compact tension specimens provided for capsule irradiation are precracked prior to insertion to reduce the time required for post-irradiation testing. The types and quantity of specimens provided exceed the minimum requirements of ASTM E185.

5.3.1.6.3 Surveillance Capsules The surveillance test specimens are placed in corrosion resistant capsule assemblies for protection from the primary coolant during irradiation. The capsules also serve to physically locate the test specimens in selected positions within the reactor vessel and to facilitate the removal of a desired quantity of test specimens when a specified radiation exposure has been attained. Six identical surveillance capsule assemblies are provided for the reactor vessel. Four of the assemblies are for retrieval, and two are for standby. The type and quantity of specimens contained in each type of capsule assembly are presented in Table 5.3-4.

A typical capsule assembly, illustrated in Figure 5.3-1, consists of a series of three specimen compartments that are connected by wedge couplings and a lock assembly.

Each compartment enclosure of the capsule assembly is internally supported by the surveillance specimens and is externally pressure tested to 219.7 kg/cm2 (3,125 psi) during final fabrication. The wedge couplings also serve as end caps for the specimen compartments and position the compartments within the capsule holders, which are attached to the reactor vessel cladding. The lock assemblies fix the locations of the capsules within the holders by exerting axial forces on the wedge coupling assemblies; this causes the wedges to exert horizontal forces against the sides of the holders preventing relative motion. The lock assemblies also serve as a point of attachment for the tooling used to remove the capsules from the reactor.

Each capsule assembly is made up of the upper compartment assembly, the center compartment assembly, and the lower compartment assembly. Each capsule assembly is assigned a unique identification so that a complete record of test specimen location within each compartment can be maintained.

5.3.1.6.3.1 Upper Compartment Assembly The upper compartment assembly contains 12 Charpy impact test specimens, nine base metal (longitudinal) Charpy impact test specimens, and a set of five flux spectrum monitors 5.3-10 Rev. 2

APR1400 DCD TIER 2 in the top section as shown in Figure 5.3-2. The bottom section contains three base metal (longitudinal) Charpy impact test specimens, six base metal (transverse) Charpy impact test specimens, three base metal (longitudinal) tension specimens, and four base metal (longitudinal) 1/2T compact tension specimens.

The Charpy test specimens are arranged vertically in 1 x 3 arrays and are oriented with the notch toward the reactor core. The 1/2T compact tension specimens are oriented so that the opening of the crack starter notch is facing the top of the compartment. This orientation results in a neutron flux gradient parallel to the crack front. The temperature differential between the specimens and the reactor coolant is minimized by using spacers between the specimens and the compartment and by sealing both sections of the assembly in an atmosphere of helium. This quantity of specimens provides an adequate number of data points for establishing a Charpy impact energy transition curve for a given irradiated material. Comparison of the unirradiated and irradiated Charpy impact energy transition curves permits determination of the RTNDT changes due to irradiation for the various materials.

5.3.1.6.3.2 Center Compartment Assembly The center compartment assembly contains six base metal (transverse) Charpy impact test specimens, 12 weld metal Charpy impact test specimens, and six base metal (longitudinal) precracked Charpy impact test specimens in the top section as shown in Figure 5.3-3. The bottom section contains three base metal (longitudinal) precracked Charpy impact test specimens, a set of 11 flux spectrum monitors, a set of four temperature monitors, three base metal (transverse) tension specimens, and four base metal (transverse) 1/2T compact tension specimens. Both compartment sections are sealed within an atmosphere of helium.

The tension specimens are placed in a housing machined to fit the compartment. Split spacers are placed around the specimen gage length to minimize the temperature differential between the specimen gage length and the reactor coolant. The impact specimens are arranged vertically in 1 x 3 arrays and are oriented with the notch toward the reactor core. Spacers are utilized between the test specimens and the compartment.

5.3.1.6.3.3 Lower Compartment Assembly The lower compartment assembly contains four weld metal 1/2T compact tension specimens, three weld metal tension test specimens, and nine base metal (transverse) pre-cracked Charpy impact test specimens in the top section as shown in Figure 5.3-4. The 5.3-11 Rev. 2

APR1400 DCD TIER 2 tension specimens are placed in a housing machined to fit the compartment. Split spacers are placed around the specimen gage length to minimize the temperature differential between the specimen gage length and the reactor coolant. The impact specimens are arranged vertically in 1 x 3 arrays and are oriented with the notch toward the reactor core.

Spacers are utilized between the test specimens and the compartment. The bottom section contains a set of five flux spectrum monitors, nine weld metal precracked Charpy impact test specimens, and 12 Charpy impact test specimens. Both compartment sections are sealed within an atmosphere of helium.

5.3.1.6.4 Neutron Irradiation and Temperature Exposure The changes in the RTNDT of the reactor vessel materials are derived from specimens irradiated to various fluence levels in different neutron energy spectra. To accurately predict the RTNDT of the vessel materials, complete information on the neutron flux energy spectra and the irradiation temperature of the encapsulated specimens are available.

5.3.1.6.4.1 Flux Measurements Fast neutron flux measurements are obtained by insertion of threshold detectors into each of the six irradiation capsules. Such detectors are particularly suited for the proposed application because their effective threshold energies are in the range of interest (0.5 to 15 MeV).

These neutron threshold detectors and the thermal neutron detectors, presented in Table 5.3-5, can be used to monitor the thermal and fast neutron spectra incident on the test specimens. These detectors possess reasonably long half-lives and activation cross sections covering the desired neutron energy range.

Three sets of flux spectrum monitors are included in each capsule assembly. Each detector is placed inside a sheath that identifies the material and facilitates handling.

Cadmium covers are used for the materials with competing neutron capture activities. The flux monitors are placed in holes drilled in stainless steel housings, as shown in Figure 5.3-3, at three axial locations in each capsule assembly to provide an axial profile of the level of fluence that the specimens attain.

To determine the neutron fluence at the inner surface of the reactor vessel both of the measured value from detectors and the calculated value by transport theory are considered in accordance with NRC RG 1.190. Calculation methods for the neutron flux and fluence 5.3-12 Rev. 2

APR1400 DCD TIER 2 are described in Subsection 4.3.3.3. The COL applicant is to provide plant-specific surveillance capsule data to benchmark APR1400-Z-A-NR-14015-P and demonstrate applicability to the specific plant (COL 5.3(2)).

5.3.1.6.4.2 Temperature Estimates Because the changes in mechanical and impact properties of irradiated specimens are highly dependent on the irradiation temperature, it is necessary to have information on the specimens as well as the pressure vessel. During irradiation, instrumented capsules are not practicable for a surveillance program extending over the design lifetime of a power reactor. The maximum temperature of the irradiated specimens can be estimated with reasonable accuracy by including small pieces of low melting point alloys or pure metals in the capsule assemblies. The compositions of candidate materials with melting points in the operating range of power reactors are listed in Table 5.3-6. The monitors are selected to bracket the operating temperature of the reactor vessel. The temperature monitors consist of a helix of low melting alloy wire inside a sealed quartz tube. A stainless steel weight is provided to destroy the integrity of the wire when the melting point of the alloy is reached. The compositions and the melting temperatures of the temperature monitors are differentiated by the physical lengths of the quartz tubes that contain the alloy wires.

A set of temperature monitors is included in each capsule assembly. The temperature monitors are placed in holes drilled in stainless steel housings, as shown in Figure 5.3-3, and provide the maximum temperature to which the specimens are exposed.

5.3.1.6.5 Irradiation Locations The test specimens are enclosed within six capsule assemblies. The axial positions of capsule assemblies are bisected by the midplane of the core as shown in Figure 5.3-6. A summary of the specimens contained in each of these capsule assemblies is presented in Table 5.3-4. The test specimens contained in the capsule assemblies are used for monitoring the neutron-induced property changes of the reactor vessel materials. These capsules, therefore, are positioned near the inside wall of the reactor vessel so that the irradiation conditions (fluence, flux spectrum, temperature) of the test specimens resemble as closely as possible the irradiation conditions of the reactor vessel. The neutron fluence of the test specimens is expected to be approximately 1.4 times higher than that seen by the adjacent vessel wall, and the measured changes in properties of the surveillance materials are therefore able to predict the radiation induced changes in the reactor vessel beltline 5.3-13 Rev. 2

APR1400 DCD TIER 2 materials. The capsule assemblies are placed in capsule holders positioned circumferentially about the core at locations that include the regions of maximum flux.

Figure 5.3-5 presents the typical exposure locations for the capsule assemblies in the plan view.

All capsule assemblies are inserted into their respective capsule holders during the final reactor assembly operation. The design also permits the remote installation of replacement capsule assemblies. The capsule holders are welded to the vessel cladding on the inside surface, and the welds are subject to inspection according to the requirements for permanent structural attachments as given in ASME Sections III and XI.

5.3.1.6.6 Withdrawal Schedule The capsule assemblies remain within their holders until the specimens in the assemblies have been exposed to predetermined removal schedule based on effective full power years (EFPYs). At that time, the capsule assembly is removed, and the surveillance materials are evaluated. The design maximum fluence values for the surveillance capsules are determined at the azimuthal locations for the recommended withdrawal schedule of ASTM E185, extended to a design life of 60 years. The design maximum fluence values in Table 5.3-7 are accurate within +20 percent, -20 percent. The target fluence identified in Table 5.3-7 is an actual fluence which a capsule may experience until it is withdrawn. The target fluence values in Table 5.3-7 are accurate within +16.28 percent, -16.28 percent.

The uncertainty is composed of errors in the calculational method and errors in the combined radial and axial power distribution.

Withdrawal schedules may be modified to coincide with the refueling outages or plant shutdowns most closely approaching the withdrawal schedule. The two standby capsules are provided in the event they are needed to monitor the effect of a major core change or annealing of the vessel or to provide supplemental toughness data for evaluating a flaw in the beltline.

5.3.1.6.7 Irradiation Effects Prediction Basis Irradiation induced RTNDT shift and reduction of upper shelf energy are predicted based on NRC RG 1.99, Radiation Embrittlement of Reactor Vessel Materials. Predicted changes in RTNDT and upper shelf energy are used to select the surveillance materials (see Subsection 5.3.1.6.1) and to formulate the initial heatup and cooldown limit curves for 5.3-14 Rev. 2

APR1400 DCD TIER 2 plant operation. When actual post-irradiation surveillance data become available for each reactor vessel, the data are used to adjust plant operating limit curves.

5.3.1.7 Reactor Vessel Fasteners The bolting material for the reactor vessel closure head is fabricated from SA-540 B24, Class 3 material (Reference 27). This material conforms to the requirements of 10 CFR Part 50, Appendix G, and the intent of NRC RG 1.65 (Reference 33). Nondestructive examination is performed according to ASME Section III, NB-2580, during the manufacturing process. More information on NDE is described in Subsection 5.3.1.3.

Material for reactor vessel studs is tested in accordance with the requirements of SA-540 Grade B24 Class 3, ASME Section III, NB-2220 and NB-2300. The maximum measured yield strength of the reactor vessel closure stud bolting material SA-540, Grade B-24 will not exceed 1035 MPa (150 ksi). Charpy V-Notch testing is required to be performed at a temperature of 4.4 °C (40 °F) or lower. Each specimen of one test (consisting of three specimens) is required to exhibit a minimum of 0.635 mm (25 mils) lateral expansion and 68 Joules (45 ft-lbs) absorbed energy. These requirements also satisfy NRC RG 1.65 and 10 CFR Part 50, Appendix G, Paragraph IV A, at a temperature of 4.4 °C (40 °F) or lower, depending on the actual test temperature for the reactor vessel stud preload temperature or lowest service temperature, whichever is lower.

Actual material property values are reported on the certified material test reports (CMTRs) for the reactor vessel stud material.

The use of a manganese phosphate coating on threads of studs, nuts, and washers is specified to improve anti-galling properties and resistance to corrosion. In addition, a nickel-based high purity anti-seize lubricant is specified to be added to threads and bearing surfaces at installation to further enhance anti-galling properties. Field experience to date has shown no evidence of deleterious breakdown of either phosphate coating or lubricant.

The stud holes in the vessel flange are protected from the refueling water using the seal plugs prior to refueling activity.

5.3-15 Rev. 2

APR1400 DCD TIER 2 5.3.2 Pressure-Temperature Limits, Pressurized Thermal Shock, and Charpy Upper Shelf Energy Data and Analyses All components in the RCS are designed to withstand the effects of cyclic loads due to RCS temperature and pressure changes. These cyclic loads are introduced by normal power maneuver, loss of load transient, reactor trips, and startup and shutdown operation. The design number of cycles for heatup and cooldown is based on a rate of 55.6 °C/hr (100 °F/hr). During unit startup and shutdown, the rate of temperature change is limited to less than 55.6 °C/hr (100 °F/hr) by administrative procedure. The maximum allowable RCS pressure at the corresponding minimum allowable temperature is based upon the stress limitations for brittle fracture. These limitations are derived using linear elastic fracture mechanics principles, the procedures prescribed by ASME Section XI, Appendix G, Fracture Toughness Criteria for Protection Against Failure, Appendix G to 10 CFR Part 50, Fracture Toughness Requirements, NRC RG 1.99, Radiation Embrittlement of Reactor Vessel Materials, 10 CFR 50.61, Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock Events, NRC SRP BTP 5-3, Fracture Toughness Requirements, and the procedures recommended by Welding Research Council (WRC) Bulletin 175, Pressure Vessel Research Committee (PVRC) Recommendations on Toughness Requirements for Ferritic Materials (Reference 28). The reactor vessel is also designed, fabricated, erected, and tested to conform with the requirements of 10 CFR 50.55a, 10 CFR 50.60, and 10 CFR Part 50, Appendix A (GDC 1, 14, 31, and 32).

5.3.2.1 Pressure-Temperature Limitation Curves 5.3.2.1.1 Material Properties Pressure-temperature limitations (P-T limits) are determined using material property test data for reactor coolant pressure boundary materials, as required by ASME Section XI, Appendix G. Based on considerations of existing material property test data, an initial RTNDT for the reactor vessel beltline forging is -23.3 °C (-10 °F), and an initial RTNDT for the remaining material including weld materials of the reactor coolant system (RCS) is -12.2 °C (10 °F). RTNDT is determined in accordance with Article NB-2300 of ASME Section III.

As a result of fast neutron irradiation in the region of the core, the RTNDT of irradiated material increases with operation. The maximum integrated neutron fluence on the reactor vessel wall beltline region is estimated to be 9.5 x 1019 n/cm2. There are no 5.3-16 Rev. 2

APR1400 DCD TIER 2 longitudinal seam welds, and two of the circumferential seam welds are located near the fringes of core beltline region. It is conservatively assumed that weld materials are subjected to the maximum neutron fluence of 9.5 x 1019n/cm2 for evaluating RTNDT. The techniques used to analytically and experimentally predict the integrated fast neutron (E 1 MeV) fluxes of the reactor vessel are described in Subsections 4.3.2.8 and 5.3.1.6.

The shift in RTNDT of reactor vessel beltline materials can be analytically predicted based on the procedures described in NRC RG 1.99 because the RCS operating temperature (cold leg) is 290.6 °C (555 °F), which is above 274 °C (525 °F) as shown in Table 5.1.1-1. The surveillance program is prepared to obtain the reliable irradiation data for the adjustment or qualification of operating parameters. Reactor vessel shell materials are designed to limit RTNDT values at 1/4T location within 93.3 °C (200 °F) at the end-of-life. The RTNDT values at 1/4T location at the end-of-life are expected to be 20.2 °C (68.4 °F) for beltline forging and 46.9 oC (116.5 oF) for weld material per NRC RG 1.99 based on the weight percent of residual elements in Subsection 5.2.3.1.

The measured shift in RTNDT for a specimen is applied to the adjacent section of the reactor vessel for later stages in plant life because the measured neutron spectra and flux at the specimen and reactor vessel inside radius are close. The measured shift in RTNDT is adjusted for the difference in calculated flux magnitudes between the surveillance specimens and the point of interest in the reactor vessel wall.

The maximum fluence of the reactor vessel is obtained from the measured exposure by application of the calculated azimuthal neutron flux variation. The neutron fluence and the actual shift in RTNDT are established periodically during plant operation by testing the reactor vessel surveillance material specimens that are irradiated in capsules secured to the inside wall of the reactor vessel, as described in Subsection 5.3.1.6 and shown in Figures 5.3-5 and 5.3-6. Because surveillance materials are irradiated close to the inside surface of the vessel, the specimens demonstrate the accuracy of the RTNDT shift prediction as well as the effect of any additional long-term aging phenomenon. The P-T limits are then adjusted periodically, if necessary, to stay within allowable stress limits during normal operation.

5.3-17 Rev. 2

APR1400 DCD TIER 2 5.3.2.1.2 Determination of Pressure-Temperature Limitation Curves Figure 5.3-7 shows the pressure-temperature limitations determined in accordance with Appendix G of 10 CFR Part 50 for normal operation of the RCS. Details of P-T limit are described in the pressure and temperature limits report (PTLR) (Reference 29).

The P-T Limit curves are determined based on the following:

a. Minimum boltup temperature The minimum boltup temperature is governed principally by ASME Section XI, Appendix G, G-2222(c). The ASME Code requires that when the flange and adjacent shell regions are stressed by the full bolt preload and by pressure not exceeding 20 percent of the preoperational system hydrostatic test pressure, the minimum metal temperature in the stressed region must be at least the initial RTNDT plus any effects of irradiation. From the assumptions that the initial RTNDT for all regions of the RCS other than the beltline is -12.2 °C (10 °F) and that the flange and adjacent shell regions are not subjected to significant irradiation, the minimum boltup temperature per this requirement is -12.2 °C (10 °F). The minimum boltup temperature is taken conservatively to be 21.1 °C (70 °F).

b. Maximum pressure below the lowest service temperature (LST)

The maximum allowable pressure below the lowest service temperature is defined by ASME Section III, NB-2332(b), to be 20 percent of the preoperational hydrostatic test pressure. This test pressure is 125 percent of the design pressure (175.8 kg/cm2A [2,500 psia]) or 219.7 kg/cm2A (3,125 psia), and 20 percent of this value is 43.9 kg/cm2A (625 psia). Therefore, the maximum pressure below the lowest service temperature is 43.9 kg/cm2A (625 psia).

c. Minimum required temperature The lowest service temperature (LST) is defined by ASME Section III, Article NB-2332(b), to be the minimum allowable temperature at pressures above 20 percent of the preoperational hydrostatic test pressure. This value is defined to be no lower than RTNDT + 55.6 °C (100 °F), where the RTNDT is considered to be for the most limiting component in the RCS other than the beltline. From the 5.3-18 Rev. 2

APR1400 DCD TIER 2 assumption that the initial RTNDT for all regions of the RCS is -12.2 °C (10 °F), the LST per this requirement is -12.2 °C (10 °F) + 55.6 °C (100 °F) = 43.4 °C (110 °F)

(actual fluid temperature at the beltline). However, minimum allowable temperature in accordance with the minimum temperature requirements in Table 1 of 10 CFR Part 50, Appendix G, is calculated as 54.4 °C (130 °F), which is higher than the LST and, therefore, is used as the minimum required temperature.

d. Operation, heatup, and cooldown curves

1) Reactor vessel beltline P-T limits for the reactor vessel beltline are examined for heatup and cooldown conditions. For the heatup analysis, both the 1/4 thickness (1/4T) and 3/4T locations are examined. For heatup, the thermal stresses, t are compressive at the inside surface and tensile at the outside surface. The membrane stresses due to pressure, m are always tensile, but more so at the inside than outside surface. As a result, the total stress is always greater at the outside than the inside surface. However, the maximum allowable stresses, taking irradiation effects into account, decrease more at the inside than outside surface because the effects of irradiation are more pronounced there. It is not clear which surface stresses approach this maximum first.

Therefore, both locations are examined for the heatup transient.

For the cooldown analysis, only the 1/4T location needs to be examined.

During cooldown, the thermal stresses are tensile at the inside surface and compressive at the outside. Again, membrane stresses due to pressure are always positive. As a result, the total stress is always greater at the inside than the outside surface. Since the maximum allowable stresses, taking irradiation effects into account, decrease more at the inside than outside surface, it is clear that the total stress at the inside surface approaches the maximum allowable before those at the outside surface. Therefore, only the 1/4T location needs to be examined for the cooldown transient.

Heatup and cooldown rates from 0 °C/hr (0 °F/hr) (i.e., isothermal pressurization) to the design limit of 55.6 °C/hr (100 °F/hr) are examined in determining the allowable heatup and cooldown rates as a function of 5.3-19 Rev. 2

APR1400 DCD TIER 2 temperature to meet LTOP requirements for the RCS. LTOP considerations are discussed in Subsection 5.2.2.

For the beltline analysis, during normal operations, the following condition is maintained:

KIC = 2KIm + KIt Where:

KIC = reference stress intensity factor specified by Figure G-2210-1 in ASME Section XI, Appendix G KIm = stress intensity factor for membrane stress due to pressure KIt = stress intensity factor for thermal stress KIm = m Mm Mm = membrane correction factor defined in ASME Code Section XI, Appendix G, G-2214.1 m = (Pr)/t For inside defect:

KIt = 0.579 x 10-6 x CR x t2.5 MPam1/2 or KIt = 0.953 x 10-3 x CR x t2.5 ksiin1/2 For outside defect:

KIt = 0.458 x 10-6 x HU x t2.5 MPam1/2 or KIt = 0.753 x 10-3 x HU x t2.5 ksiin1/2 Where:

P = internal RV pressure 5.3-20 Rev. 2

APR1400 DCD TIER 2 r = inside RV radius t = RV wall thickness, mm (in.)

CR = cooldown rate, °C/hr (°F/hr)

HU = heatup rate, °C/hr (°F/hr)

The right side of the above equation (2KIm + KIt) is calculated for various pressures and then set equal to the left side (KIC). 2 represents a safety factor required by ASME Section XI, Appendix G. The minimum allowable temperature corresponding to a given pressure can then be calculated from this equation. The resulting combination represents a (maximum) pressure-(minimum) temperature limit that is not exceeded in order to provide reasonable assurance of non-brittle material behavior.

A set of such pressure-temperature coordinates defines a P-T limit curve for a specific heatup or cooldown rate at a particular point in plant life.

Figure 5.3-7 illustrates typical P-T limits for the end-of-life of 60 years or 55.8 EFPYs (based on 93 percent capacity factor).

The pressure used in computing KIm, and KIt and the corresponding computed temperature are for the crack tip. Correction factors for pressure and temperature are taken into account when expressing P-T limits graphically to show the limits in terms of indicated pressurizer pressure and indicated RCS temperature. This is done for P-T Limit curve presentation in the Technical Specifications (Chapter 16). The correction factors take into account the effects of instrument error, pressure differentials due to flow in the RCS, static pressure differentials due to elevation differences, and temperature differentials due to thermal gradients in the reactor vessel wall. The P-T limits shown in Figure 5.3-7 are in terms of indicated fluid conditions.

KIC is a function of the temperature, T, and the adjusted reference temperature (ART) of the material at the cracktip. The analytical expression for KIC is as follows:

KIC = 36.5 + 22.783 exp{0.036(T - ART)} MPam1/2 or 5.3-21 Rev. 2

APR1400 DCD TIER 2 KIC = 33.2 + 20.734 exp{0.02(T - ART)} ksiin1/2 The calculation of the ART is in accordance with the procedure described in NRC RG 1.99. The ART is a function of the initial RTNDT of the material, the shift in RTNDT due to irradiation over a period of time, RTNDT, and a safety margin. The equation for the ART is:

ART = (Initial)RTNDT + RTNDT + Margin The shift, RTNDT, is calculated from:

RTNDT = (CF) f(0.28 - 0.10logf) where CF is a chemistry factor and f is the neutron fluence at the point of interest in the reactor vessel wall. The fluence, f, is calculated from the surface fluence, fsurface (1019 n/cm2, E >1 MeV), as f = fsurface (e-0.24 x), n/cm2 where x (in inches) is the depth into the RV wall.

The margin is calculated based on:

Margin = 2(I² + ²)1/2 where I is the standard deviation of the (Initial)RTNDT data and is the standard deviation for RTNDT data as described in Regulatory Position C.1.1 of NRC RG 1.99. A value of zero is assigned to I because a measured property is used to establish RTNDT, not estimated values. For the beltline forging, the margin required to be added for uncertainties by RG 1.99 is 15.8 °C (28.4 °F). However, to cover unanticipated long-term aging phenomena, a margin of 27.8 °C (50 °F) for the vessel beltline base materials is used for additional conservatism. In case of weld materials, no additional conservatism is applied in evaluating the margin because the maximum neutron fluence is applied to the weld location. Once confirmatory data are available from the reactor vessel surveillance program, the margin can be reduced in subsequent shift calculations consistent with the RG 1.99.

2) Reactor vessel flange 5.3-22 Rev. 2

APR1400 DCD TIER 2 P-T limits for the reactor vessel flange are examined for heatup and cooldown in accordance with the procedures in Article G-2220 in ASME Section XI, Appendix G. For the flange analysis, the following condition is maintained during normal operations:

KIC = 2KI, primary + KI, secondary Where:

KI, primary = Km, pressure + Km, boltup + Kb, boltup KI, secondary = Kb, pressure + Kt Km, pressure = stress intensity factor for membrane stress due to pressure

= m, pressure Mm Km, boltup = stress intensity factor for membrane stress due to boltup

= m, boltup Mm Kb, boltup = stress intensity factor for bending stress due to boltup

= b, boltup Mb m, pressure = membrane (hoop) stress due to pressure m, boltup = membrane stress due to boltup b, boltup = bending stress due to boltup Mm = membrane correction factor Mb = bending correction factor Where:

Kb, pressure = stress intensity factor for bending stress due to pressure 5.3-23 Rev. 2

APR1400 DCD TIER 2

= b, pressure Mb b, pressure = secondary bending stress due to pressure Kt = stress intensity factor for thermal stress

= Mb t t = thermal stress at the crack The left side of the above equation (KIC) is calculated for various temperatures; the right side is calculated as a function of pressure. The maximum allowable pressure corresponding to a given temperature can then be calculated from this equation. The resulting (maximum) pressure-(minimum) temperature coordinates define the flange P-T Limit for a specific heatup or cooldown at a particular point in plant life. In no case is the flange minimum temperature limit allowed to be less than the flange RTNDT +

66.7 °C (120 °F) during normal operation (when the pressure exceeds 20 percent of the preoperational system hydrostatic pressure), and RTNDT + 50 °C (90 °F) during hydrostatic pressure tests and leak tests in accordance with Appendix G of 10 CFR Part 50.

e. Preservice hydrostatic test limit To conform with Table 1 of 10 CFR Part 50 Appendix G or the recommendation of Article G-2400(a) in ASME Section XI, Appendix G, the preservice hydrostatic test is to be performed at an isothermal temperature no lower than RTNDT +

33.3 °C (60 °F). Assuming an initial RTNDT of -12.2 °C (10 °F) for all regions of the RCS, the preservice hydrostatic test limit is 21.1 °C (70 °F) (actual fluid temperature measured at the beltline).

f. Inservice leak and hydrostatic test curves P-T limits for inservice leak and hydrostatic tests are developed in the same manner as for the RV beltline described in the preservice hydrostatic test limit.

The exception is that a safety factor of 1.5 is applied to the stress intensity factor for membrane stress due to pressure, KIm, rather than 2, as allowed by Article G-2400(b) in ASME Section XI, Appendix G.

5.3-24 Rev. 2

APR1400 DCD TIER 2

g. Core critical curves The core critical curve is intended to provide additional margins of safety during core operation. The limit is defined as 22.2 °C (40 °F) above the minimum allowable temperature for heatup or cooldown and no less than the minimum temperature required in accordance with operating conditions 2.c and 2.d of Table 1 of 10 CFR Part 50 Appendix G.

The COL applicant is to develop P-T Limit curves based on plant-specific data (COL 5.3(3)).

5.3.2.2 Operating Procedures Details of the limiting condition for operations related to the RCS P-T limits and their bases are specified and described in Subsections 3.4.3 and B3.4.3 of Chapter 16 (Technical Specifications and Bases). The P-T Limit curves that are provided were prepared in accordance with Appendix G of ASME Section XI.

The RCS pressure and temperature are maintained within the prescribed P-T limits, which provide reasonable assurance that the integrity of reactor coolant pressure boundary can be maintained.

5.3.2.3 Pressurized Thermal Shock The reactor vessel meets the requirements of 10 CFR 50.61 (Reference 30), and NRC SRP BTP 5-3 (i.e., the PTS screening criteria are not projected to be exceeded by expiration of the operations).

RTPTS is evaluated using the procedure described in 10 CFR 50.61, which is provided below:

RTPTS = (Initial) RTNDT + RTPTS + Margin The calculated maximum RTPTS satisfies the screening criteria in 10 CFR 50.61(b)(2).

The PTS screening criteria are:

a. 132.2 °C (270 °F) for plates, forgings, and axial weld materials

b. 148.9 °C (300 °F) for circumferential weld materials 5.3-25 Rev. 2

APR1400 DCD TIER 2 The following assumptions are applied in the calculation of RTPTS for limiting beltline material:

a. The limiting case is the weld material subjected to the maximum integrated fast neutron fluence of 9.5 x 1019 n/cm2.

b. For the weld material, maximum copper content is 0.05 wt% and maximum nickel content is 0.10 wt%, and the maximum initial RTNDT is -12.2 °C (10 °F).

c. The adjustment in the reference temperature caused by irradiation (RTPTS) is calculated to be 31.4 °C (56.6 °F). The margin required by 10 CFR 50.61 is 31.1 °C (56 °F) for the weld materials.

The calculated RTPTS is 50.3 C (122.6 F), which satisfies the above PTS screening criteria for circumferential weld materials as shown in Table 5.3-10.

The calculated RTPTS for lower shell course in Table 5.3-10 is 10.2 C (50.4 F), which also satisfies the above PTS screening criteria for forging.

The COL applicant is to verify the RTPTS value based on plant-specific material property and neutron fluences (COL 5.3(4)).

5.3.2.4 Upper-Shelf Energy In accordance with 10 CFR Part 50, Appendix G, Paragraph IV A, and NRC SRP BTP 5-3, the reactor vessel beltline materials must have the minimum upper-shelf energy (USE) of 102 Joules (75 ft-lbs) initially and must maintain USE values of 68 joules (50 ft-lbs) through the life of the reactor vessel. The initial USE is determined from Charpy V-notch tests on unirradiated specimens in accordance with ASME Section III, NB-2320. Charpy impact tests are performed on transversely (weak direction) oriented specimens from the beltline forgings.

The change in the USE due to radiation embrittlement can be predicted in accordance with NRC RG 1.99 because the operating temperature (cold leg) is 290.6 °C (555 °F), which is higher than 274 °C (525 °F) as shown in Table 5.1.1-1.

Even with the limiting value of 102 Joules (75 ft-lbs) assumed for the initial USE, the end-of-life (EOL) USE is estimated to be 69.4 Joules (51 ft-lbs), which is greater than the 5.3-26 Rev. 2

APR1400 DCD TIER 2 limiting EOL value of 68 Joules (50 ft-lbs) based on the maximum neutron fluence of 9.5 x 1019 n/cm2, a maximum copper content of 0.03 wt% for beltline forgings, and 0.05 wt% for weld materials, as assumed in Subsection 5.3.2.3. Previous data for the OPR1000 reactor vessel materials including weld metal show that initial USE values are mostly greater than 200 joules (147 ft-lbs) and that actual EOL values of USE are expected to be much greater than 68 Joules (50 ft-lbs).

The COL applicant is to verify the USE at EOL based on plant-specific material property and neutron fluences (COL 5.3(4)).

5.3.3 Reactor Vessel Integrity Reasonable assurance of vessel integrity is provided because proven fabrication techniques are used and because well-characterized steels, which exhibit uniform properties and consistent behavior, are used. The characterization of these materials was established through industrial and governmental studies that examined the prefabrication material properties through irradiated service operation. Inservice inspection and material surveillance programs are also conducted during the service life of the vessel, which provide further reasonable assurance that vessel integrity is maintained. The reactor vessel material satisfies the screening criteria in 10 CFR 50.61 as described in Subsection 5.3.2.3, so reasonable assurance of the reactor vessel integrity against pressurized thermal shock events is provided. The reactor vessel is also designed, fabricated, erected, and tested to conform with the requirements of 10 CFR Part 50, Appendix A (GDC 1, 4, 14, 30, 31, and 32), 10 CFR 50.60, 10 CFR 50.55a, and 10 CFR Part 50, Appendices G and H.

5.3.3.1 Design Table 5.2-1 contains the applicable design codes. A schematic of the reactor vessel is shown in Figure 5.3-8. Additional information on the design is provided in Subsection 5.3.1.2. The design permits all required inspections to be performed and does not preclude access to areas requiring inservice inspection in conformance with ASME Section XI, as detailed in Subsection 5.2.4.

Reactor Vessel The reactor vessel is designed to operate for 60 years. The design temperature and 2

pressure are 343.3 °C (650 °F) and 175.8 kg/cm A (2,500 psia), respectively.

5.3-27 Rev. 2

APR1400 DCD TIER 2 The vessel consists of three cylindrical shell sections (upper, intermediate, and lower) and a bottom head. The upper, intermediate, and lower shell sections and bottom head forging are welded together to form a complete vessel assembly. There is no weld in the core beltline regionto enhance the prevention of brittle fracture.

The upper shell including vessel flange is a forged ring with a machined ledge on the inside surface for supporting the reactor vessel internal (RVI) and the core. In addition, four keyways are machined on the ledge to accommodate the RVI alignment keys. The vessel flange is machined to provide a mating surface for the reactor vessel closure seals and is drilled and tapped to engage the closure studs.

The bottom head is a single hemispherical forging. The bottom head contains 61 ICI penetration nozzles and four external shear key supports that mate with the keyway in the RV support column base plate. A flow skirt is also attached inside the bottom head. The flow skirt is a right circular cylinder and is located in the reactor vessel lower head below the RVI. Flow holes in the skirt are distributed to direct and make a uniform coolant flow to the core.

The closure head is fabricated separately and is joined to the reactor vessel by bolting.

The closure head consists of a head flange, a dome, and 101 CEDM nozzles including 8 spare nozzles, 2 heated junction thermocouple (HJTC) nozzles, a reactor coolant gas vent system (RCGVS) line, and pads for the integrated head assembly (IHA). The head flange is a forged ring and is drilled to match the vessel flange stud holes, and the lower surface of the flange is machined to provide a mating surface for the vessel closure seals. The dome is a single hemispherical forging.

The 54 closure stud bolts screw into the tapped holes in the vessel flange, and the nuts installed on the closure head are screwed onto the studs to provide a compressive load on the head for sealing. To provide uniform loading, the studs are hydraulically tensioned with the pre-load in the prescribed sequence.

Reasonable assurance is provided by the RV sealing by the use of two silver- plated NiCrFe alloy O-rings between the vessel and closure head flanges. The O-rings are hollow with openings to accommodate reactor coolant pressure. This configuration results in a self-energized seal that gets tighter as system pressure increases. The outer ring acts as a backup for the inner ring. A connection to the space between the seals is provided to monitor the integrity of the seals.

5.3-28 Rev. 2

APR1400 DCD TIER 2 The core stop lugs are installed on the internal surface of the reactor vessel bottom head to catch the core and RVI in the event of normal support failures.

The core stop lugs and flow skirt are arranged to minimize resistance to the flow and not to interfere with the core stabilizing lug shim installation.

The core stabilizing lugs, which function to limit the horizontal movement of the core and RVI, are also installed on the internal surface of the reactor vessel lower shell.

The external seal ledge of the RV flange provides the mating surface for the reactor cavity pool seal, which provides the bottom surface of the cavity to fill water for refueling operation.

Reactor Vessel Supports The RV is supported by four vertical columns located under the vessel inlet nozzles. A nozzle foot with a flange under each inlet nozzle provides a surface to which the column is bolted. The flange also acts as a horizontal key to positively locate the vertical centerline of the RV. The key is designed to mate with the building structure and allows free radial growth of the RV during thermal expansion while supporting the vessel horizontally during an earthquake, a postulated pipe break, and an IRWST discharge.

The bottom of each column ends in a base plate drilled to accept anchor bolts. Preloaded anchor bolts are the mechanism by which column loads are transmitted to the building structure. The base plate also acts as a keyway for the shear key welded on the RV bottom head. The key and keyway provide horizontal support and limit motion of the bottom head due to an earthquake, a postulated pipe break, and an IRWST discharge.

Reactor Vessel Nozzles There are two 106.7 cm (42 in) ID primary outlet nozzles and four 76.2 cm (30 in) ID primary inlet nozzles spaced equally around the vessel and welded to the intermediate shell of the RV. Each of four inlet nozzles has one foot below the nozzle attached with a bolting pad that serves as the support interfaces.

Four 21.6 cm (8.5 in) ID direct vessel injection (DVI) nozzles are welded to the intermediate shell above the centerline of the inlet and outlet nozzles to which the safety injection system (SIS) pipes are connected.

5.3-29 Rev. 2

APR1400 DCD TIER 2 Sixty-one ICI nozzles are fitted in the bottom head penetration holes. ICI nozzles are made of Alloy 690TT and are welded by J-groove welds with Alloy 52/52M and/or 152 weld metals on the bottom head.

One hundred and one CEDM nozzles and two HJTC nozzles are fitted in the closure head penetration holes. They are welded by J-groove weld with NiCrFe alloy on the closure head.

5.3.3.2 Materials of Construction The materials used in the construction of the reactor vessel, as listed in Table 5.2-2, are in accordance with ASME Section III. Detailed information about the reactor vessel materials including weld materials are described in Subsections 5.2.3 and 5.3.1.

Material requirements of ASME Section III NB and the applicable ASME Section II material specifications are applied to reactor vessel pressure boundary materials. The materials satisfy the fracture toughness requirements of 10 CFR Part 50, Appendix G. In addition, weld materials satisfy applicable ASME Section IX requirements.

The reactor vessel closure head and upper, intermediate, and lower shells including flanges, bottom head dome, and major nozzles are low-alloy steel that conforms to ASME Section II SA-508 Grade 3, Class 1. Austenitic stainless steel or nickel base alloy are used for the cladding materials of the reactor vessel.

The reactor vessel stud bolts are described in Subsections 5.3.1.7 and 5.3.3.8.

Material selection for reactor vessel is based on a consideration of strength, fracture toughness, fabrication, radiation embrittlement characteristics, operating experiences, and compatibility in the PWR environmental condition.

Appropriateness of the material that has been selected has been proven by successful long-term operating experience of reactor vessels at Korean nuclear power plants as well as experience throughout the world.

5.3.3.3 Fabrication Methods Fabrication of the reactor vessel is described in Subsection 5.3.1.2. Fabrication processes used in the construction of the reactor vessel conform with ASME Section III and 5.3-30 Rev. 2

APR1400 DCD TIER 2 ASME NQA-1. No special manufacturing methods that could compromise the integrity of the reactor vessel are used.

More than 10 reactor vessels in operation for many years or those being constructed in Korea were and are fabricated using similar processes.

The reactor vessel is a vertically mounted cylindrical vessel with a hemispherical lower head welded to the vessel and a removable hemispherical upper closure head. Fabrication of the reactor vessel is based on drawings, fabrication procedures, and examination procedures in accordance with ASME Section III requirements. The reactor vessel shell consists of three shell sections (upper, intermediate, and lower) and a lower head. The length of each shell is adjusted so that the shell does not include the welds in the active core region.

The reactor vessel shells are joined by circumferential welds. Welding procedures applied to the welds of the reactor vessel pressure boundary are qualified in accordance with ASME Section III and Section IX requirements.

Welding processes such as GTAW, SMAW, FCAW, and SAW are used for the reactor vessel. Electroslag welding is not used for the reactor vessel. Detailed information on the welding of reactor vessel is described in Subsection 5.3.1.2.

Other fabrication processes including cutting, bending, drilling, and forming are performed in accordance with manufactures procedures and/or instructions.

5.3.3.4 Inspection Requirements Nondestructive examinations (NDE) performed on the reactor vessel in accordance with ASME Section III are described in Subsection 5.3.1.3.

Ultrasonic examination, and magnetic particle or liquid penetrant methods are performed for reactor vessel pressure boundary forgings and stud bolts in accordance with the requirements of ASME Section III and Section V (Reference 31), as applicable.

Pressure boundary welds of the reactor vessel are examined according to ASME Section III, and satisfy applicable acceptance requirements of ASME Section III. Examinations are performed in accordance with the methods in ASME Section V, if required by ASME Section III.

5.3-31 Rev. 2

APR1400 DCD TIER 2 5.3.3.5 Shipment and Installation The requirements of ASME NQA-1 (Reference 32) are followed for the packaging and shipment of the reactor vessel. Reactor vessels are prepared to be shipped by barge or rail to the site while mounted on the shipping skid used for installation. The vessels are protected by closing all openings (including the top of the vessel) with shipping covers.

The closure heads are shipped with separate skids and covers. Vessel surfaces and covers are sprayed with a strippable coating or wrapped with shrink-wrap for protection against corrosion during shipping and installation.

Following the application of the removable coating or equivalent protection material on the interior surface and prior to wrapping or coating the exterior, all openings are sealed to provide protection against dust, moisture, and/or detrimental materials during shipment and storage at the site.

After the removable coating or equivalent protection material is applied, a desiccant is applied to the interior of the closure head in the area surrounding the nozzles, and the openings in the cover are resealed.

The reactor vessel is cleaned and protected from contamination prior to shipment as described in Subsection 5.3.1.4. Additional information on cleanliness and protection against contamination for austenitic stainless steel materials is provided in Subsection 5.2.3.4.

After arrival at the site and prior to installation, all covers, plugs, and similar items are left in place until they are installed unless otherwise specified. Prior to the welding of interconnecting piping and installation of insulation, the temporary protection material is removed. Only enough strippable protection material for installation requirements is removed. The balance remains in place until just prior to installation of the insulation of the reactor vessel.

The insulation for the reactor vessel is designed to have an annular flow path suitable for the external reactor vessel cooling (ERVC) operation during a severe accident.

5.3.3.6 Operating Conditions Refer to Sections 3.9 and 4.4 for information on design transients and operating conditions, respectively. Pressure-temperature limitations (P-T limits) and protection against 5.3-32 Rev. 2

APR1400 DCD TIER 2 pressurized thermal shock issues for the reactor vessel are described in Subsection 5.3.2.

P-T limits, which are described in Subsection 5.3.2.1, meet the requirements of 10 CFR Part 50 Appendix G, Fracture Toughness Requirements, during operating conditions such as hydrostatic pressure tests or normal operation including anticipated operational occurrences.

Reactor vessel integrity is verified for events or transients causing severe overcooling concurrent with or followed by significant pressure called pressurized thermal shock (PTS).

For such an event of the reactor vessel integrity, the beltline materials satisfy the PTS screening criteria in 10 CFR 50.61, which are described in Subsection 5.3.2.3.

5.3.3.7 Inservice Surveillance Inservice Inspection ASME Section XI requirements are followed for inservice inspection of the reactor vessel.

Preservice inspections are also conducted after installation in accordance with applicable ASME Section III and Section XI requirements.

Inservice inspection for the APR1400 is described in Subsection 5.2.4. A detailed list of inservice and preservice inspections for the reactor vessel is described in Table 5.3-8 and Table 5.3-9. The COL applicant is to provide and develop the inservice inspection and testing program for the RCPB in accordance with ASME Section XI and 10 CFR 50.55a (COL 5.3(5)). The inservice inspection plan is implemented every 10 years.

Accessibility to equipment for maintenance, testing, and inspection is a basic element of the APR1400 design process.

The outer surface of closure head and closure head nozzles beyond the peripheral nozzles can be accessed by removing the head removable insulation panels. Visual inspections around each nozzle on the head surface can also be applied using remote inspection devices.

The head insulation is to maintain the gap from the surface of top head by approximately 2.5 inches to allow access for the inspection devices. The closure head is available for inspection whenever it is removed, and its removal makes available the vessel closure flange, the flange-to-shell weld, closure stud holes and ligaments, and the closure studs and nuts. Each control element drive mechanism is removable as a unit through a closure at the top of its housing. Because many of the reactor vessel closure head examinations are 5.3-33 Rev. 2

APR1400 DCD TIER 2 done from the underside of the head, the head laydown area provides access for examinations.

The closure head stud bolts, nuts, and washers are inspected periodically using visual magnetic particle and/or ultrasonic examinations.

All internals of the reactor vessel (which is an open structure offering insignificant impediment to access) are removable, making the entire inner surface of the vessel including the beltline welds, and the weld zones of the internal load-carrying structure attachments, available for the required surface and volumetric inspections. For interim inspections of the vessel, nozzle-to-shell welds and inner radii of the outlet nozzles are accessible from inside the reactor vessel by using remote automated equipment without removing the vessel internals.

The outside surface of the bottom head of the reactor pressure vessel is manually examined from outside of the vessel, and an access tunnel is therefore provided to allow personnel into the area below the bottom head. Insulation is provided by removable panels over the bottom head weld seams.

Material Surveillance Program The reactor vessel surveillance program conforms to the requirements of Appendix H of 10 CFR Part 50 and ASME Section XI as described in Subsection 5.3.1.6. The design of the program is based on ASTM E185.

Tensile test specimens and Charpy impact test specimens are included to corroborate the post-irradiation surveillance data and fracture toughness specimens to enable determination of fracture toughness properties before and after irradiation. The number of standard Charpy specimens that are required by ASTM E185 are included in reactor surveillance program to increase the accuracy in defining post-irradiation index temperatures.

When combined with the use of highly radiation-resistant materials in the beltline of the reactor vessel, the surveillance program provides reasonable assurance of the integrity of the reactor vessel in terms of strength and fracture resistance.

5.3-34 Rev. 2

APR1400 DCD TIER 2 5.3.3.8 Threaded Fasteners The bolting material for the reactor vessel closure head is fabricated from SA 540 B24 Class 3 material. This material conforms to the requirements of 10 CFR Part 50, Appendix G and the intent of NRC RG 1.65 (Reference 33). Nondestructive examination is performed according to ASME Section III, NB-2580, during the manufacturing process.

Detailed information concerning the reactor vessel stud bolts and examinations applied to provide reasonable assurance of the integrity of the bolts is provided in Subsections 5.3.1.7 and 3.13.

The reactor vessel bolting materials that are used to provide reasonable assurance of the integrity of bolts are described in Subsection 5.3.1.7 and Section 3.13.

5.3.4 Combined License Information COL 5.3(1) The COL applicant is to provide a reactor vessel material surveillance program for a specific plant.

COL 5.3(2) The COL applicant is to provide plant-specific surveillance capsule data to benchmark APR1400-Z-A-NR-14015-P and demonstrate applicability to the specific plant.

COL 5.3(3) The COL applicant is to develop P-T Limit curves based on plant-specific data.

COL 5.3(4) The COL applicant is to verify the RTPTS value and the USE at EOL based on plant-specific material property and neutron fluences.

COL 5.3(5) The COL applicant is to provide and develop the inservice inspection and testing program for the RCPB, in accordance with ASME Section XI and 10 CFR 50.55a.

5.3.5 References

1. 10 CFR Part 50, Appendix A, General Design Criteria for Nuclear Power Plants, U.S. Nuclear Regulatory Commission.

2. 10 CFR 50.55a, Codes and Standards, U.S. Nuclear Regulatory Commission.

5.3-35 Rev. 2

APR1400 DCD TIER 2

3. 10 CFR 50.60, Acceptance Criteria for Fracture Prevention Measures for Light Water Nuclear Power Reactors for Normal Operation U.S. Nuclear Regulatory Commission.

4. 10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, U.S. Nuclear Regulatory Commission.

5. 10 CFR Part 50, Appendix G, Fracture Toughness Requirements, U.S. Nuclear Regulatory Commission.

6. 10 CFR Part 50, Appendix H, Reactor Vessel Material Surveillance Program Requirements, U.S. Nuclear Regulatory Commission.

7. NUREG-0800, Standard Review Plan, BTP 5-3, Fracture Toughness Requirements, Rev. 2, U.S. Nuclear Regulatory Commission, March 2007.

8. ASME Boiler and Pressure Vessel Code,Section III, Rules for Construction of Nuclear Facility Components, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

9. Regulatory Guide 1.50, Control of Preheat Temperature for Welding of Low-Alloy Steel, Rev. 1, U.S. Nuclear Regulatory Commission, March 2011.

10. ASME Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

11. Regulatory Guide 1.31, Control of Ferrite Content in Stainless Steel Weld Metal, Rev. 4, U.S. Nuclear Regulatory Commission, October 2013.

12. Regulatory Guide 1.34, Control of Electroslag Weld Properties, Rev. 1, U.S. Nuclear Regulatory Commission, March 2011.

13. Regulatory Guide 1.28, Quality Assurance Program Criteria (Design and Construction), Rev. 4, U.S. Nuclear Regulatory Commission, June 2010.

14. Regulatory Guide 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components, Rev. 1, U.S. Nuclear Regulatory Commission, March 2011.

5.3-36 Rev. 2

APR1400 DCD TIER 2

15. Regulatory Guide 1.44, Control of the Processing and Use of Stainless Steel, Rev. 1, U.S. Nuclear Regulatory Commission, March 2011.

16. Regulatory Guide 1.71, Welder Qualification for Area of Limited Accessibility, Rev. 1, U.S. Nuclear Regulatory Commission, March 2007.

17. Regulatory Guide 1.99, Radiation Embrittlement of Reactor Vessel Materials, Rev. 2, U.S. Nuclear Regulatory Commission, May 1988.

18. Regulatory Guide 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence, Rev. 0, U.S. Nuclear Regulatory Commission, March 2001.

19. ASTM E185-1982, Design of Surveillance Programs for Light-Water Moderated Nuclear Power Reactor Vessels, American Society for Testing and Materials, 1982.

20. ASTM E208-1991, Standard Test Method for Conducting Drop-Weight Test to Determine Nil-Ductility Transition Temperature of Ferritic Steels, Rev. A, American Society for Testing and Materials, 1991.

21. ASTM E23-2007, Standard Test Methods for Notched Bar Impact Testing of Metallic Materials, Rev. A, American Society for Testing and Materials, 2007.

22. ASTM A370-2010, Standard Test Methods and Definitions for Mechanical Testing of Steel Products, American Society for Testing and Materials, 2010.

23. ASTM E8/8M-2009, Standard Test Methods for Tension Testing of Metallic Materials, American Society for Testing and Materials, 2009.

24. ASTM E21-2009, Standard Test Methods for Elevated Temperature Tension Tests of Metallic Materials, American Society for Testing and Materials, 2009.

25. ASTM E1820-2010, Standard Test Method for Measurement of Fracture Toughness, Rev. A, American Society for Testing and Materials, 2010.

26. ASTM E1921-2010, Standard Test Method for Determination of Reference Temperature, To, for Ferritic Steels in the Transition Range, American Society for Testing and Materials, 2010.

5.3-37 Rev. 2

APR1400 DCD TIER 2

27. ASME Section II, SA-540 Specification for Alloy-Steel Bolting Materials for Special Applications, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

28. Welding Research Council Bulletin 175, Pressure Vessel Research Committee (PVRC) Recommendations on Toughness Requirements for Ferritic Materials, Welding Research Council, PVRC Ad Hoc Group on Toughness Requirements, August 1972.

29. APR1400-Z-M-NR-14008-P, Pressure-Temperature Limits Methodology for RCS Heatup and Cooldown, Rev. 1, KHNP, January 2018.

30. 10 CFR 50.61, Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock Events, U.S. Nuclear Regulatory Commission.

31. ASME Boiler and Pressure Vessel Code,Section V, Nondestructive Examination, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

32. ASME Boiler and Pressure Vessel Code, NQA-1, Quality Assurance Requirements for Nuclear Facility Applications, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

33. Regulatory Guide 1.65 Materials and Inspections for Reactor Vessel Closure Studs, Rev. 1, U.S. Nuclear Regulatory Commission, April 2010.

5.3-38 Rev. 2

APR1400 DCD TIER 2 Table 5.3-1 Total Quantity of Specimens Number of Specimens Base Weld Type of Specimen Orientation Metal Metal HAZ (1) Total Drop weight Transverse 12 12 12 36 Standard Charpy Longitudinal 114 - - 114 Transverse 114 114 114 342 Precracked Charpy Longitudinal 66 - - 66 Transverse 66 66 - 132 Compact tension 1T longitudinal 4 - - 4 1/2T longitudinal 28 - - 28 1T transverse 8 8 - 16 1/2T transverse 28 28 - 56 Tensile test Longitudinal 30 - - 30 Transverse 30 30 - 60 Total 500 258 126 884 (1) Heat-affected zone 5.3-39 Rev. 2

APR1400 DCD TIER 2 Table 5.3-2 Type and Quantity of Specimens for Baseline Tests Number of Specimens Base Weld Type of Specimen Orientation Metal Metal HAZ (1) Total Drop weight Transverse 12 12 12 36 Standard Charpy Longitudinal 24 - - 24 Transverse 24 24 24 72 Precracked Charpy Longitudinal 12 - - 12 Transverse 12 12 - 24 Compact tension 1T longitudinal 4 - - 4 1/2T longitudinal 4 - - 4 1T transverse 8 8 - 16 1/2T transverse 4 4 - 8 Tensile test Longitudinal 12 - - 12 Transverse 12 12 - 24 Total 128 72 36 236 (1) Heat-affected zone 5.3-40 Rev. 2

APR1400 DCD TIER 2 Table 5.3-3 Type and Quantity of Specimens for Irradiated Tests Number of Specimens Base Weld Type of Specimen Orientation Metal Metal HAZ (1) Total Standard Charpy Longitudinal 90 - - 90 Transverse 90 90 90 270 Precracked Charpy Longitudinal 54 - - 54 Transverse 54 54 - 108 Tensile test Longitudinal 18 - - 18 Transverse 18 18 - 36 1/2T Compact Tension Longitudinal 24 - - 24 Transverse 24 24 - 48 Totals 372 186 90 648 (1) Heat-affected zone 5.3-41 Rev. 2

APR1400 DCD TIER 2 Table 5.3-4 Type and Quantity of Specimens Contained in Each Irradiation Capsule Assembly Number of Specimens Standard Precracked Type of Specimen Charpy 1/2T CT Charpy Tension Total Base metal (longitudinal) 15 4 9 3 31 Base metal (transverse) 15 4 9 3 31 Weld metal 15 4 9 3 31 Heat-affected zone 15 - - - 15 Total 60 12 27 9 108 5.3-42 Rev. 2

APR1400 DCD TIER 2 Table 5.3-5 Material for Neutron Threshold Detectors Threshold Material Reaction Energy (MeV) Half-Life 93 93m Niobium Nb (n, n`) Nb 0.5 16.4 years 237 Neptunium Np (n, f) 137Cs 0.5 30.2 years 238 Uranium U (n, f) 137Cs 1.5 30.2 years 54 54 Iron Fe (n, p) Mn 2.2 312.5 days 58 58 Nickel Ni (n, p) Co 2.1 70.78 days 63 Copper Cu (n, ) 60Co 5.0 5.27 years 46 46 Titanium Ti (n, p) Sc 4.4 83.83 days 59 60 Cobalt Co (n, ) Co Thermal 5.27 years 5.3-43 Rev. 2

APR1400 DCD TIER 2 Table 5.3-6 Composition and Melting Points of Candidate Materials for Temperature Monitors Composition, Melting Temperature, wt% °C (°F)

Cd - 17.4 Zn 266 (511)

Au - 20.0 Sn 280 (536)

Pb - 2.5 Ag 304 (580)

Pb - 1.75 Ag - 0.75 Sn 310 (590) 5.3-44 Rev. 2

APR1400 DCD TIER 2 Table 5.3-7 Capsule Assembly Removal Schedule Azimuthal Target Fluence (2) Design Maximum (1)

Capsule Location Removal Time (n/cm2) Fluence (3) (n/cm2)

A 217 ° 6 EFPY 0.82 x 1019 1.0 x 1019 B 37 ° 15 EFPY 1.83 x 1019 2.6 x 1019 C 224 ° 32 EFPY 3.75 x 1019 5.4 x 1019 D 323 ° EOL 6.44 x 1019 9.5 x 1019 E 44 ° Standby -

F 143 ° Standby -

(1) Schedule may be modified to coincide with the refueling outages or scheduled shutdowns most closely approximating the withdrawal schedule.

(2) Best estimate fluences (best estimate values of expected neutron fluence) at specimen locations in each capsule with +/-16.28% uncertainty (3) Design maximum or conservative fluence values at the reactor vessel inside surface with +/-20%

uncertainty, which are used to determine the withdrawal schedule 5.3-45 Rev. 2

APR1400 DCD TIER 2 Table 5.3-8 Inspection Plan for Reactor Vessel Materials Requirements Procurement Manufacturing Preservice Inservice Forgings: Shell and Flange MT MT (1) - -

UT Forgings: Closure Head MT MT (1) VT (2) VT ( 2)

UT Stud Bolts, Nuts and MT MT (1) UT (3) UT (3)

Washers UT VT (3) VT (3)

Forgings: Vessel Nozzle MT MT (1) - -

UT Closure Head Nozzle PT PT (1) ECT (4) -

UT Closure Head Vent Pipe PT PT (1) ECT (4) -

UT Attachments: Ferritic UT and MT MT (1) - -

Material Attachments: Stainless Steel UT and PT PT (1) - -

and A690 Alloy ECT =Eddy current testing (1) Only for machined surfaces MT = Magnetic particle testing (2) Only for closure head dome portion PT = Dye-penetrant testing (3) UT applicable for stud bolts, VT applicable for nuts and washers RT = Radiographic testing for stud bolts: UT UT = Ultrasonic testing for nuts and washers: VT VT =Visual testing (4) Only for inner surfaces of Alloy 690 materials 5.3-46 Rev. 2

APR1400 DCD TIER 2 Table 5.3-9 Inspection Plan for Reactor Vessel Welds Requirements Manufacturing Preservice Inservice Full penetration welds : Pressure RT UT UT boundary ferritic forgings UT PT (1) PT (1)

MT J-groove welds and vent pipe head PT (2) ECT ECT nozzles DVI nozzle to safe end welds RT UT UT UT PT PT PT Attachment welds to pressure MT or PT - -

boundary Cladding UT VT VT PT (1) Only for closure head to flange welds (2) Every 1.3 cm (0.5 in) thickness of weld and final weld surface 5.3-47 Rev. 2

APR1400 DCD TIER 2 Table 5.3-10 RTPTS for the APR1400 Reactor Vessel Materials at EOL (60 Years)

Initial Chemistry Screening RTNDT Fluence Factor (2) RTPTS Margin (3) RTPTS Criterion Material (C(F)) Factor (1) (C(F)) (C(F)) (C(F)) (C(F)) (C(F))

Lower Shell Course -23.3 11.1 16.8 16.8 10.2 132.2 1.51 (beltline (-10) (20) (30.2) (30.2) (50.4) (270) material)

Weld Material -12.2 20.8 31.4 31.1 50.3 148.9 1.51 (G-2 & G-3) (10) (37.5) (56.6) (56) (122.6) (300)

-12.2 24.4 132.2 Head Flange negligible NA (4) NA (4) NA (4)

(10) (44.0) (270)

-12.2 24.4 132.2 Vessel Flange negligible NA (4) NA (4) NA (4)

(10) (44.0) (270)

-12.2 24.4 132.2 Inlet Nozzles negligible NA (4) NA (4) NA (4)

(10) (44.0) (270)

-12.2 24.4 132.2 Outlet Nozzles negligible NA (4) NA (4) NA (4)

(10) (44.0) (270)

-12.2 24.4 132.2 DVI Nozzles negligible NA (4) NA (4) NA (4)

(10) (44.0) (270)

(1) Fluence Factor = f(0.28-0.10log f), f = Fluence at Limiting Case, 9.5 x 1019 n/cm2.

(2) Chemistry Factor with Chemical Composition of Cu 0.03 wt% and Ni 1.00 wt% for the lower shell course; Cu 0.05 wt% and Ni 0.10 wt% for the weld material; and Cu 0.07 wt% and Ni 1.00 wt% for the flanges and nozzles.

(3) Margin = 22 + 2 where:

u = 0

= lesser of 17F or 0.5xRTPTS for the forging and lesser of 28F or 0.5 x RTPTS for the weld material.

(4) Not applicable because fast neutron fluence is not significant.

5.3-48 Rev. 2

APR1400 DCD TIER 2 Lock Assembly Wedge Coupling Assembly Upper Compartment Connecting Spacer Assembly Center Compartment Assembly Lower Compartment Assembly Figure 5.3-1 Typical Surveillance Capsule Assembly 5.3-49 Rev. 2

APR1400 DCD TIER 2 Stud Wedge Coupling End Cap Charpy Impact Specimens Flux Monitor Housing Connecting Spacer Charpy Impact Specimens Spacers Tension Specimens Tension Specimen Housing 1/2 T Compact Tension Specimens Rectangular Tubing Wedge Coupling End Cap Figure 5.3-2 Upper Compartment Assembly 5.3-50 Rev. 2

APR1400 DCD TIER 2 Stud Wedge Coupling End Cap Charpy Impact Specimens Precracked Charpy Impact Specimens Connecting Spacer Precracked Charpy Impact Specimens Flux Spectrum Monitor (Cadmium Shielded)

Stainless Steel Tubing Flux Monitor Housing Cadmium Shield Stainless Steel Vanadium Tubing Tubing Threshold Detector Threshold Detector Quartz Tubing Weight Temperature Monitor Temperature Monitor Housing Tension Specimens Low Melting Alloy Tension Specimen Housing 1/2 T Compact Tension Specimens Rectangular Tubing Wedge Coupling End Cap Figure 5.3-3 Center Compartment Assembly 5.3-51 Rev. 2

APR1400 DCD TIER 2 Stud Wedge Coupling End Cap 1/2 T Compact Tension Specimens Rectangular Tubing Tension Specimens Tension Specimen Housing Precracked Charpy Impact Specimens Connecting Spacer Flux Monitor Housing Precracked Charpy Impact Specimens Charpy Impact Specimens Wedge Coupling End Cap Figure 5.3-4 Lower Compartment Assembly 5.3-52 Rev. 2

APR1400 DCD TIER 2 Outlet Nozzle 180° 217° 224° 143° Surveillance Surveillance Capsule Capsule Assembly Assembly Inlet Nozzle 323° 44° 37° Fuel Assembly 0° Core Shroud Core Support Barrel Reactor Vessel Figure 5.3-5 Location of Surveillance Capsule Assemblies (Plan View) 5.3-53 Rev. 2

APR1400 DCD TIER 2 Inlet Nozzle Outlet Nozzle Fuel Assembly Surveillance Core Shroud Capsule Assembly Core Center Core Support Barrel Reactor Vessel Figure 5.3-6 Location of Surveillance Capsule Assemblies (Elevation View) 5.3-54 Rev. 2

APR1400 DCD TIER 2 Figure 5.3-7 Pressure-Temperature Limit Curve (60 years) 5.3-55 Rev. 2

APR1400 DCD TIER 2 NOZZLE SCHEDULE CEDM UPPER PRESSURE SERVICE HOUSING ASSEMBLY COOLANT INLET COOLANT OUTLET CEDM AND CEDM MOTOR CEDM AND INSTRUMENTATION HOUSING ASSEMBLY INSTRUMENTATION NOZZLES NOZZLES IN-CORE INSTRUENTATION VENT-RCGVS SEAL LEAK MONITOR VENT-RCGVS CLOSURE DIRECT VESSEL INJ. STUD (54)

MATING SURFACE SEAL LEAK MONITOR 4.45 m 0.30 m (12") NOM. (14' - 7")

DVI NOZZLE 0.22 m (8.5" ID) HEATED JUNCTION THERMOCOUPLE 4.99 m 1.07 m (42")

0.76 m (30") PROBES (16' - 4.32") OUTLET INLET NOZZLE NOZZLE CORE EXIT THERMOCOUPLE 14.63 m (48')

11.92 m (39' - 1.35")

EFFECTIVE CORE BASE METAL DIAMETER THICKNESS IN CORE REGION 0.23 m (9 1/16")

CLADDING 0.003 m (1/8")

MIN.

4.68 m SNUBBER (15' - 4.43")

CORE STOP FLOW BAFFLE IN-CORE INSTRUMENT NOZZLES Figure 5.3-8 Reactor Vessel Assembly 5.3-56 Rev. 2

APR1400 DCD TIER 2 5.4 Reactor Coolant System Component and Subsystem Design 5.4.1 Reactor Coolant Pumps The reactor coolant pumps provide sufficient forced circulation flow through the reactor coolant system (RCS) to provide reasonable assurance of adequate heat removal from the reactor core during power operation. A low limit on reactor coolant pump flow rate (i.e.,

design flow) is established to provide reasonable assurance that specified acceptable fuel design limits (SAFDLs) are not exceeded. Design flow is derived on the basis of the thermal-hydraulic considerations presented in Subsection 4.4.4.5.1.

The reactor coolant pump and motor assembly in conjunction with the flywheel provide sufficient coastdown flow following loss of power to the pumps to provide reasonable assurance of adequate core cooling.

The reactor coolant pump pressure boundary is designed for the transients given in Table 3.9-1 so the ASME Section III (Reference 1) allowable stress limits are not exceeded for the specified number of cycles. Stress criteria concerning earthquake and pipe rupture conditions are presented in Subsection 3.9.3.

The design overspeed of the reactor coolant pump is 125 percent of normal speed.

5.4.1.1 Pump Flywheel Integrity The RCP flywheel maintains the integrity to prevent the possibility of producing high-energy missiles and excessive vibration of the pump assembly under standstill, normal and anticipated operating condition consistent with the intent of General Design Criteria 1 and 4 (Reference 2) and Regulatory Guide 1.14 (Reference 3).

The flywheel is constructed by a cylindrical shrink fit of the outer wheel to the hub, and then a conical shrink fit between the hub and the shaft. The stresses in the flywheel are a function of three attributes which are the material, the shrink fit, and the rotational speed.

5.4.1.1.1 Material Selection and Fabrication The material used to manufacture the flywheel is produced by a commercially acceptable process that minimizes flaws such as the vacuum melting and degassing process. The flywheel material is a quenched and tempered forging with the German material designation 26NiCrMoV14-5, which is a high strength ductile forged material. This 5.4-1 Rev. 2

APR1400 DCD TIER 2 material meets the requirements described in Subsection 5.4.1.1.2 and 5.4.1.1.3, and its mechanical properties are equal to or exceed SA-508 Class 2, which is a typical U.S. forged flywheel material. One of the attributes that led to selection of this material is its resistance to non-ductile-type failures. This provides adequate fracture toughness properties under operating conditions. No welding is performed on the flywheel. If the flywheel is flame cut, at least 13 mm (1/2 inch) of stock is left on the outer and bore radii for machining to final dimensions.

5.4.1.1.2 Fracture Toughness The KIC of the flywheel material at the normal operating temperature of the flywheel is greater than 165 MPam (150 ksiin), which will be demonstrated by the direct test method.

5.4.1.1.3 Design The flywheel is designed to withstand normal conditions, anticipated transients, loss of coolant accident with the largest mechanical pipe break remaining after application of leak before break as described in Subsection 3.6.3, and a safe shutdown earthquake (SSE) without loss of structural integrity. The flywheel integrity analysis is summarized in the technical report APR1400-A-M-NR-14001-P (Reference 4) which is performed for a stress analysis at standstill, normal and overspeed conditions and a fracture mechanics analysis to predict the critical speed for fracture of the flywheel.

The design overspeed of flywheel is 125 percent of the synchronous speed of the RCP motor. The design overspeed is at least 10 percent greater than the highest anticipated overspeed of the pump. The highest anticipated overspeed is predicted for loss of coolant accident with the largest break size remaining after the application of leak before break, as described in Subsection 3.6.3. The largest break size remaining after the application of leak before break that may affect the maximum overspeed of the RCP is a 10.16 cm (4 in) pressurizer spray line.

The shaft and bearings supporting the flywheel are able to withstand any combination of the loads of normal operation, anticipated transients, loss of coolant accident with the largest mechanical pipe break remaining after application of leak before break as described in Subsection 3.6.3, and an SSE.

5.4-2 Rev. 2

APR1400 DCD TIER 2 The flywheel is accessible for 100 percent in-place volumetric ultrasonic inspections. The flywheel-motor assembly is designed to allow such inspection with a minimum of motor disassembly.

5.4.1.1.4 Test and Inspection

a. Each flywheel and hub is tested at the design overspeed.

b. The flywheel and the hub are subjected to a magnetic particle or liquid-penetrant examination per ASME Section III before final assembly.

c. Each finished flywheel and its hub is subjected to a 100 percent volumetric ultrasonic inspection from the flat surface as per ASME Section III. The flywheel inspection is performed after final machining and the overspeed test.

The ultrasonic inspection for the hub is performed before final machining. Post final machining, the hub is inspected by dye penetrant test or magnetic particle test.

d. The inservice inspection program includes ultrasonic examinations of the flywheel, excluding the hub, at about three and one-third year intervals, during the refueling or maintenance shutdown coinciding with the inservice inspection schedule as required by ASME Section XI (Reference 5). Removal of the flywheel or hub is not required. The hub is inspected by dye penetrant test or magnetic particle test.

e. A surface examination of all exposed surfaces and a 100 percent volumetric examination by ultrasonic methods are conducted at approximately 10-year intervals during the plant shutdown coinciding with the inservice inspection schedule as required by ASME Section XI. This examination is limited to the flywheel, excluding the hub.

f. Each flywheel receives a preservice baseline inspection that incorporates the methods defined above for an inservice inspection. Examination procedures and acceptance criteria are determined in accordance with ASME Section III.

g. The observed flaw depth from flywheel and hub inspections shall be limited to less than 12.7 mm (0.5 in).

5.4-3 Rev. 2

APR1400 DCD TIER 2 5.4.1.2 Description Table 5.4.1-1 lists the principal parameters of the reactor coolant pumps, and Figure 5.4.1-1 depicts the arrangement of the pump and motor. Reactor coolant pump supports are described in Subsection 5.4.15. The flow diagram for the reactor coolant pump is given in Figure 5.1.2-2.

The four reactor coolant pumps are vertical, single stage, bottom suction, horizontal discharge, motor-driven centrifugal pumps. The pump impeller is splined and locked to its shaft. Pump shaft alignment is maintained by a water lubricated radial bearing within the pump and by radial and thrust bearings located in the motor stand. The pump and motor shafts are directly connected by a coupling.

The pump rotating assembly is mounted in a diffuser-type pump casing. The pump casing is a one-piece design in accordance with applicable sections of ASME Section III. The one-piece casing reduces the ASME Section XI examination requirements.

The pressure boundary materials used for the reactor coolant pump assembly are listed in Table 5.2-2, and are compatible with the reactor coolant addressed in Subsection 5.2.3.2.1.

The pump shaft assembly is supported by a lower water lubricated journal bearing and an oil lubricated combination journal and thrust bearing. The lower bearing is a conventional hydrodynamic sleeve bearing. The combination journal and thrust bearing consists of two journal bearings and a double-acting tilting pad type thrust bearing. The thrust bearing carries upward thrust during normal operation and downward thrust during operation under low system pressure. Two journal bearings are used to increase shaft stiffness and ensure positive guidance of the shaft assembly during normal operation of the pump.

The shaft seal assembly consists of two face types, mechanical seals in series, with a controlled leakage bypass to provide the same pressure differential across each seal. The seal assembly is designed for the pressure differential of 175.8 kg/cm2 (2,500 psi) and to reduce the leakage pressure from the RCS pressure to the volume control tank pressure. A third, face-type, low-pressure vapor seal at the top is designed to withstand system operating pressure when the pumps are not operating. As indicated in Figure 5.4.1-2, seal injection water enters into the high pressure piping at a point below the water lubricated bearing and is directed through the cyclone filter/jet pump assembly to the high pressure cooler before being injected into seal system. The effluent from the high pressure cooler enters the high pressure side of the first seal and is divided into two flow paths. A 5.4-4 Rev. 2

APR1400 DCD TIER 2 majority of the flow is pumped through the journal bearing by the auxiliary impeller. This cools the journal bearing and minimizes the ingress of contaminants into the seal system.

The second flow path is into the first seal and through a throttle coil to the high pressure side of the second seal. Flow from the second seal continues through another throttle coil to the third seal and then to the volume control tank within the chemical and volume control system. The controlled leakage around the seals is required for seal pressure distribution.

Should injection water fail, controlled bypass leakage comes from the pump casing and passes through the high pressure cooler by natural circulation. As described above, a portion of this water is circulated by the auxiliary impeller through the journal bearing, high pressure cooler and back to the seal area. Leakage past the low-pressure vapor seal is collected and piped to the reactor drain tank.

The temperature of the water in the seal assembly is maintained within acceptable limits by a water-cooled heat exchanger (HX). Water is also injected into the seal area from an external seal injection system. The performance of the shaft seal system is monitored by pressure and temperature sensing devices in the seal system. The seal assembly can be replaced without draining the pump casing or removing the shaft.

The RCP shaft seals are cooled by (1) seal injection water from the CVCS and (2) the component cooling water (CCW) through a high-pressure seal cooler. Pump seal operation may continue indefinitely provided either seal injection water or the CCW is available. The APR1400 design includes an additional support system (i.e., auxiliary charging pump). This system features a positive displacement pump to provide a diverse means of seal injection to the RCPs if the normal means of seal cooling are lost. Detailed descriptions are given in Subsections 9.2.2.3 and 9.3.4.2.

In the event of loss of either seal injection to the seal assembly or loss of CCWS flow to the high-pressure seal cooler, the seal cooling water temperature increases. Performance tests and analyses have shown that a minimum margin of 12.2 °C (22 °F) exists between the seal cooling water outlet temperature and the seal cooling water temperature limit specified by the pump manufacturer.

If there is a simultaneous loss of CCW to all RCP and motor bearing assemblies but seal injection water is available to the seals, the RCP can operate for at least 30 minutes without bearing seizure, which could affect normal RCP coastdown. This is discussed further in Subsection 5.4.1.3.

5.4-5 Rev. 2

APR1400 DCD TIER 2 The seal assemblies are designed to limit seal leakage plus controlled bypass flow per pump to approximately the following values:

All seals functioning (normal) 12.1 L/min (3.2 gpm)

One seal functioning (abnormal) 16.7 L/min (4.4 gpm)

An acoustic leak sensor is provided on the shaft seal housing for use in detecting leakage coming through in the vapor seal of the pump. A description of the acoustic leak monitoring system (ALMS) is provided in Subsection 7.7.1.5.

The need for improved station blackout (SBO) performance has led to selected improvements in the design of the seal. The seal uses an enhanced manufacturing process and improved composition of elastomer materials to provide high temperature seal performance at 300 oC (572 oF) and 163.1 kg/cm²G (2,320 psig). Key materials used in the seals are silicon carbide/graphite compound material for the glide rings (primary seals) and specially treated (high-temperature-resistant) ethylene propylene diene monomer (EPDM) elastomers (secondary seals). Both materials are capable of withstanding long-term exposure to a high temperature and pressure environment. Seal dimensions and normal operational characteristics are basically unchanged from those in pump assemblies in existing operating plants. As the seal is intended to withstand adverse SBO conditions, it is verified by a robust test program which focuses on demonstrating the ability of the seal to survive a long term SBO event and represents simulation of a SBO event lasting up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with and without isolation of the controlled leakage and a test regimen to investigate seal performance under low subcooling conditions. The test results are summarized in Extended Loss of AC Power Capability for APR1400 KSB RCP Seals (Reference 6).

The motor is sized for continuous operation at the flows resulting from a four-pump or one-pump operation with a 1.0 to 0.74 specific gravity of water. The motors are designed to start and accelerate to speed under full load with a drop to 80 percent of normal rated voltage at the motor terminals.

The rotor bearing of RCP motor consists of a lower radial journal bearing and a upper combination journal and thrust bearing. Both bearings are oil lubricated and have oil-to-water coolers, which dissipate heat from the bearings when the machine is rotating.

5.4-6 Rev. 2

APR1400 DCD TIER 2 Each RCP motor is equipped with two air-to-water heat exchangers such that the temperature of motor cooling outlet air discharged to the containment is less than the maximum containment ambient temperature. Electrical insulation of the motor is suitable for a high humidity and high radiation environment.

Each motor is provided with an anti-reverse rotation device. The device is designed to prevent impeller rotation in the reverse direction, assuming each of the following two conditions: (1) motor starting torque if the motor was incorrectly wired for reverse rotation and (2) reactor coolant flow through the pump in the reverse direction due to the largest pipe break remaining after the application of leak before break as described in Subsection 3.6.3.

The RCP assembly is equipped with an oil collection system to collect oil leakage. The oil collection system is capable of collecting lube oil from all potential pressurized and unpressurized leakage sites in the RCP assembly. The oil collection system is designed to withstand an SSE.

5.4.1.3 Evaluation The reactor coolant pumps are sized to deliver flow that equals or exceeds the design flow rate utilized in the thermal hydraulic analysis of the RCS. Analysis of steady-state and anticipated transients is performed assuming the minimum design flow rate. Tests are performed to evaluate reactor coolant pump performance during the post-core load hot functional testing to verify adequate flow.

If the offsite and onsite electrical powers are lost, the RCPs are tripped and begin to coast down, and the forced coolant flow through the reactor core gradually declines. Each RCP is designed to coast down at a rate that is slow enough to prevent core damage during the first few seconds of the core flow transient. Reasonable assurance that core damage will be prevented is provided by the flywheel in each RCP motor, which provides an additional rotating inertia to extend the pump coastdown. The total rotating inertia of the pump, motor, and flywheel is no less than 6,717 kg-m2 (159,400 lbs-ft2). The coastdown capability of the pump is reasonably assured to be maintained following a loss of offsite or onsite electrical power combined with an SSE, as addressed in Subsection 3.2.1. Core flow transients are addressed in Subsection 15.3.1.

Leakage from the pump via the pump shaft is controlled by the shaft seal assembly.

Reactor coolant entering the seal chambers is cooled and collected in closed systems to 5.4-7 Rev. 2

APR1400 DCD TIER 2 prevent reactor coolant leakage to containment. Instrumentation is provided to monitor seal operation.

The design overspeed of the flywheel is 125 percent of normal speed. A test of each flywheel at the design overspeed is performed prior to assembly to confirm that no missile is generated. Pump flywheel integrity is described in Subsection 5.4.1.1.

In the event of a break that is not eliminated by leak before break and that could result in increased flow through the pump tending to accelerate the pump impeller, the highest predicted pipe break induced overspeed is less than the lowest critical speed of the flywheel.

The pump and motor oil-lubricated bearings are lubricated by internal oil systems. Each bearing assembly has an internal oil system consisting of an oil bath or a force-feed type system. During normal operation, no external pumps are required because pumping action is accomplished by internal pumping devices. Lubricating oil is cooled by cooling coils submerged in the oil sumps. Both sumps and cooling coils are internal to the pump and motor structural frame, and are designed for seismic Category I operation. They adhere to ASME Section III, Class 3, as a guide for design and construction. Although the pump-motor assembly operation is not considered necessary for plant safety, this design minimizes the direct effects of seismic events on the reactor coolant pump and motor assembly oil lubricating systems so that adequate coastdown characteristics are not detrimentally affected.

Bearing metal temperatures, oil flow or pressure, oil levels, cooling water flow, and temperature are monitored and alarmed in the control room.

In the unlikely event that component cooling water to the reactor coolant pump and motor oil lubricating systems is not available or that an oil leak occurs during operation, the operator is alerted as soon as cooling water to the oil system is lost, and has at least 30 minutes in which to reduce power, if necessary, isolate the cooling water, and shut the reactor coolant pump motor assembly down to prevent bearing seizure. In the remote possibility of a simultaneous loss of component cooling water to all reactor coolant pump motor assemblies, 30 minutes is adequate to secure the plant and maintain the normal coastdown capabilities of the reactor coolant pump motor assemblies.

A shaft seizure due to bearing failure is unlikely during a loss of component cooling water event for the following reasons:

5.4-8 Rev. 2

APR1400 DCD TIER 2

a. The design is such that the heat generated in the bearing, normally carried away by the cooling water, is removed through alternate paths. The lube oil sump baths surrounding the bearings, the stagnant cooling water remaining in the heat exchanger coils, and the bearing and sump assembly metal masses, all act as heat sinks. In addition, conduction down the pump shaft and radiation from the outer sump shell help reduce the temperature increase.

b. The rotation of the bearing assemblies provides reasonable assurance of adequate oil flow and mixture of heated oil so the heat transfers as described above.

c. In the event that the oil temperature increases such that the viscosity degrades significantly, the design of the thrust bearing provides reasonable assurance that the bearing will continue to produce a hydrodynamic film to preclude metal-to-metal contact.

If the event of an oil leak, redundant instrumentation alerts the operator to shut down the reactor coolant pump motor assembly, thereby avoiding bearing damage.

In the event of an oil leak, the separation of lubrication systems limits the problem to a single reactor coolant pump.

The loss of the oil in the bearing oil reservoir would not result in bearing seizure for the following reasons:

a. Temperature and oil level monitors provide appropriate indication of an abnormal condition.

b. The vibration monitoring device furnished on the pump responds to bearing degradation and allows the operator to shut down the pump.

c. If the above protective measures fail, the high torque produced by the motor causes a slow breakdown of the bearings but not a rapid shaft seizure. Industry experience indicates that the babbitt bearing surfaces wear away and the bearing pads and sleeves are badly worn but the shaft continues to rotate.

If the extremely remote possibility of bearing seizure occurs while the reactor coolant pump motor assembly is in operation, adequate flow to the core is available from the other reactor coolant pump motor assemblies as demonstrated in Subsection 15.3.3.

5.4-9 Rev. 2

APR1400 DCD TIER 2 Figure 5.1.2-2 shows a separate oil lift system that is required for startup of the pump assembly. The oil lift system furnishes high pressure oil to the pump assembly thrust bearings, thereby lifting the rotor and reducing bearing friction during pump startup.

Interlocking devices are furnished, which prevent pump startup until oil lift flow is established. The oil lift system shuts down automatically when the pump reaches full speed. Because an oil lift is not necessary during normal operation, an oil leak in this system does not cause a bearing failure.

5.4.1.4 Tests and Inspections The reactor coolant pump pressure boundary is nondestructively inspected as required by ASME Section III for Class 1 components. The pump undergoes a hydrostatic pressure test in the vendors shop and with the RCS. Inservice inspection of the pump pressure boundary is performed during the plant life in accordance with ASME Section XI.

The pump assembly is performance tested in the vendors shop over at least the normal operating range in accordance with ASME PTC 8.2 (Reference 7). The tests also demonstrate the ability of the pumps to function under the various operating conditions specified. Tests commonly performed are hot and cold performance and stop-start cycling.

Vibrations are monitored at several places on the pump during shop testing. In addition to meeting an absolute criterion for vibration amplitude, the test results are examined for evidence of critical speed problems.

The pump motors undergo a routine test in accordance with NEMA MG-1 (Reference 8).

This test also confirms that the motors are within their vibration limits. One motor is used as the driver for the pump assemblies during the pump manufacturers shop testing.

To the greatest extent practicable, all conditions of operation within the reactor coolant pump are duplicated.

Reactor coolant pump flywheel inspections and testing are described in Subsection 5.4.1.1.

5.4.1.4.1 Reactant Coolant System Flow Rate Verification Initial verification of the RCS flow rate is made during the plant startup tests. RCS flow rates are measured during the pre- and post-core hot functional tests, and during the power ascension tests. The objective of these tests is to verify that the RCS flow rate meets the flow rate range in Subsection 3.4.1 of the Technical Specifications (Chapter 16).

5.4-10 Rev. 2

APR1400 DCD TIER 2 5.4.2 Steam Generators The two steam generators are designed to transfer 4,000 MWt from the RCS to the secondary system, producing approximately 8.141 x 106 kg/hr (17.95 x 106 lb/hr) of 70.30 kg/cm2A (1,000 psia) saturated steam, when provided with 232.2 °C (450 °F) feedwater. Moisture separators and steam dryers in the shellside of the steam generator limit the moisture content of the steam to maximum 0.25 wt% during normal operation at full power. The steam generator design parameters are listed in Table 5.4.2-1. The steam generators, including the tubes, are designed to withstand the consequences of the design transients of Table 3.9-1 so that the ASME Code allowable stress limits are not exceeded for the specified number of cycles. All transients have been established based on conservative assumptions of operating conditions in consideration of supporting system design capabilities.

The steam generator is designed to provide reasonable assurance that critical vibration frequencies are well out of the range that are expected during normal operation and during abnormal conditions. The tubing and tubing supports are designed and fabricated with considerations given to both secondary side flow induced vibrations and reactor coolant pump induced vibrations. In addition, the steam generator assemblies are designed to withstand the blowdown forces resulting from a steam line break and feedwater line break.

The two accidents are not considered simultaneously.

Vapor bubbles are generated if the static pressure in a flowing liquid is dropped below the saturated pressure corresponding to the liquid temperature. The region of the flow where bubbles exist is the cavitating region, whereas the observed damage is at the location of the bubble collapse. In the APR1400 steam generator, a pressure drop inside the tubes is not as significant as a cavitation, which can occur because the operating pressure of 158.19 kg/cm2A (2,250 psia) inside the tubes is much higher than the saturation pressure of 121.13 kg/cm2A (1,723 psia) of the maximum coolant temperature of 323.8 °C (615 °F) in the steam generator, and the flow paths of tubes from the tube inlet to the tube outlet are smooth enough not to cause a sudden drop of velocity of flow. The secondary side flow path outside-tubes is also smooth on the secondary side so that cavitation does not occur.

No cavitation has been reported to date in the OPR1000 steam generators which are almost the same in the design concept and configuration to the APR1400 steam generators.

The steam generator tube material is thermally treated NiCrFe Alloy 690 (ASME SB-163).

The outside diameter is 19.05 mm (0.75 in) with 1.0668 mm (0.042 in) nominal wall 5.4-11 Rev. 2

APR1400 DCD TIER 2 thickness. Straight portion of tube is triangular array with 25.4 mm (1.00 in) pitch. U-bend portion of tube is rotated square array with 31.27 mm (1.231 in) pitch. An analysis is performed to establish the maximum allowable tube wall degradation for the steam generator tubes in accordance with the requirements of NRC RG 1.121 (Reference 9).

Load conditions considered are maximum tube differential pressures during normal operation and faulted load conditions. The margin of safety against tube rupture under normal operating condition is not less than 3.0, and the margin of safety against tube failure under postulated accidents, such as a loss of coolant accident, main steam line break, or feedwater line break concurrent with an SSE, are consistent with the margin of safety determined by the stress limits specified in the ASME Code.

The more probable modes of tube failure, which may result in leaks, are the results from involving the occurrence of pinholes, small cracks or wear in the tubes and of cracks in the seal welds between the tubes and tubesheet. Detection and control of steam generator tube leakage are described in Subsection 5.2.5.

The concentration of radioactivity in the secondary side of the steam generators is dependent on the concentration of radionuclides in the reactor coolant, the primary-to-secondary leak rate, and the rate of steam generator blowdown. The specific activities that are expected in the secondary side of the steam generators during normal operation are given in Section 11.1.

The recirculation water within the steam generators contains volatile additives necessary for proper chemistry control. These and other chemistry considerations for the steam generators are discussed in Subsection 10.3.5.

5.4.2.1 Steam Generator Materials 5.4.2.1.1 Selection, Processing, Testing, and Inspection of Materials The pressure boundary materials used in the construction of the steam generators are listed in Table 5.2-2. These materials are in accordance with ASME Section III.

The selection, fabrication, testing, and inspection of all steam generator pressure boundary materials meet the applicable ASME Code requirements as described in Subsection 5.2.3.

The corrosion-resistant cladding (NiCrFe alloy or austenitic stainless steel) on the tubesheet and on other primary side components is weld-deposited, fabricated, and inspected 5.4-12 Rev. 2

APR1400 DCD TIER 2 according to the requirements in Section III NB and Part QW of Section IX of the ASME Code. The thickness of tubesheet cladding and base metal is 4.8 mm (0.19 in) and 647.7 mm (25.5 in) minimum, respectively.

There is no austenitic stainless steel that is used for the primary and secondary side pressure boundary of the APR1400 steam generators.

5.4.2.1.2 Steam Generator Design 5.4.2.1.2.1 Design Description The steam generator is illustrated in Figure 5.4.2-1. Moisture-separating equipment in the shell side of the steam generators limits moisture content of the exit steam. Manways and handholes are provided for access to the steam generator internals. Reactor coolant enters at the bottom of each steam generator through a single inlet nozzle, flows through the U-tubes, and leaves through two outlet nozzles. A vertical divider plate separates the inlet and outlet plenums in the lower head.

The steam generator with integral economizer (Figures 5.4.2-2 and 5.4.2-3) is in most respects similar to earlier U-tube recirculating steam generators. The basic difference is that instead of introducing feedwater only through a sparger ring to mix with the recirculating water flow in the downcomer channel, feedwater is also introduced into a separate, but integral section of the steam generator. A semi-cylindrical section of the tube bundle, at the cold leg or exit end of the U-tubes, is separated from the remainder of the tube bundle by vertical divider plates. Feedwater is introduced directly into this section and pre-heated before discharge into the evaporator section.

The economizer section is designed in consideration of operating transients, startup and standby operation, and accident conditions such as loss of feedwater flow and feedwater line break. The structural design of the various parts is adequate to withstand the thermal and pressure loadings from these various conditions, consistent with the appropriate load classifications and design rules in ASME Section III, Appendix G.

The components of the steam generator economizer section are designed for the primary stresses that occur due to the blowdown associated with a feedline break. The divider plates, which separate the economizer region from the evaporator region of the secondary side, are supported from the vessel shell and the central cylindrical support welded to the tubesheet. This divider cylinder becomes an extension of the primary tubesheet stay 5.4-13 Rev. 2

APR1400 DCD TIER 2 cylinder, though less massive, and extends the full height of the economizer. The tube support/flow baffle plates are supported from the vessel shell, the divider cylinder, and the tubesheet via an array of support rods. The support rods, which also serve as support plate spacers, are solid and designed for either tensile or buckling loads. Thin plates are not used because of the potential for collapse when subjected to differential pressure.

The lower portion of the evaporator section and the downcomer channel occupy only half of the steam generator cross section. The effect of this non-symmetry is considered in the calculation of the recirculation ratio, internal flow considerations, and the design of the tube support structures.

The steam-water mixture leaving the vertical U-tube heat transfer surface enters the separators, which produce a centrifugal motion in the mixture and separate the water particles from the steam. The water exits from the perforated separator housing and recirculates through the downcomer channel to repeat the cycle. Final drying of the steam is accomplished by passage of the steam through corrugated plate dryers.

The steam generators are designed to provide a margin of 10 percent of the total heat transfer surface area for the plugging.

A recirculation system allows the circulation of water through the steam generator during wet lay-up and the addition of chemical cleaning agents. The recirculation system consists of a distribution ring located above the tube bundle below the normal water level with connecting piping to the blowdown system. This piping needs a nozzle penetration through the pressure boundary (shell). Suction is taken at the blowdown nozzle and recirculated through the distribution ring. The recirculating header can effect a rapid changeover of the steam generator inventory if a chemical intrusion requiring the rapid removal of impurities occurs.

The primary head draining capability is provided by the channel head drains. Tubesheet drains allow secondary side draining. The drain capability enhances access for inspection and maintenance.

In order to enhance the steam generator integrity, the feedwater box is designed to prevent the inflow of foreign objects greater than the 6.35 mm (0.25 in) tube gap through the economizer feedwater region, which is a major path of foreign object inflow, and to remove the foreign objects during the overhaul period.

5.4-14 Rev. 2

APR1400 DCD TIER 2 The steam generator blowdown system (Subsection 10.4.8) is designed for high-flow blowdown. The system is effective in removing particulate accumulations at the tubesheet.

The pressure drop from the steam generator economizer feedwater nozzles to the steam outlet nozzle including the economizer is designed to be less than 3.52 kg/cm2D (50 psid).

The steam generator supports are described in Subsection 5.4.15.

5.4.2.1.2.1.1 Flow-Induced Vibration of the Tube Bundle The tube support system uses the eggcrate grid and upper tube supports, both of which have proven effective in suppressing excessive tube vibration while providing superior thermal hydraulic characteristics for maximum protection against the shell side chemical hideout and tube corrosion. The test data provided the basis for determining acceptable shell side fluid velocities in the most critical regions of the tube bundle, the flow entrance, and the flow exit regions. Based on the test data and results from the shell side flow distribution analysis, the design of tube support spacing is shown to have conservative design margins against the onset of the fluid elastic instability (FEI). The steam generator design configuration possesses the tube vibration stability ratio below the design goal of one.

Tube displacements due to the random turbulent excitation (RTE) are based on the turbulent buffeting methodology of ASME Section III, nonmandatory Appendix N (Reference 10).

Fluid elastic instability (FEI): FEI is the dominant mechanism for inducing the vibrational instability in tube bundles representative of the APR1400 design. This phenomenon occurs when sufficient flow velocity exists to put the tube into motion, which leads to the activation of a feedback mechanism. This causes an ever-increasing amplitude of vibration until (1) a balance is reached between the fluid energy that is absorbed and the energy that is dissipated through damping by the tube or (2) impacting ensues. The pertinent relationships are the critical velocity, effective velocity, and stability ration.

Random turbulent excitation (RTE): In a turbulent fluid flow environment, a tube can extract some of the energy from the fluid that has a frequency at or near the tube span natural frequency. Once the tube is put in motion, it may tend to coordinate the flow in such a way as to make it possible to absorb even higher quantities of fluid energy. ASME Section III non-mandatory Appendix N recommends an analytical methodology for determining tube response (displacements) due to RTE.

5.4-15 Rev. 2

APR1400 DCD TIER 2 Vortex shedding: This mechanism manifests itself in a classic resonance situation when the Von-Karman vortex shedding frequency coincides with a tube span natural frequency.

Theoretically when resonance exists, the magnification factor becomes infinite and even the smallest forcing function can produce vibrational failure. In reality, the forcing function introduces more energy into the system than can be dissipated through damping or a stable level of vibration will be established. However, the design of the tube and tube support for the APR1400 steam generator is not susceptible to the vortex shedding resonance based on the results of the tube vibration program implemented on the tube bundle with tightly packed tube arrays.

To evaluate the flow-induced vibration, the thermal-hydraulic conditions including interstitial fluid velocity, fluid density, void fraction, and steam quality of APR1400 steam generator secondary side are analyzed using EPRIs ATHOS3 computer program specified in Subsection 3.9.1.2.1.11. The design concept of tube support structures for the APR1400 steam generator is identical to that of the OPR1000 steam generator. This design has been used in other nuclear power plants and has proven to effectively suppress flow-induced vibrations of large-sized tube bundles. Refer to Subsection 5.4.2.1.2.2 for detailed descriptions of the tube support structures.

5.4.2.1.2.1.2 Water Hammer at Feedwater Ring Provisions related to the design and operating procedure of economizer-type steam generators are made to prevent the water hammer. A goose-neck design and top-discharge spray nozzle of the downcomer feedwater piping inside the steam generator is included in the design to prevent the generation of steam bubbles regardless of water level. An auxiliary feedwater line is also connected to the downcomer feedwater line, and a plant startup test to confirm that there is no water hammer in the feedwater line is performed.

With respect to the operating procedure, all feedwater flow to the steam generator is directed through the downcomer feedwater nozzle below 20 percent of full power, which eliminates the possibility of a condensation-induced water hammer in the economizer feedwater line.

5.4.2.1.2.1.3 Thermal Stratification at Feedwater nozzle NRC Bulletin 79-13 (Reference 11) addresses the effect of thermal stratification that leads to cracking of the feedwater line.

5.4-16 Rev. 2

APR1400 DCD TIER 2 The APR1400 feedwater lines are designed to minimize thermal stratification. The feedwater lines are angled downward from the horizontal to minimize the potential for thermal stratification.

Thermal stratification could occur in the horizontal sections of piping when the incoming feedwater flow rate is low and there is a large temperature difference between the incoming feedwater and the steam generator coolant, which results in a density difference.

Fluctuations in the elevation of the interface between the hot and cold coolants cause thermal fatigue damage.

As shown in Figure 5.4.2-1, the upward bend using a goose-neck design is incorporated to avoid the stratified flows in the piping connecting the thermal sleeve in the downcomer feedwater nozzle to the downcomer feedwater piping inside the steam generator.

5.4.2.1.2.2 Material Design The design of the APR1400 steam generators limits the potential for degradation so the integrity of the steam generator, including the tubes, is maintained during the operating period between inspections. Degradation of the steam generator tubes and other secondary side components that could affect tube integrity is manageable through the steam generator program (see Subsection 5.4.2.2). In addition, degradation of steam generator RCPB materials is manageable through the inservice inspection program (See Subsection 5.2.4).

There are 13,102 tubes installed in an APR1400 steam generator. Tube bundle has 175 rows and 207 lines (columns). Tubes in row number 1 through 17 are U-bends and tubes in row number 18 through 175 are square-bends. Maximum bend radius of U-bend tube is 11 inches for row number 17. The bend radius of all square-bend tubes is 10 inches. All the U-bend tubes (row number 1 through 17) are thermally treated for stress relief.

Tube Supports The three types of structures in the APR1400 steam generators that support the tubes are horizontal grid or eggcrate, vertical, and diagonal. All three types are fabricated from Stainless Steel Type 409. A design consideration for the supports is the prevention of dryout at support locations. With one exception, all tube supports in the APR1400 steam generator are constructed of flat strips that present a flat surface to the tube. The exception is the flow distribution plate just above the entrance to the economizer section of 5.4-17 Rev. 2

APR1400 DCD TIER 2 the tube bundle. The flow distribution plate is a stainless steel perforated plate with circular flow holes, where the tube and secondary side fluid pass. The diameter of a flow hole is 19.685 mm (0.775 in). At this location, secondary water is subcooled, and dryout will therefore not occur.

The eggcrates have three configurations depending on their location in the evaporator: a full circular structure, a half circular structure, and a structure bounded by the circumference and a chord. An eggcrate is composed of strips intersecting at an angle of 60 degrees and joined at the outer and inner perimeters with a pair of square bars on top and bottom. The strips alternate between a 50.8 mm (2 in) slotted type and a 25.4 mm (1 in) unslotted type; both are 2.286 mm (0.090 in) thick (refer to Figure 5.4.2-4). The eggcrates themselves are supported and spaced by tie rods located throughout the tube bundle and by the weldment to the tube bundle shroud.

The eggcrates form an open lattice and thus minimize the potential for local dryout conditions. The number of eggcrates is selected to maintain the natural frequency of the tubes that is significantly higher than the exciting frequencies induced by cross flow at the fluid entrances to the bundle. Both analysis and test results have been applied to define spacing that precludes vibration-induced damage (fretting and wear). In addition, careful attention is paid to localized flow path details where velocities may be higher than nominal.

The vertical supports, shown in Figure 5.4.2-5, are assembled concurrently with tube installation and are composed of vertical, slotted 50.8 mm (2 in) strips intersecting with horizontal 12.7 mm (0.5 in) strips; both 2.286 mm (0.090 in) thick. The assembly is bounded about the periphery by either square bars or custom-shaped plates depending on the location. The vertical supports in the bend region are made of perforated strips to enhance their free-flowing nature. As shown on Figure 5.4.2-5, the vertical supports are also integrated with perforated diagonal strips, which provide thorough vibration support of the bend region without compromising the free-flowing character of the supports.

One set of eggcrate flow distribution plate is installed at the uppermost full eggcrate of steam generator to mitigate the secondary-side flow from concentrating into central cavity.

Eggcrate flow distribution plate is a stainless steel perforated plate with circular flow holes.

No tubes pass through the eggcrate flow distribution plate and only secondary side fluid passes through the eggcrate flow distribution plate. This design has been proven to effectively reduce localized wear since having been applied to previous nuclear power plants. The operating experiences related to the tube wear status at Korean Nuclear Power Plants provide a justification for the assertion. The eggcrate flow distribution plate is 5.4-18 Rev. 2

APR1400 DCD TIER 2 fixed onto the square-section ring in the full eggcrate with retainer ring segment and hexagon head cap screws. The cover plate is provided in the center of the eggcrate flow distribution plate for manufacturing process. Lock washers and initial preloads for the cap screws are applied.

Steam Generator Tubes and Other Secondary Non-pressure Boundary Material To limit the potential for the tubes to be dented, the tube support structures are fabricated from stainless steel Type 409 material (see Table 5.2-2). Tube denting is associated with the corrosion of tube support structures and creates a hard corrosion product that fills the crevice between the tube and the tube support. Dents can result in the restriction of primary coolant flow and stress-corrosion cracking of the tubes.

To limit the susceptibility of steam generator tubes to corrosion and to optimize the corrosion resistance of the microstructure, the APR1400 steam generator tubes are made of NiCrFe Alloy 690 that is thermally treated (TT). To reduce residual stresses in the U-bent region of short-radius (less than or equal to 279.4 mm [11 in]) U-bent tubes, the U-bent region of short-radius tubes is stress-relieved after bending. The materials that support the tubes and other materials on the secondary side, such as flow distribution plate and eggcrate flow distribution plate, are stainless steels that are sufficiently resistant to degradation to provide reasonable assurance that the tubes will remain adequately supported and to reduce the potential for the generation of loose parts, which can result in loss of tube integrity.

In addition, to prevent PWSCC, thermally treated alloy 690 (690TT) and 52/52M/152 weld metals are used for the steam generators. An additional discussion of the avoidance of stress corrosion cracking for Ni-base alloys is included in Subsection 5.2.3.5.

Tube Fastening to Tubesheet The method of fastening tubes to the tubesheet conforms to the requirements of ASME Sections III and IX. The tubes are welded to the tubesheet cladding after the primary side of the tubesheet is weld clad with nickel-chromium-iron alloy. These fusion welds comply with Sections III and IX of the ASME Code. The tube-to-tubesheet weld is designed to satisfy the allowable limits described in NB-3200 of the Section III of the ASME Code. Tube expansion into the tubesheet is such that no voids or crevices occur along the length of the tube in the tubesheet. The tube is expanded into the tubesheet by the use of hydraulic expansion. For hydraulic expansion, the expansion mandrel length is set to provide full-depth expansion, and hydraulic pressure is accurately applied, measured, 5.4-19 Rev. 2

APR1400 DCD TIER 2 reapplied, and controlled inside the tube so that the crevice between the tube and tubesheet is as small as possible. Expansion of tubes creates residual stresses in the transition zone between the expanded and the unexpanded regions of the tube. Residual stress measurements have been taken on the transition zone. The residual stress measurements verify the absence of any high residual tensile stress in the transition zone. Material specifications such as the use of TT tubing, welding procedures and fabrication procedures preclude the need for complete-bundle stress relief after assembly.

Corrosion Allowance Carbon or low allow steel materials, which comprise the pressure boundary of the secondary side, have a corrosion allowance of 1.6 mm (1/16 in). For the primary side pressure boundary materials which are low alloy steel, they are protected against general corrosion with austenitic stainless steel or Ni-base alloy deposited cladding which has a corrosion allowance of 0.053 mm (0.002 in). These corrosion allowances for the primary and secondary side pressure boundary materials are selected based on test data. Therefore, there is no expectation of a general corrosion problem in the APR1400 steam generators.

Bolting Materials Primary studs and nuts of the APR1400 steam generators are SB-637 N07718, and secondary studs and nuts are SA-540 Grade B24, or SA-193 Grade B7. These studs and nuts have performed adequately under service conditions and have not shown stress-corrosion cracking. The yield strength of ferritic fastener materials is limited to a maximum of 10,546 kg/cm2 (150 ksi).

5.4.2.1.3 Fabrication and Processing of Ferritic Materials Fracture Toughness The primary and secondary side pressure boundary components of the steam generator meet the fracture toughness requirements of the ASME Code Section III NB. Fracture toughness testing is described further in Subsection 5.2.3.3.

Welding The primary and secondary side pressure boundary components of the steam generator meet the welding requirements as described in Subsection 5.2.3.3.

5.4-20 Rev. 2

APR1400 DCD TIER 2 Subsection 5.2.3.3 describes the controls for welding ferritic steels. Conformance to the applicable NRC RGs for steam generators is summarized as follows:

a. NRC RG 1.50, Control of Preheat Temperature for Welding of Low-Alloy Steel, is addressed in Subsection 5.2.3.3.

b. NRC RG 1.71, Welder Qualification for Areas of Limited Accessibility, is addressed in Subsection 5.2.3.3.

c. NRC RG 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components, is addressed in Subsection 5.2.3.3.

Electroslag welding (ESW) is not used in primary and secondary side pressure boundary components of the steam generator.

5.4.2.1.4 Fabrication and Processing of Austenitic Stainless Steel There is no austenitic stainless steel that is used for the primary and secondary side pressure boundary of the APR1400 steam generators.

5.4.2.1.5 Compatibility of Materials with the Primary and Secondary Coolant and Cleanliness Control The primary water chemistry is controlled in accordance with EPRI guidelines as stated in Subsection 5.2.3.2.1 to minimize corrosion in the steam generator. The materials of the primary side steam generator are selected to minimize corrosion and have demonstrated satisfactory performance in existing operating reactor plants. A detailed description is shown in Subsection 5.2.3.2.2.

Localized corrosion of tubing material has led to steam generator tube leakage in some operating reactor plants. Examinations of tube defects that have resulted in leakage have shown that two mechanisms are primarily responsible. Localized corrosion mechanisms are referred to as stress assisted caustic cracking and wastage or tube wall thinning. Both types of corrosion have been related to steam generators that have operated on phosphate chemistry. The caustic stress-corrosion type of failure is precluded by controlling bulk water chemistry to the specification limits shown in Subsection 10.3.5.

Operating steam generators have experienced the following corrosion degradation mechanisms: phosphate wastage, sulfate wastage, intergranular attack, secondary side stress 5.4-21 Rev. 2

APR1400 DCD TIER 2 corrosion cracking, and pitting and denting resulting from tube support corrosion. With respect to these phenomena, the most important design feature of the APR1400 steam generators is the selection of tubing and tubing support materials. NiCrFe Alloy 690 TT is specified for the APR1400 steam generator tubes. Stainless Steel Type 409 material is specified for the tube supports (see Table 5.2-2).

Volatile chemistry has been successfully used to minimize corrosion in many of the steam generators that have gone into operation since 1972. Secondary water chemistry and operating chemistry limits for secondary water and feedwater are addressed in Subsection 10.3.5. Removal of solids from the secondary side of the steam generator is addressed in Subsection 10.4.8.

The onsite cleaning and cleanliness of the steam generator are controlled according to NRC RG 1.28.

5.4.2.1.6 Provisions for Accessing the Primary and Secondary Sides of the Steam Generator The steam generators have 533.4 mm (21 in) manways (Figure 5.4.2-1). On the primary side, there is one manway for the cold leg side and another for the hot leg side. Manway locations are optimized for use of remote manipulators for inspection and maintenance.

Access for eddy current testing is through the primary-side manways.

On the secondary side, two manways are provided to allow access to the separator and dryer area. In addition, an internal hatch provides access to the top of the tube bundle.

These openings allow inspection, which provides information on the condition of separation equipment, feedwater ring, and top of the tube bundle. Two 203.2 mm (8 in) handholes, at the tubesheet elevation, are included to provide access for tubesheet sludge lancing as well as for inspection of the downcomer annulus. These handholes can be used to remotely inspect for and retrieve loose parts. In order to enhance the steam generator integrity, the feedwater box is designed to limit the introduction of foreign objects greater than the 6.35 mm (0.25 in) tube gap through economizer feedwater region, which is a major path of foreign object inflow. Two 127.0 mm (5 in) inspection holes are provided to remove the foreign objects trapped in the feedwater box.

5.4-22 Rev. 2

APR1400 DCD TIER 2 5.4.2.2 Steam Generator Program The purpose of a steam generator program (SGP) is to maintain the structural and leakage integrity of steam generator (SG) tubes. An SGP provides effective monitoring and management of tube degradation and degradation precursors for prompt preventive and corrective actions. The SGP contains a balance of prevention, inspection, and evaluation, and leakage monitoring measures. The SGP is established and maintained based on the requirements of NEI 97-06 (Reference 12) and its referenced EPRI guidelines.

The SGP complies with the relevant requirements of the following NRC regulations:

a. GDC 32 of Appendix A to 10 CFR 50 requires, in part, that the designs of all components that are part of the RCPB permit periodic inspection and testing of critical areas and features to assess their structural and leak-tight integrity.

b. 10 CFR 50.55a(g) requires that inservice inspection (ISI) programs meet the applicable inspection requirements in ASME Section XI. The SGP is a portion of the ISI program.

c. 10 CFR 50.36 applies to the SGP in the Technical Specifications.

d. Appendix B to 10 CFR 50 applies to the implementation of the SGP. Of particular note are Criteria IX, XI, and XVI. Criterion IX requires, in part, that measures be established to ensure that special processes, including nondestructive testing, are controlled and accomplished by qualified personnel using qualified procedures.

Criterion XI requires, in part, the establishment of a test program to ensure that all testing required to demonstrate that SSCs will perform satisfactorily in service is identified and performed in accordance with written test procedures that incorporate the requirements and acceptance limits in applicable design documents.

Criterion XVI requires, in part, that measures be established to ensure the prompt identification and correction of conditions that are adverse to quality.

e. 10 CFR 50.65 requires that licensees monitor the performance or condition of SSCs against goals to provide reasonable assurance that such SSCs are capable of fulfilling their intended functions.

5.4-23 Rev. 2

APR1400 DCD TIER 2 5.4.2.2.1 Design Description The SGs are designed to permit access required for tube inspections, testing, and plugging.

The SG tubes of the APR1400 can be accessed from the primary side of the SG for full length inspection. The design is described further in Subsection 5.4.2.1.6.

5.4.2.2.2 Implementation of SGP KHNP has been operating the SGP comprehensive integration procedure, which includes the constitution and application of SGP documents, the roles and responsibilities of organizations, and also the technical program including the QA process. The SGP includes degradation assessment, inspection, integrity assessment, and tube plugging, primary-to-secondary leak monitoring, maintenance of secondary-side integrity, secondary-side water chemistry, primary-side water chemistry, foreign material exclusion, contractor oversight, self-assessment, and reporting.

5.4.2.2.2.1 Degradation Assessment A degradation assessment is performed prior to the preservice inspection (PSI) and planned ISI for SGs during commercial operation to address the RCPB integrity within the SG (e.g.,

plugs, tubes, and components that support the pressure boundary such as secondary-side components).

The assessment considers operating experience and provides reasonable assurance that appropriate inspections are performed during the upcoming outage and that the requisite information for integrity assessment is provided.

Some of the important features of the degradation assessment are:

a. Identifying existing and potential degradation mechanisms

b. Choosing techniques to test for degradation based on the probability of detection and sizing capability

c. Establishing the number of tubes to be inspected

d. Establishing the tube integrity limits for condition monitoring and operational assessment 5.4-24 Rev. 2

APR1400 DCD TIER 2 5.4.2.2.2.2 Inspection SG tube inspections based on degradation assessments are conducted and follow the inspection guidance in the EPRI PWR Steam Generator Examination Guidelines (Reference 13).

Some of the important features of SG tube inspections are:

a. Sampling as supported by the degradation assessment

b. Obtaining the information necessary to develop degradation, condition monitoring, and operational assessments

c. Qualifying the inspection program by determining the accuracy and defining the elements for enhancing nondestructive examination (NDE) system performance, including technique, analysis, field analysis feedback, human performance and process controls Preservice inspection is performed on the full length of 100% of the tubes in each steam generator using techniques capable of detecting degradation and fabrication abnormalities along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet. The preservice inspection will be performed after field hydrostatic testing and before operation.

5.4.2.2.2.3 Integrity Assessment SG tube integrity is assessed after each SG tube inspection. The assessment includes:

a. Condition Monitoring (CM): A backward-looking assessment that confirms that adequate SG tube integrity has been maintained during the previous inspection interval.

b. Operational Assessment (OA): A forward-looking assessment that demonstrates that tube integrity performance criteria will be met throughout the next inspection interval.

The SG tube surveillance program, including performance criteria for tube integrity, tube plugging criteria, and tube inspections, is described in the Technical Specifications (Chapter 16) Subsection 5.5.9. The plugging criteria are determined based on NRC RG 5.4-25 Rev. 2

APR1400 DCD TIER 2 1.121 and the EPRI guidelines. Limiting conditions for operation and reactor coolant system operational leakage limits, including primary-to-secondary leakage limits, are described in the Technical Specifications (Chapter 16) Subsections 3.4.12 and 3.4.17.

5.4.2.2.2.4 Tube Plugging Plugging methods are qualified and implemented in accordance with industry standards (i.e., ASME Section XI, IWA-4700). The qualification of the plugging techniques considers the SG conditions and mockup testing. The EPRI guidance document, Pressurized Water Reactor Steam Generator Examination Guidelines (Reference 13),

provides a pre-service inspection of the plugging. The EPRI document, PWR Steam Generator Tube Plug Assessment provides further guidance on tubing maintenance.

5.4.2.2.2.5 Primary-to-Secondary Leak Monitoring In order to prevent the leakage of primary coolant to the environment through SGs, primary-to-secondary leak monitoring procedures are established in accordance with the Technical Specifications and the EPRI PWR Primary-to-Secondary Leak Guidelines (Reference 14) provides further guidance. Monitoring gives operators information that is needed to safely respond to situations in which tube integrity becomes impaired and significant leakage or tube failure occurs. There are three action levels of reactor operation according to the leak rate in SGs.

5.4.2.2.2.6 Maintenance of Steam Generator Secondary-Side Integrity Secondary-side SG components that are susceptible to degradation are monitored if their failure could prevent the SG from fulfilling its intended safety-related function. The monitoring includes design reviews, assessment of potential degradation mechanisms, industry experience for applicability, and inspections, as necessary, to provide reasonable assurance that degradation of these components does not threaten tube structural and leakage integrity or the ability of the plant to achieve and maintain safe shutdown.

The secondary-side visual inspection program defines the scope of inspection, and the inspection procedures and methodology to be used, when secondary-side visual inspections are performed. Additional guidance is provided in the EPRI Steam Generator Integrity Assessment Guidelines (Reference 15).

5.4-26 Rev. 2

APR1400 DCD TIER 2 5.4.2.2.2.7 Secondary-Side Water Chemistry Procedures are prepared for monitoring and controlling secondary-side water chemistry to inhibit secondary-side corrosion-induced degradation such as outside diameter stress corrosion cracking in accordance with the EPRI PWR Secondary Water Chemistry Guidelines (Reference 16). More details are described in Subsection 10.3.5 and the Technical Specification Subsection 5.5.10.

5.4.2.2.2.8 Primary-Side Water Chemistry Procedures are prepared for monitoring and controlling primary-side water chemistry to inhibit primary-side corrosion-induced degradation such as primary water stress corrosion cracking in accordance with the EPRI PWR Primary Water Chemistry Guidelines (Reference 17). More details are described in Subsection 9.3.4.2.7.

5.4.2.2.2.9 Foreign Material Exclusion Procedures are prepared for control and monitoring of foreign objects and loose parts to prevent fretting and wear degradation of the tubing The SG program includes secondary-side visual inspections and procedures to preclude the introduction of foreign objects into either the primary or secondary side of the SG whenever it is opened for inspections, maintenance, modifications, or other reasons.

Such procedures include the following as a minimum:

a. Detailed accountability for all tools and equipment used during any activity when the primary or secondary side is open

b. Appropriate controls and accountability for foreign objects such as eyeglasses and personal dosimetry

c. Cleanliness requirements

d. Accountability for components and parts removed from the internals of major components (e.g., reassembly of cut and removed components)

The potential for introduction of loose parts or foreign objects from secondary-side systems is also considered.

5.4-27 Rev. 2

APR1400 DCD TIER 2 5.4.2.2.2.10 Contractor Oversight Procedures are established for oversight of contractor work for the SG inspections and cleaning work that will be performed during the refueling outage. Critical aspects of the oversight include the following as a minimum:

a. Review and approval of the scope of work to be performed by a contractor

b. Review and approval of the degradation assessment

c. Review and approval of the contractors examination procedures

d. Monitoring of the contractors examination work progress

e. Review and approval of the contractors deliverables

f. Review and approval of the tube integrity assessment (CM/OA) and associated support documents 5.4.2.2.2.11 Self-Assessment Self-assessment of the SGP is performed by the SG expert team and independent peer review by knowledgeable personnel in the power stations on a periodic basis. The self-assessment identifies areas for program improvement along with program strengths.

5.4.2.2.2.12 Reporting The following reports will be submitted to the NRC within 6 months after completion of an inspection performed under the SGP:

a. The scope of inspection performed on each SG

b. Degradation mechanisms found

c. NDE techniques utilized for each degradation mechanism

d. Location, orientation (if linear), and measured sizes (if available) of service-induced indications

e. Number of tubes plugged (or repaired) during the inspection outage for each degradation mechanism 5.4-28 Rev. 2

APR1400 DCD TIER 2

f. The number and percentage of tubes plugged to date, and the effective plugging percentage in each steam generator

g. The results of condition monitoring, including the results of tube pulls and in situ testing

h. Repair method utilized and the number of tubes repaired by each repair method 5.4.2.3 Tests and Inspections Prior to, during, and after fabrication of the steam generator, nondestructive tests based on Section III of the ASME Code are performed.

Initial hydrostatic tests of the primary and secondary sides of the steam generator are conducted in accordance with ASME Section III. Leak tests are also performed.

Following satisfactory performance of the hydrostatic tests, magnetic-particle inspections are made on all accessible welds.

Inservice inspections of the steam generator are performed in accordance with ASME Section XI, including automatic ultrasonic for SG transition region.

5.4.3 Reactor Coolant Piping 5.4.3.1 Design Basis Applicable design codes are provided in Table 5.2-1. The reactor coolant loop piping is designed and analyzed for the transients specified in Table 3.9-1. In addition, those nozzles subjected to local thermal transients, caused by fluid entering the RCS from an auxiliary system, are analyzed to provide reasonable assurance that the nozzles can accommodate the transients.

In addition to being specified as seismic Category I, the piping is designed to provide reasonable assurance that critical vibration frequencies are out of the range expected during normal operation and abnormal conditions. Additional descriptions relating to seismic and dynamic analyses and criteria for the reactor coolant piping are contained in Subsections 3.7.2 and 3.9.2, respectively.

Leak-before-break (LBB) is applied to reactor coolant piping, including the surge line.

The LBB evaluation procedure is described in Subsection 3.6.3.

5.4-29 Rev. 2

APR1400 DCD TIER 2 5.4.3.2 Description Each of the two heat transfer loops contains five sections of pipe: one 1,066.8 mm (42 in) internal diameter pipe between the reactor vessel outlet nozzle and steam generator inlet nozzle, two 762 mm (30 in) internal diameter pipes from the steam generators two outlet nozzles to the reactor coolant pumps suction nozzle, and two 762 mm (30 in) internal diameter pipes from the pumps discharge nozzle to the reactor vessel inlet nozzles. These pipes are referred to as the hot leg, suction legs, and cold legs, respectively. The other major pieces of reactor coolant piping are the surge line, a 300 mm (12 in) pipe between the pressurizer and the hot leg, and the spray line, a 100 mm (4 in) pipe at the pressurizer end reduced to an 80 mm (3 in) pipe and connected to two cold legs.

The 1,066.8 mm (42 in) and 762 mm (30 in) pipe internal diameter are selected to obtain coolant velocities that provide a reasonable balance between erosion-corrosion, pressure drop, and system volume. The surge line is sized to limit the frictional pressure loss through it during the maximum in-surge so that the pressure differential between the pressurizer and the heat transfer loops is no more than 5 percent of the system design pressure. The spray line sizing is discussed in Subsection 5.4.10.

To reduce the amount of field welding during plant fabrication, the 1,066.8 mm (42 in) and 762 mm (30 in) pipes are supplied in major pieces, complete with shop-installed instrumentation nozzles and connecting nozzles to the auxiliary systems. Where required, the nozzles are supplied with safe ends to facilitate field welding of the connecting piping.

Flow restricting orifices (5.6 mm dia. x 25.4 mm long) (7/32 in dia. x 1 in long) are provided in the nozzles for the RCS instrumentation and sampling lines to limit flow in the event of a break downstream of a nozzle.

The analysis, loadings, and limits for the structural evaluation of the reactor coolant piping for each condition are discussed in Subsection 3.9.3.

5.4.3.3 Materials The materials used in the fabrication of the piping are listed in Table 5.2-2. These materials are in accordance with ASME Section III. The provisions taken to control those factors that contribute to stress corrosion cracking are discussed in Subsection 5.2.3.

Fracture toughness of the reactor coolant piping is discussed in Subsection 5.2.3.

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APR1400 DCD TIER 2 The fracture toughness properties of all ferritic reactor coolant pressure boundary (RCPB) materials are required to be in accordance with the requirements of ASME Section III, NB-2300 and Appendix G of 10 CFR Part 50. The SA 516 Grade 70 or SA-508 Grade 1 or 1a material used for reactor coolant piping is in accordance with these requirements.

Piping materials are required to meet the impact test requirements of ASME Section III, NB-2300, at a temperature of RTNDT + 33.33 °C (60 °F) or less.

5.4.3.4 Tests and Inspections Prior to, during, and after fabrication of the reactor coolant piping, nondestructive tests based upon ASME Section III are performed. In addition, the fully assembled RCS is hydrostatically tested in accordance with the ASME Code. Inservice inspection of the RCS piping is discussed in Subsection 5.2.4.

5.4.3.5 Design Features for Minimization of Contamination The APR1400 is designed with specific features to meet the requirements of 10 CFR 20.1406 (Reference 18) and Regulatory Guide 4.21 (Reference 19). The basic principles of RG 4.21, and the methods of control suggested in the regulations, are specifically delineated in four design objectives and two operational objectives discussed in Subsection 12.4.2 of this DCD. The following evaluation summarizes the primary features to address the design and operational objectives for the RCS.

The RCS SSCs, including the facility that houses the components, are designed to limit leakage and/or control the spread of contamination. In accordance with RG 4.21, the RCS has been evaluated for leak identification from the SSCs that contain radioactive or potentially radioactive materials, the areas and pathways where probable leaks may occur, and methods of control incorporated in the design of the system. The leak identification evaluation indicated that the RCS is designed to facilitate early leak detection, provide capability for prompt assessment and evaluation of the responses, and sufficient spaces for the mitigation of the leak areas. Thus, unintended contamination of the facility and the environment is minimized or prevented by the SSC design, supplemented by operational procedures and programs for inspection and maintenance activities.

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APR1400 DCD TIER 2 Prevention/Minimization of Unintended Contamination

a. The RCS is designed in accordance with ASME Section III and proven nuclear power industry experience. The RCS is designed with and overpressure protection system and other engineered safety features (ESF) to provide reasonable assurance of safe operation and mitigation of accident conditions, thus preventing unintended contamination.

b. The RCS components are designed to provide the first barrier to contain the radioactivity resulting from power operation and damaged fuel. These components are designed with proven materials and fabrication techniques, and are housed inside the reactor containment structure, which provides the second barrier. The basemat of the reactor containment structure is equipped with steel liners to prevent and minimize the spread of contamination from leaked reactor coolant. The in-core instrumentation (ICI) sump is provided at the basemat level to collect leaks, and the reactor containment sump is provided at the reactor vessel operating floor to collect leaks from the other components. The reactor floor is also lined with a steel layer to prevent contamination of the concrete structure.

c. The system, including wetted parts of the reactor vessel, steam generators, pressurizer, reactor coolant pumps, and associated piping, is designed with stainless steel cladding or base material, and has welded construction for life-cycle planning, thus minimizing leakage and unintended contamination of the facility and the environment.

d. The components are designed with material resistant to primary water stress corrosion cracking and reduced SG hot leg temperature to minimize the potential for stress corrosion and cracking.

e. The containment also includes the IRWST and a holdup volume tank with sufficient capacity to provide temporary storage of reactor coolant from anticipated operational occurrences and design basis accidents.

Adequate and Early Leak Detection

a. The RCS components are designed with multiple level, pressure, temperature, and radiation detection instruments to provide reasonable assurance of safe operation of the SSCs, including the associated piping, and provide alarms to the operating 5.4-32 Rev. 2

APR1400 DCD TIER 2 personnel in the event of off-normal conditions. Releases from overpressurization and leaks are collected in the reactor drain tank (RDT), the ICI sump, the containment sump, and the IRWST. A detailed description of the early leak detection instruments, locations, leak collections and pathways, and operation notifications for response actions is presented in Subsection 5.2.5.

b. Leak detection methods are segregated into two classifications: unidentified leakages and Identified leakages. Unidentified leakages are monitored by containment sump level, area particulate radiation detection, and containment atmosphere humidity instruments. Leakages are collected in sumps and a computer program is developed to estimate leakage rates based on flow measurements. This approach can detect 0.5 gpm leakage within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

Additionally, 19 locations within the containment are equipped with acoustic leak detection instruments where leakage is considered critical. See Subsection 5.2.5.1.1 for details.

1) Containment area radiation monitors, temperature and pressure monitors, sump levels and sump pump flow rates are programmed to provide leakage information and notification in the MCR for operator actions.

2) Acoustic leak monitoring instruments are installed in other critical areas within the reactor coolant pressure boundary, including in-core instrumentation nozzles at reactor lower head, SG manway seals, reactor hot and cold leg welding areas, reactor coolant pump shaft seal housings, pressurizer lower head area, and CEA nozzle areas near the reactor head.

These leak monitoring instruments provide early detection of leak and alarm signals for operator actions when required.

c. The identified leakages for the primary RCS leak detection methods and locations, and other indications of reactor coolant leakage are summarized in Subsections 5.2.5.1.2. The leakage sources and instruments for early detection of reactor coolant leakage are as follows:

1) Steam generator leaks are monitored by N-16 monitors on each of the main steam lines. An increase in radioactivity, as indicated by the condenser vacuum vent effluent monitor and SG blowdown monitor, will reveal reactor coolant leakage through SG tubes to the secondary side. Routine analysis of 5.4-33 Rev. 2

APR1400 DCD TIER 2 the SG secondary side will also indicate leakage of reactor coolant into the secondary system.

2) The RCPs are designed with two mechanical seals and one mechanical vapor seal made of renewable silicon carbide rings. Each of these three seals can withstand full operating pressure. Any leakage from these seals is collected and routed to the RDT. An acoustic sensor is provided with each pump to detect any leak through the seal.

3) Temperatures downstream of the pilot-operated safety relief valves (POSRVs) are continuously monitored for early detection of leaks.

4) Leakage between the two metal O-rings that seal the reactor vessel head flange is routed through a leakoff line to the RDT. A normally closed, remotely activated isolation valve and a pressure indicator are installed in the leakoff line. Leakage from the reactor vessel head flange causes pressure in the leakoff line to rise. The pressure in the leakoff line is continuously monitored to detect the presence of a leak. Any leakage is bled off to the RDT by opening the isolation valve.

d. Other primary coolant leak detection methods and locations are discussed in Subsection 5.2.5.2.2.

Reduction of Cross-Contamination, Decontamination, and Waste Generation

a. Each RCP is equipped with an oil collection system in accordance with NRC RG 1.189 that collect oil from non-welded parts. Leaked oil is collected and drained to an oil collection tank that can store the entire inventory. This design approach prevents the potential generation of mixed waste.

b. Shop welding of major piping to larger pieces is maximized to reduce field welding. Piping safe-ends are provided for field welding connections to minimize the potential for leaking.

c. The SSCs are designed with life-cycle planning through the use of nuclear industry-proven materials compatible with the chemical, physical, and radioactive environment, thus minimizing waste generation.

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APR1400 DCD TIER 2

d. The RCS is designed with continuous letdown of reactor coolant for purification in the CVCS and provision of sampling to maintain reactor coolant chemistry and quality. Similarly, the steam generators are designed with continuous blowdown of dissolved and suspended solids on the secondary side for treatment and with provisions for sampling and analysis. This design approach minimizes the buildup of radioactivity and impurities, enhances safe operation, and reduces decontamination and waste generation during decommissioning.

e. The RCS components are made of steel with low cobalt content as much as is practicable. The approach minimizes waste generation.

f. Manual valves 2 inches and larger are designed with a double-packed stem and a lantern ring with an intermediate leak drain connection. The drains are routed to the drain system for collection and treatment. This design approach minimizes the spread of contamination and the contamination of the facility.

g. Sampling lines from the RCS are designed to be as short and straight as possible to minimize traps and pockets. Flow velocity is maintained in the turbulent region to prevent settling of suspended solids. Gaseous sampling lines are sloped upward to facilitate draining of condensate. This design approach minimizes accumulation of condensate and provides more accurate samples, thus minimizing waste generation. Sampling lines are purged with adequate demineralized water or nitrogen gas in order to maintain quality of sampling.

h. The process piping containing primary coolant is properly designed to be the shortest between components, sized for turbulent flow, and laid out to minimize traps and erosion. This approach facilitates easier flow and with sufficient velocities to prevent settling of solids, thus reducing the decontamination needs and waste generation.

i. Utility connections are designed with a minimum of two barriers to prevent cross-contamination.

Decommissioning Planning

a. The top surface of the containment basemat is sloped and lined with a layer of steel to prevent contamination of the basemat by facilitating draining of leakage to 5.4-35 Rev. 2

APR1400 DCD TIER 2 the ICI sump and the containment sump. This layered approach facilitates easier decommissioning and minimizes waste generation.

b. The SSCs are designed for the full service life and are fabricated as individual assemblies for easy removal.

c. The RCS is designed with no embedded or buried piping, thus facilitating decommissioning planning and preventing unintended contamination.

Operations and Documentation

a. The RCS is designed for remote and automatic operation with operator supervision. Adequate instrumentation, including level, flow, temperature, and pressure elements, radiation monitors, and acoustic leak detection instruments, is provided to monitor and control the operations to prevent undue interruption, and minimize the spread of contamination and waste generation.

b. The RCS is designed for a minimal amount of maintenance. The layout takes into account the necessary access, laydown areas, handling and lifting cranes, and the auxiliary equipment in the event that maintenance is required.

c. The RCS components are equipped with loose parts monitoring instruments and vibration monitoring instruments at specific locations. This design approach enhances equipment life and minimizes waste generation.

d. Areas adjacent to the RCS pressure boundary are designed to have adequate clearance to access for inservice inspections. Personnel access is provided for component maintenance and inspections.

e. The COL applicant is to prepare operational procedures and maintenance programs for leak detection and contamination control of the RCS (COL 5.4(1)).

Procedures and maintenance programs are to be completed before fuel is loaded for commissioning.

f. The COL applicant is to maintain complete documentation of system design, construction, design modifications, field changes, and operations.

Documentation requirements are included as a COL information item (COL 5.4(2)).

5.4-36 Rev. 2

APR1400 DCD TIER 2 Site Radiological Environmental Monitoring The RCS is located inside the reactor containment building. Because of its location and associated safety design features, the potential for environmental contamination of soil and groundwater from reactor coolant is minimal. Therefore, RCS inclusion in the site radiological environmental monitoring program is not required. However, a site radiological environmental monitoring program is included for the whole plant for detection radiological of contamination.

5.4.4 [Reserved]

5.4.5 [Reserved]

5.4.6 Reactor Core Isolation Cooling System (Boiling Water Reactors Only)

This section is not applicable to the APR1400.

5.4.7 Shutdown Cooling System 5.4.7.1 Design Bases 5.4.7.1.1 Summary Description The shutdown cooling system (SCS) is a safety-related system that is used to reduce the temperature of the reactor coolant system (RCS) in post shutdown periods from the hot shutdown operating temperature to the refueling temperature. The initial phase of a cooldown is accomplished by heat rejection from the steam generators (SGs) to the condenser or atmosphere. After the reactor coolant temperature and pressure have been reduced to approximately 176.7 °C (350 °F) and 31.6 kg/cm2A (450 psia), the SCS is put into operation for normal shutdown cooling to reduce the RCS temperature to the refueling temperature, and to maintain this temperature during refueling.

Additionally, the SCS is used in conjunction with the atmospheric dump valves (ADVs) and the auxiliary feedwater system to cooldown the RCS following a small break loss of coolant accident (LOCA) (refer to Section 6.3). The SCS is also used subsequent to steam and feedwater line breaks, steam generator tube ruptures, and is used during plant startup prior to RCP restart to maintain flow through the core. After an accident, the SCS can be put into operation when the RCS temperature and pressure are below approximately 193.3 °C (380 °F) and 28.1 kg/cm2A (400 psia), respectively.

5.4-37 Rev. 2

APR1400 DCD TIER 2 5.4.7.1.2 Functional Design Bases The following functional design bases apply to the SCS:

a. The SCS, SCS piping and its support, and components including instrumentation and controls are designed to meet GDC 2, 4, 5, 19, and 34 and BTP 5-4.

b. The SCS is designed to remove decay heat, RCS sensible heat, and heat generated by the shutdown cooling pumps (SCPs) during normal plant cooldown after partial cooldown has been accomplished, and during safe cold shutdown condition.

c. Two independent trains of the SCS are provided, each with its own suction and discharge connections to the RCS.

d. No single active failure prevents at least one complete train of the SCS from being brought on line from the main control room (MCR), whether this is during normal plant cooldown or following a design basis event (DBE).

e. The design bases defined in Subsection 5.4.7.1.1 are met assuming the failure of a single active component during shutdown cooling or a single active or limited leakage passive failure of a component during long-term operations following a DBE. Redundant components and instrumentations are used to provide reasonable assurance of the availability of the SCS. Limited leakage passive failure is defined based on maximum flow through a failed valve packing or pump (e.g., SCP mechanical seal).

f. The SCS is designed so that the SCPs and containment spray pumps (CSPs) are identical and functionally interchangeable. Provisions are made to control the status of those valves used in the SCS/containment spray system (CSS) interconnection. When used in a containment spray configuration, the SCPs are capable of being automatically started by a safety injection actuation signal (SIAS) or containment spray actuation signal (CSAS).

g. The SCS is designed for a pressure of 63.3 kg/cm2G (900 psig) and a temperature of 204.4 °C (400 °F) to address NRC intersystem loss of coolant accident (ISLOCA) issues.

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APR1400 DCD TIER 2

h. No single failure allows the SCS to be overpressurized by the RCS. The SCS components whose design pressure is less than the RCS design pressure are provided with overpressure protection (refer to Subsection 5.4.7.2.3).

i. The SCS reduces the RCS temperature as follows:

1) Two train cooldown (normal operation): With no component failures assuming two trains are in service, the SCS is designed to be capable of reducing reactor coolant temperature as follows:

a) To 60 °C (140 °F) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after reactor shutdown b) To 54.4 °C (130 °F) by the time reactor vessel head stud detensioning operations are started (within approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> after reactor shutdown) c) To 48.9 °C (120 °F) within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after reactor shutdown Achievement of the specified temperatures within the prescribed time is accomplished assuming that shutdown cooling is initiated at 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after reactor shutdown.

2) One train cooldown (safety shutdown operation): Assuming one train is out of service, the SCS is designed to be capable of reducing reactor coolant temperature as follows:

a) To 93.3 °C (200 °F) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after reactor shutdown in conjunction with other heat removal systems (e.g., steam generator ADVs, auxiliary feedwater system)

This meets BTP 5-4 (Reference 20) criteria to be in cold shutdown within a reasonable time, typically defined as 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Achievement of the specified temperature within the prescribed time is accomplished assuming shutdown cooling initiated at 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> after reactor shutdown.

Typical cooldown curves are shown in Figures 5.4.7-1 and 5.4.7-2.

j. The SCS components are designed in accordance with the applicable codes and classifications discussed in Subsection 5.4.7.2.4.

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APR1400 DCD TIER 2

k. Materials are selected to preclude system performance degradation due to the effects of short and long-term corrosion.

l. The SDCHXs are sized to remove decay heat 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after shutdown based upon an average refueling water temperature of 48.9 °C (120 °F) and a component cooling water temperature of 35 °C (95 °F) with an average reactor core burnup of two fuel cycles.

m. The SCS is designed so that the SCPs can be tested at design flow conditions with the reactor operating at power.

n. The SCS is designed to transfer RCS fluid to the CVCS for purification during SCS operation.

o. The SCS is designed to transfer refueling pool water back to the IRWST following refueling operations.

p. The SCS is designed to provide cooling of the IRWST during post-accident feed and bleed operations utilizing the SIS and the safety depressurization and vent system.

q. The SCS is protected by relief valves with sufficient capacity to prevent overpressure in isolated sections and is designed to provide for RCS overpressure protection by the event initiating the pressure from either an operator or equipment malfunction during a low-temperature condition. Discharges from relief valves are collected in the EDT, RDT, or IRWST.

r. The SCS is designed to be operated with reduced RCS inventory including mid-loop condition.

s. The SCS piping and its support are designed to withstand loads arising from the various operating and design conditions. All SCS piping is provided with protection against pipe whip and missiles. Components of the SCS, including associated instrumentation and controls, are designed to perform their designed safety function under the environmental conditions of Section 3.11. The SCS is designed to accommodate seismic loads so that in the event of an SSE, the SCS components will remain functional and are protected natural phenomena such as floods and hurricanes. Fire protection is provided for components and 5.4-40 Rev. 2

APR1400 DCD TIER 2 instruments of the SCS. Piping of the SCS connected to the RCS that could be subjected to temperature distributions that would result in unacceptable thermal stress is described in Subsection 3.12.5.9.

t. The control room is provided for shutdown cooling operation under both normal and accident conditions. Adequate SCS instrumentation and controls are provided at appropriate locations outside the MCR to permit prompt shutdown to hot shutdown with a potential capability for subsequent cold shutdown of the reactor using suitable procedures.

u. The SCS is provided with appropriate isolation from the RCS when the RCS is at high pressure. The interlocks associated with six valves on the two SCS suction lines are provided to prevent the valves from opening in the event RCS pressure exceeds the SCS operating pressure.

v. The pumps are provided with minimum flow protection (recirculation lines) to prevent damage when starting against an isolated discharge pathway.

w. All SCS and subsystems connected to the RCS that extend outside the containment boundary are designed to the extent practicable to an ultimate rupture strength at least equal to normal RCS operating pressure. For those interfacing systems or subsystems that do not meet the full RCS ultimate rupture strength requirement, the degree and quality of isolation or reduced severity of the potential pressure challenges is sufficient to preclude an intersystem LOCA.

x. The SCS is designed for a single power unit only that is used only for the SCS.

Each train of the SCS is isolated physically and electrically from the other to provide reasonable assurance that a failure in one train, or the effects thereof, will not result in the failure of the other train. The SCS is capable of being powered from both the plant's normal and emergency electrical power sources. In addition, the SCS components and valves are arranged and installed to prevent flooding.

y. The SCS is provided with provisions for a leakage detection and control program to minimize the leakage from those portions of the system outside of the containment that contain or may contain radioactive material following an accident.

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APR1400 DCD TIER 2

z. For external reactor vessel cooling (ERVC) under hypothetical core melting severe accident conditions, one SCP is used for initial ERVC injection.

5.4.7.2 System Design 5.4.7.2.1 System Schematic The flow diagrams of SCS are shown in Figures 5.4.7-3 and 6.3.2-1. The SCS contains two heat exchangers, two pumps, and two pump miniflow heat exchangers. One SCP is capable of meeting the safety shutdown cooldown criteria specified above; two SCPs are needed to meet the normal cooldown design criteria. SCS detailed design parameters are given in Table 5.4.7-1. In addition, the mode diagram is shown in Figure 5.4.7-5.

During initial shutdown cooling, a portion of the reactor coolant flows out of the SCS nozzles located on the reactor vessel outlet pipes (hot legs), and is circulated through the SDCHXs by the SCPs. The return to the RCS is through SIS direct vessel injection (DVI) nozzles. The pressure and temperature of the RCS varies from 31.6 kg/cm2A (450 psia) and 176.7 °C (350 °F) at the initiation of shutdown cooling to atmospheric pressure and 48.9 °C (120 °F) at refueling conditions. The SCS suction side pressure and temperature follow RCS conditions. The discharge side pressure is higher by an amount equal to the pump head. The operation temperature at the SDCHX outlet is lower than the RCS temperature.

Shutdown cooling flow is measured by orifice flow meters installed in each train of the SCP discharge piping. The information provided is used by the operator for flow control during the SCS operation. The cooldown rate is controlled by adjusting flow through the heat exchangers with throttle valves that are located in the outlet piping of each heat exchanger. The operator maintains a constant total SCS flow to the core by adjusting the heat exchanger bypass flow to compensate for changes in flow through the heat exchangers.

5.4.7.2.2 Component Description

a. Shutdown cooling heat exchangers The design temperature is based upon the temperature of the reactor coolant at the initiation of shutdown cooling plus a design tolerance. The SDCHXs are used to remove core decay, RCS sensible heat, and SCP heat during normal plant cooldown after a partial cooldown has been accomplished and during safe cold 5.4-42 Rev. 2

APR1400 DCD TIER 2 shutdown conditions. The SDCHXs are designed to maintain an average refueling water temperature of 48.9 °C (120 °F), with a component cooling water temperature of 35 °C (95 °F) at 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after shutdown following an assumed reactor core average burnup of two fuel cycles. A fouling resistance is assumed for additional margin for heat exchanger performance.

b. Instrumentation The instrumentation and controls for the SCS are designed in accordance with the applicable portions of the IEEE Standards, as described in Subsection 7.1.2.

The operation of the SCS is controlled and monitored using dedicated redundant instrumentation that provides the capability to monitor the cooldown rate and shutdown cooling flow to detect degradation of flow or SCS heat removal capabilities. The instrumentation provided for monitoring SCS components during normal SCS operation is discussed below, and is also summarized in Section 7.5.

1) Shutdown cooling heat exchanger inlet and return line temperature The temperature of each shutdown cooling heat exchanger inlet and return line (combined HX and HX bypass flow) is indicated in the MCR and at a remote shutdown room (RSR). Recording capabilities for the heat exchanger inlet temperature and return line temperature are also provided in the MCR for each SCS train. These indications are used to provide a measurement of system performance, and provide information allowing the operator to adjust the cooldown rate.

2) Shutdown cooling heat exchanger outlet temperature The temperature at the outlet of each heat exchanger is indicated in the MCR.

This instrument functions to monitor heat exchanger performance by directly measuring the outlet temperature.

3) Shutdown cooling pump suction and discharge pressure 5.4-43 Rev. 2

APR1400 DCD TIER 2 The pump suction and discharge pressures are indicated in the MCR and function to monitor pump performance. Low pressure alarms are provided for SCP discharge in the MCR.

4) Shutdown cooling flow A shutdown cooling flow indicator in each train of the SCS measures shutdown cooling flow, and indicates the flow rate in the MCR and at an RSR.

A low flow alarm is provided in the MCR. The alarm alerts the operator to a low flow condition that may lead to a loss of shutdown cooling due to either a loss of adequate pump suction or the closure of a system valve.

5) SCS valve position indication a) Open/closed position indication is provided in the MCR for SCP local manual isolation valves SI-106, SI-107, SI-578, and SI-579. An alarm is provided to alert the operator when a valve is not fully open.

b) Open/closed position indication is provided in the MCR and at an RSR for IRWST recirculation line isolation valves SI-300, SI-301, SI-688, and SI-693.

c) Open/closed and full range 0 to 100 percent position indication is provided in the MCR and an RSR for SDCHX and heat exchanger bypass flow control valves SI-310, SI-311, SI-312, and SI-313.

d) Open/closed and full range 0 to 100 percent position indication is provided in the MCR and at an RSR for IRWST recirculation line flow control valves SI-314 and SI-315.

e) Open/closed position indication is provided in the MCR and an RSR for SCS/CSS pump suction cross connect valves SI-340 and SI-342 and is provided in the MCR for SCS/CSS pump discharge cross connect valves SI-341 and SI-343.

f) Open/closed and full range 0 to 100 percent position indication is provided in the MCR and at an RSR for SCS DVI line isolation/flow control valves SI-600 and SI-601.

5.4-44 Rev. 2

APR1400 DCD TIER 2 g) Open/closed position indication is provided in the MCR and at an RSR for SCS suction line isolation valves SI-651, SI-652, SI-653, SI-654, SI-655, and SI-656. Valve position alarms are described in Subsection 5.4.7.2.3.

h) Open/closed and full range 0 to 100 percent position indication is provided in the MCR and at an RSR for SCS warm-up line isolation/flow control valves SI-690 and SI-691.

c. Piping All SCS piping is austenitic stainless steel. All piping joints and connections are welded, except for a minimum number of flanged connections that are used to facilitate equipment maintenance or accommodate component design.

The design features to prevent air entrainment during mid-loop operation are described in Subsection 5.4.7.2.6. The SCS piping is designed to accommodate venting the SCPs to the RCS, if necessary, after the pumps have been stopped.

High points in the SCS piping are minimized. Vent valves and the pipe arrangement design also provide system venting for reasonable assurance that maintenance can be performed on each component.

d. Valves The location of valves, along with their type, type of actuator, position during the normal operating mode of the plant, type of position indication, and failure position is shown in Figure 6.3.2-1.

1) Relief valves Protection against the overpressurization of components within the SCS is provided by conservatively designing the system piping, appropriate valving between high pressure sources and lower pressure piping, and by relief valves.

The pressure of the SCS suction lines, up to and including SI-653 and SI-654, is designed to be equal to the RCS design pressure. In addition, the pressure of the SCS discharge lines, up to and including SI-168 and SI-178 from DVI nozzles, is designed to be equal to the RCS design pressure. Relief valves 5.4-45 Rev. 2

APR1400 DCD TIER 2 are provided as required by applicable codes. All relief valves are of the totally enclosed, pressure tight type, with suitable provisions for gagging.

Thermal relief valves (SI-169, SI-187, SI-188, SI-287, SI-289, SI-422, SI-423, SI-450, SI-461, SI-462, SI-466, SI-469, and SI-467) are provided in the system to prevent overpressurization due to thermal transients in isolated sections of piping. A relief valve on each of the SCS suction lines (SI-179, SI-189) is sized to have sufficient capacity to provide LTOP for the RCS due to accidental operation of the SIPs, pressurizer heaters, the charging pump, and the reactor coolant pump (RCP) while in shutdown cooling (see Table 5.2-3).

These relief valves also can prevent overpressurization of the SCS.

2) Actuator-operated throttling and stop valves The failure position of each valve on loss of actuating signal or power supply is selected to provide reasonable assurance of safe operation. System redundancy is considered when defining the failure position of any given valve. Valve position indication is provided at the main control panel.

Valve control with appropriate status control on the main control panel is provided where necessary for efficient and safe plant operation. All motor operated valves consist of a manual override handwheel. All actuator operated valves have stem leakage controlled by a double packing with a lantern ring leak-off connection.

Isolation valves are provided to isolate equipment for maintenance and to align the SCS for operation (SI-310, SI-311, SI-312, SI-313 for SDCHX; SI-340, SI-341, SI-342, SI-343 for SCS/CSS cross connection; and SI-391, SI-393, SI-395 for ERVC injection). Throttle valves (SI-310, SI-312, SI-311, SI-313 for heat exchanger tube side flow control; SI-690, SI-691 for SCS warmup line flow control; SI-600, SI-601 for SCS flow control) are provided for remote control. The SCS suction isolation valves (SI-651, SI-653, SI-655, SI-652, SI-654, and SI-656) are interlocked to prevent overpressurizing the SCS. The ERVC injection line isolation valves (SI-391, SI-393) are normally power removed to prevent inadvertent ERVC injection.

3) Vent and drain valves 5.4-46 Rev. 2

APR1400 DCD TIER 2 Vent and drain valves are provided for reasonable assurance that maintenance can be performed on each SCS component.

e. Shutdown cooling pumps The function of the SCPs is to provide flow through the SDCHXs and reactor core for normal plant shutdown operation or for long term post-accident core cooling.

During normal power operation, the SCPs are isolated from the RCS by redundant motor-operated valves in series on the suction side of the pumps and a combination of redundant check valves and motor-operated valves on the discharge side of the pumps.

The shutdown cooling and containment spray functions are evaluated to select a single pump to serve both functions. The flow available with a single SCP is sufficient to either maintain an acceptable cooldown rate (41.7 °C/hr (75 °F/hr) maximum) during shutdown cooling operation or supply the CSS. Net positive suction head (NPSH) available exceeds NPSH required for both pumps for all conditions under which the pumps will be operated.

The SCP data are provided in Table 5.4.7-1. The design temperature for the SCPs is based upon the temperature of the reactor coolant at the initiation of shutdown cooling (176.7 °C (350 °F) nominal) plus a design tolerance, resulting in a design temperature of 204.4 °C (400 °F). The characteristic curve of an SCP is provided in Figure 5.4.7-4.

The SCPs are vertical, single-stage centrifugal units equipped with mechanical seals backed up by a bushing, with a leak-off to collect the leakage past the seals.

The seals are designed for operation with a pumped fluid temperature of 204.4 °C (400 °F). The pump motors are specified to have the capability of starting and accelerating the driven equipment, under load, to design point running speed within 5 seconds, based upon an initial voltage of 75 percent of the rated voltage at the motor terminals, and increasing linearly with time to 90 percent voltage within 3 seconds, and increasing to 100 percent voltage in another 2 seconds. The rated power of the SCP motor is to be determined at a sufficient level to operate at any point from shut-off to runout flow conditions.

5.4-47 Rev. 2

APR1400 DCD TIER 2 The pumps are provided with drain and flushing connections to facilitate reduction of radiation levels before maintenance. The pressure containing parts are fabricated from stainless steel; the internals are selected for compatibility with boric acid solutions. The pumps are provided with minimum flow protection (recirculation lines) to prevent damage when starting against an isolated discharge pathway.

The SCPs are designed for operation at any point on the characteristic curve from minimum bypass recirculation flow (miniflow) to runout flow. A miniflow path is provided for each pump to provide protection in the event that a pump is inadvertently operated against a closed discharge line and miniflow capacity is sufficient to protect the pump against hydraulic instability. Each miniflow path is routed from pump discharge back to pump suction and contains a heat exchanger for cooling and an orifice sized to meet pump vendor miniflow requirements. A locally operated manual valve is also provided to facilitate pump maintenance; the valve is locked open during all plant operating modes.

Runout flow for each SCP is limited when the SCS is set up during preoperational testing. A flow-limiting device, located in each SCS train downstream of the SCS/CSS discharge side cross-connection, prevents pump runout flow from exceeding the maximum operation flow to protect each SCP from possible damage.

In the SCS configuration, each SCP takes suction from an RCS hot leg and returns flow to the RCS through a DVI nozzle. In this closed recirculation loop, the RCS pressure does not affect the pump flow rate. The SCPs are not required to operate at a reduced flow, such as what may occur in a safety injection application following a small break LOCA. For post-accident long-term cooling, shutdown cooling is initiated after the RCS fluid level has stabilized and the RCS pressure and temperature have been reduced to shutdown cooling entry conditions. The SCP flow is manually controlled by the operator from the MCR. The SCP flow through each SDCHX is adjusted to control the RCS cooldown rate, and flow that bypasses each heat exchanger is adjusted to maintain total SCP flow in the range from the design point to the runout limit. The ability to maintain a constant total pump flow during shutdown cooling precludes low flow operations, described in the NRC Bulletin 88-04 (Reference 21), which may cause pump damage resulting from flow instability phenomena.

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APR1400 DCD TIER 2

f. Shutdown cooling pump miniflow HXs The shutdown cooling pump miniflow heat exchangers remove heat generated by running SCP during operating at miniflow (i.e., against a closed discharge path).

Required shutdown cooling pump miniflow heat exchanger performance is based on removing heat to limit the temperature increase.

5.4.7.2.3 Overpressure Prevention Overpressurization of the SCS by the RCS is prevented in the following ways:

a. The SCS suction line isolation valves (SI-651, SI-652, SI-653, and SI-654) are powered by four independent power supplies so that a fault in one power supply or valve will neither line up the RCS to either of the two SCS trains inadvertently nor prevent the initiation of shutdown cooling with at least one SCS train.

b. Relief valves SI-179 and SI-189, located on the SCS suction lines, are sized to provide LTOP of the RCS (see Subsection 5.2.2). Since the LTOP relief valve setpoint pressure is lower than the design pressure of the SCS, these valves also provide overpressure protection of the SCS. An interlock associated with the shutdown cooling suction isolation valves prevents the isolation valves from being opened at RCS for normal shutdown cooling pressures above 31.6 kg/cm2A (450 psia). The interlock setpoint is calculated considering tolerances necessary to provide reasonable assurance that the pressure at the valves will not exceed the LTOP valve setpoint when the SCS is aligned to the RCS for normal shutdown cooling. The instrumentation and controls that implement the interlock are described in Section 7.6.

c. The redundant SCS suction line isolation valves inside the containment are designed for full RCS pressure with the second valve SI-653 (Train A) and SI-654 (Train B) forming the pressure boundary and safety class change. The motor operators for SI-651 and SI-652 are sized to open or close against a differential pressure of 158.1 kg/cm2D (2,250 psid). This is consistent with Generic Letter 89-10 (Reference 22), which requires that safety-related motor-operated valves (MOVs) function when subjected to design basis conditions (both normal and abnormal events).

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APR1400 DCD TIER 2

d. Alarms on SI-651, SI-652, SI-653, and SI-654 annunciate when the SCS suction line isolation valves are not fully open (with concurrent low RCS temperature).

Also, if SI-651 and SI-653 or SI-652 and SI-654 valves are open, and RCS pressure increases to the maximum pressure for SCS operation, an alarm will notify the operator that a pressurization transient is occurring during low temperature conditions.

e. Relief valves are provided as discussed in Subsection 5.4.7.2.2.

f. System piping is conservatively designed and maximum utilization of welded connections is made.

g. The response of the SCS to intersystem LOCA challenges is presented in Subsection 19.2.2.5.

5.4.7.2.4 Applicable Codes and Classifications

a. The piping and valves from the RCS, up to and including SI-653 and SI-654, are designed to ASME Section III, NB.

b. The remainder of the piping, valves, and components of the SCS, with the exception of the above piping and valves from the RCS, are designed to ASME Section III, NC.

c. The component cooling water side of the SDCHX is designed to ASME Section III, ND.

d. The power operated valves are designed to applicable IEEE Standards.

e. The SCS is a seismic Category I system.

5.4.7.2.5 System Reliability Considerations The SCS is designed to perform its design function assuming a single failure, as described in Subsection 5.4.7.1.2. To provide reasonable assurance of availability of the SCS when required, redundant components and power supplies are used. The RCS can be brought to refueling temperature utilizing one of the two redundant SCS trains. However, with the design heat load, the cooldown would be considerably longer than the specified 96-hour 5.4-50 Rev. 2

APR1400 DCD TIER 2 time period. Since the SCS is essential for a safe (cold) shutdown of the reactor, it is a seismic Category I system and designed to remain functional in the event of an SSE.

The SCS does not utilize any pneumatically operated valves. The instrumentation controls and electric equipment pertaining to the SCS is designed to applicable portions of IEEE Standards 308 and 603. In addition to normal offsite power sources, physically and electrically independent and redundant emergency power supply systems are provided to power safety-related components (refer to Chapter 8 for further information).

For long-term performance of the SCS without degradation due to corrosion, only materials compatible with the pumped fluid are used. Environmental envelopes are specified for system components to provide reasonable assurance of acceptable performance in normal and applicable accident environments (refer to Section 3.11).

A limited leakage passive failure is defined as the failure of a pump seal or valve packing, whichever is greater. The maximum leakage is expected to be from a failed SCP seal.

Leakage to the pump compartment drains to the room sump. From there, it is pumped to the waste management system. The sump pumps in each room will handle expected amounts of leakage. If leakages are greater than the sump pump capacity, the affected SCS train will be isolated. In the event of a limited leakage passive failure in one train of the SCS, continued core cooling is provided by the unaffected independent SCS train.

The limited leakage passive failure is identified via appropriate leak detection provisions.

Makeup of the leakage is provided by manually aligning the SIS to the IRWST, or by opening the safety injection tank isolation valves. The affected SCS train can then be isolated and core cooling continued with the other train.

5.4.7.2.6 Manual Actions

a. Plant cooldown Plant cooldown is a series of manual operations that bring the reactor from hot shutdown to cold shutdown.

Cooldown to approximately 176.7 °C (350 °F) is accomplished by releasing steam from the secondary side of the steam generators. An inadvertent SIAS or safety injection tank (SIT) discharge is precluded during a controlled cooldown by manually decreasing the SIAS setpoint, and depressurizing and isolating the SITs.

5.4-51 Rev. 2

APR1400 DCD TIER 2 When the RCS temperature and pressure decrease to 176.7 °C (350 °F) and the maximum pressure for SCS operation (31.6 kg/cm2A (450 psia)), the SCS is used.

The RCS needs to be depressurized to below the maximum pressure for SCS operation in order to clear the permissive SCS interlock (see Subsection 5.4.7.2.3).

If the SCS suction line relief valves (SI-179 and SI-189) are not aligned to the RCS before cold leg temperature is reduced to below the maximum RCS cold leg temperature requiring LTOP, an alarm will notify the operator to open the SCS suction line isolation valves (SI-651, SI-652, SI-653, and SI-654). The maximum temperature requiring LTOP is based upon the evaluation of applicable RCS pressure/temperature curves (see Subsection 5.2.2.2.2.2).

Shutdown cooling is initiated using the SCPs. The SCS is warmed up and then placed in operation.

A maximum rate of cooldown (not to exceed 41.7 °C/hr (75 °F/hr)) is maintained by adjusting the flow rate of reactor coolant through the SDCHXs, utilizing the SDCHX outlet flow control valves in conjunction with the SDCHX bypass flow control valves. With the shutdown cooling flow indicators, the operator maintains a total shutdown cooling flow rate by adjusting the amount of coolant, which bypasses the SDCHXs.

When the system is at first put into operation, the temperature difference for heat transfer across the SDCHX is large, and only a portion of the total flow from the SCPs is diverted through the heat exchangers. As the cooldown proceeds, the temperature differential across the heat exchanger decreases, and the flow rate through the heat exchangers is increased to maintain the maximum permissible cooldown rate.

The flow to the SDCHXs is increased periodically until full SCP flow through the heat exchangers is attained. A graph of RCS temperature versus time after shutdown for a typical normal design basis cooldown is presented in Figure 5.4.7-1.

Shutdown cooling is continued throughout the entire period of plant shutdown to maintain an average refueling water temperature of 48.9 °C (120 °F) or less.

Whenever shutdown cooling is in operation, shutdown purification flow may be initiated through the CVCS.

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APR1400 DCD TIER 2

b. Plant heatup Plant heatup is a manual operation process that brings the RCS from cold shutdown to hot standby. The SDCHXs are bypassed to maintain flow through the core without the heat removal effect of the heat exchangers. Flow can be initiated to the heat exchangers if necessary to control the heatup rate. When the RCPs can be run and the pressure-temperature limitations for LTOP are no longer necessary, the SCPs are stopped and the system is isolated for the standby mode.

c. Abnormal operation

1) Initiation of shutdown cooling with the most limiting single failure (loss of one shutdown cooling train) can be accomplished via plant procedures using equipment in the operable train.

2) The SCPs can be used alternatively as CSPs. In addition, the CSPs can be used alternatively as SCPs.

3) The SCPs, in conjunction with the SDCHXs, can be used for IRWST cooling.

d. Design basis event operations Following certain DBEs (feedwater line break, small break LOCA, steam line break, or loss of offsite power), shutdown cooling can be initiated with RCS hot leg conditions that exceed the normal shutdown cooling initiation temperature of 176.7 °C (350 °F). However, shutdown cooling is never initiated at conditions that exceed the design temperature of 204.4 °C (400 °F) for the SCS components.

e. Operator response to an LTOP transient alarm During SCS operation, if suction line isolation valves SI-651 and -653 or SI-652 and -654 are open, and RCS pressure exceeds the maximum pressure for SCS operation, a LTOP transient alarm will occur in the MCR. The LTOP relief valves SI-179 and SI-189, located downstream of SI-653 and SI-654, respectively, will open if pressure at the valve increases to the relief valve set pressure of 37.3 kg/cm2 (530 psig). The limiting events that cause a pressurization transient during low temperature conditions are evaluated in Subsection 5.2.2. During 5.4-53 Rev. 2

APR1400 DCD TIER 2 plant startup, the LTOP transient alarm will also occur if the SCS suction valves fail to isolate the SCS from the RCS as pressure is increased.

The principal operator actions taken any time the LTOP transient alarm occurs are to identify and terminate the cause of the pressurization. LTOP relief valve availability is maintained throughout the transient, as long as overpressure protection is required.

During RCS heatup, LTOP relief valve availability is required up to an RCS temperature equal to the LTOP disable temperature, as described in Subsection 5.2.2.2.2.2. The operator will isolate the SCS and LTOP relief valves from the RCS prior to exceeding an RCS temperature of 176.7 °C (350 °F). During RCS heatup between the LTOP disable temperature and 176.7 °C (350 °F) if an LTOP transient alarm occurs, the operator will close the SCS isolation valves to prevent a depletion of RCS inventory. At temperatures above the LTOP disable temperature, overpressure protection of the RCS is provided by the pressurizer POSRVs. The operator assesses SCS status and overall plant status prior to proceeding with RCS heatup.

If the operator determines that the LTOP transient alarm is due to an event at RCS temperature conditions requiring the protection via LTOP relief valve, the operator closes downstream SCS suction line isolation valves SI-655 and SI-656 to minimize the impact of the transient on the rest of the SCS. After RCS pressure is reduced below the pressure that corresponds to the relief valve blowdown pressure, the operator confirms that the LTOP relief valves have been reseated by monitoring RCS pressure and level and IRWST. If an LTOP relief valve is stuck open, the operator takes actions to provide adequate RCS makeup inventory and core cooling.

f. Operation with reduced RCS inventory Reduced inventory including mid-loop operation is necessary for increasing the plant availability. During this operation, the RCS water level is lowered to below the reactor vessel flange. When the RCS water level abnormally decreases, air may be ingested into the shutdown cooling system with the possibility of affecting the SCS. The RCS level is maintained higher than the RCS low water level of 8.3 cm (3.28 inch) above the loop center, and a SCS flow rate of 14,385 to 5.4-54 Rev. 2

APR1400 DCD TIER 2 15,710 L/min (3,800 to 4,150 gpm) is maintained for decay heat removal and prevention of an air ingestion.

Reactor coolant level is monitored during the reduced inventory condition by the Refueling Water Level Indication System (RWLIS). The RWLIS consists of the Permanent Refueling Water Level Indication System (PRWLIS), the Local Refueling Water Level Indication System (LRWLIS), and the Ultrasonic Level Measurement System (ULMS).

The PRWLIS (Wide Range) monitors coolant level between 10 % level of the PZR and the bottom of the hot leg. The level indication of the PRWLIS (WR) is provided in the MCR. Upper level taps are connected with the PZR pressure instrument sensing lines. Lower level taps are connected with the SCS suction lines located on the bottom of the hot legs. Two level instrumentations are provided for monitoring coolant level.

The PRWLIS (Narrow Range) monitors coolant level between the top of the hot leg and 2 inch above the bottom of the hot leg. Level indication and high, low and low-low alarms are provided in the MCR. Upper level taps are connected with piping to the DVI nozzles. Lower level taps are connected with the SCS suction lines located on the bottom of the hot legs. Two level instrumentations are provided for monitoring coolant level for Loop1 and Loop 2, separately.

The LRWLIS (Sight Glass) has a minimum visible span of 150 inches (3.81 m) above the bottom of the hot leg. The local level indicator is located outside the secondary shield. High, low and low-low alarms are provided in the MCR.

Upper level taps are connected with the PZR pressure instrument sensing lines.

Lower level taps are connected with the SCS suction lines located on the bottom of the hot legs. Two level instrumentations are provided for monitoring coolant level.

Two ULMS are installed temporarily on the bottom of both hot legs to monitor coolant level of hot legs during mid-loop operation. The ULMS monitors coolant level between 8.4 inch above the hot leg bottom to the hot leg top. High, low and low-low alarms are provided in the MCR.

The performance of the SCS operation is verified at the RCS mid-loop level during preoperational testing. For the air ingestion RCS cooldown rate, the 5.4-55 Rev. 2

APR1400 DCD TIER 2 shutdown cooling flow rate, SCP motor current, and SCP suction/discharge pressure are monitored.

The APR1400 design includes the features listed below to facilitate continued SCS operations during reduced RCS inventory in conformance with Generic Letter (GL) 88-17. The Shutdown Evaluation Report (Reference 23) provides an assessment of shutdown operation risk in conformance with GL 88-17.

1) Two independent instrumentation systems are provided for RCS level measurement. These instruments function to monitor the RCS level in order to preclude SCS suction line vortexing and subsequent air entrainment.

Level instrument types and corresponding instrumentation ranges are optimized to encompass all reduced RCS inventory conditions.

2) Two independent thermocouples are provided to measure core exit temperature.

3) Instruments that monitor the state of the SCS performance (such as pump suction pressure, pump discharge pressure, flow rate, pump motor current, and RCS heat removal degradation) are provided. These instruments function to provide sufficient information to indicate an approaching SCS malfunction due to the formation of vortexing and subsequent air entrainment.

4) SCS suction line isolation valves are not automatically closed in the event of RCS pressurization during the shutdown cooling operation. This precludes a loss of shutdown cooling by automatic closure of the isolation valves.

Although the features described above do not describe SCS instrumentation completely, the descriptions are provided in this section because they focus on precluding SCS failures due to loss of the SCP operations.

g. Refueling pool drain operation The SCS is used to drain refueling water from the refueling pool to the IRWST during refueling. During this operation, one SCS train transfers water while the other train removes decay heat. This is done by pumping water from the RCS through the pump full flow test line to the IRWST.

5.4-56 Rev. 2

APR1400 DCD TIER 2 5.4.7.3 Performance Evaluation The capability of the SCS to reduce RC temperature is evaluated using heat balance calculations between the RCS and SCS at stepped intervals following the initiation of SCS operation. The stepped decrease versus time of component cooling water (CCW) temperature though the shell side of SDCHX is conservatively assumed, based on the maximum CCW temperature of the CCWS design. The basic purpose of shutdown cooling process using the SCS is to transfer the decay of the primary loop (RCS) to the secondary loop (CCW). Once the key process parameters such as SCS initiation conditions, RCS volume, effective heat transfer area, heat transfer rate, resistance coefficient of SDCHX, and SCP miniflow HX are identified as the input parameters, the time-dependent decay heat removal performance is analyzed. At each time step a series of equations is used in an interactive process to determine the maximum amount of heat removal through the SDCHX and SCP miniflow HX.

The design condition of the SCS is taken at 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after plant shutdown. At this point, the design basis is to maintain a 48.9 °C (120 °F) average refueling temperature with a CCW temperature of 35 °C (95 °F). Two SDCHXs and two SCPs are assumed to be in operation at the design flow. The SDCHX size is determined at this point because it requires the greatest heat transfer area due to the relatively small T between primary fluid and component cooling water. The design input heat load at 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> 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, assuming an average reactor core burnup of two fuel cycles. Additional energy input to the RCS from two SCPs running at design flow rate is also included with no credit taken for component energy losses to the external environment. The cooldown rate is limited to a maximum of 41.7 °C/hr (75 °F/hr) throughout the cooldown. A typical two-train cooldown curve is shown in Figure 5.4.7-1.

With the most limiting single active failure in the SCS, the RCS temperature can be brought to 93.3 °C (200 °F) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following shutdown using one SCP and one SDCHX, assuming that the RCS pressure and temperature are reduced to SCS initiation conditions by other heat rejection means within 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />. A typical single-train cooldown curve is shown in Figure 5.4.7-2.

The SCS is designed using a philosophy of total physical separation of redundant trains so that the system can carry out its safety function assuming a single active failure during both normal and short-term (period of operation of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following an initiating event) post-accident modes and a single active or passive failure during long-term post-accident 5.4-57 Rev. 2

APR1400 DCD TIER 2 modes after event initiation. Total train separation provides reasonable assurance that a single failure in one train cannot preclude the other train from accomplishing its safety functions. A failure modes and effects analysis for the SCS is presented in Table 5.4.7-2.

Reasonable assurance of adequate sampling capability of the SCS is provided for all modes of SCS operation to verify boron concentration and fission product activity.

5.4.7.3.1 Performance Evaluation Assuming the Most Limiting Single Failure and Only Onsite Power Available The APR1400 is designed to have decay heat removal capability by natural circulation.

The flow by natural circulation shall be enough that the temperature increase across the core during natural circulation is less than that of the full power design condition at the same core inlet temperature and pressure conditions.

The results of a computer simulation of a natural circulation cooldown (NCC) of NSSS from normal operation to SCS entry condition are presented in this section. The simulation is in conformance with BTP 5-4 requirements. These requirements include the use of only safety-grade equipment, the concurrent loss of offsite power, and a single failure.

5.4.7.3.1.1 Natural Circulation Cooldown Sequence The following sequence was followed to achieve a successful NCC analysis:

a. Following the reactor trip, the operator manually controls the ADVs to restore and maintain the secondary pressure to no-load hot standby conditions (77.3 kg/cm2A (1,100 psia)).

b. The steam generator water level is restored, and then maintained at the normal water level by manually controlling the auxiliary feedwater flow rate within the available capacity of the auxiliary feedwater system.

c. After the 4-hour hot standby period, the RCS is depressurized by using the pressurizer vent until the RCS subcooling margin reaches the minimum limit value of 15 °C (27 °F).

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APR1400 DCD TIER 2

d. RCS cooldown with a 27.8 °C/hr (50 °F/hr) cooldown rate is initiated. This rate is slower than the administrative maximum cooldown rate of 41.7 °C/hr (75 °F/hr) and hence conservatively increases the auxiliary feedwater usage.

e. One of the three SIS pumps is throttled (three trains of the SIS are available due to the assumed single failure of one diesel generator) for the RCS boration and inventory control.

f. The pressurizer level is maintained between 30 percent and 70 percent.

g. The RCS subcooling margin is controlled between 15 °C (27 °F) and 83.3 °C (150 °F).

h. The operator utilizes the pressurizer vent of the RCGVS to manually depressurize the RCS. This is the principal means of achieving the necessary SCS pressure entry conditions. The pressurizer vent is actuated during conditions of high RCS subcooling and terminated when the subcooling margin decreases to the minimum value or when steam void in the reactor vessel upper head (RVUH) reaches a maximum value.

i. The operator uses the RVUH gas vent of the RCGVS to reduce the volume of an existing steam void and draw colder RCS fluid into the RVUH, thus cooling the RVUH region and depressurizing the RCS.

j. The operator performs the cooldown process until the RCS subcooling margin reaches the maximum value after the steam void is collapsed by the RVUH gas vent.

5.4.7.3.1.2 Natural Circulation Cooldown Analysis Results Immediately following the loss of offsite power with the assumed loss of power to the RCPs, flow through the core decreases as the RCPs coast down. This immediately results in a core protection calculator reactor trip on low reactor coolant pump shaft speed. Full natural circulation flow is then established in the RCS in less than 10 minutes.

Shortly after the reactor trip, the operator utilizes the ADVs to stabilize the NSSS at hot standby conditions. Pressurizer level stabilizes at approximately 40 percent. The auxiliary feedwater flow to the steam generators is manually controlled to slowly refill the 5.4-59 Rev. 2

APR1400 DCD TIER 2 steam generators without overcooling the RCS. The plant is maintained at hot standby for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> consistent with the BTP 5-4 requirements.

At 4.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> after the initiating event (the loss of offsite power), the operator opens pressurizer gas vent valve of the RCGVS to depressurize the RCS to the point where the RCS subcooling margin decreases to 15 °C (27 °F). The use of the pressurizer gas vent valve serves to decreases the RCS pressure to slightly below the minimum shutoff head of the safety injection pumps. The operator then manually starts the safety injection pumps to provide inventory control with borated water during the subsequent RCS cooldown.

After the pressure reaches 113.6 kg/cm2A (1,616 psia), which corresponds to the RCS subcooling margin of 15 °C (27 °F), the operator begins RCS cooldown with a 27.8 °C/hr (50 °F/hr) cooldown rate by increasing steam flow through ADVs.

At 6.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, the RCS subcooling margin exceeds the maximum limit of 83.3 °C (150 °F),

at which the operator stops cooldown to prevent RCS overcooling and opens the pressurizer gas vent valve.

As the RCS pressure decreases, the coolant in the RVUH reaches saturation condition and a steam void forms. The steam void in the RVUH continues to increase in size as long as the pressurizer gas vent valves remain open because the RVUH fluid temperature exceeds the saturation temperature and the fluid vaporizes. When the steam void in the RVUH increases to 21.2 m3 (750 ft3), the operator closes the pressurizer gas vent valves and then opens the RVUH gas vent valves to collapse the steam void.

At 7.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, the steam void in the RVUH is reduced to the smallest measurable value, and the operator closes the RVUH gas vent valve and resumes the RCS cooldown with a cooldown rate of 27.8 °C/hr (50 °F/hr).

At 9.1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the RCS subcooling is again reached at the maximum limit of 83.3 °C (150 °F), and the operator stops cooldown to relieve the RCS overcooling and opens the pressurizer gas vent valve. This avoids exceeding the hot leg subcooling limit and reduces the RCS pressure. The steam void in the RVUH rapidly grows again to 21.2 m3 (750 ft3) where the operator closes the pressurizer gas vent valve and re-opens the RVUH gas vent valve in order to collapse the void. After the RVUH void decreases, the operator resumes the RCS cooldown.

5.4-60 Rev. 2

APR1400 DCD TIER 2 At 10.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, the RCS pressure and temperature reach the shutdown cooling entry conditions of 31.6 kg/cm2A (450 psia) and 176.7 °C (350 °F), respectively. The final collapsing of the steam void that still exists in the RVUH is accomplished using a combination of the RVUH gas vent and the SIS.

The amount of safety-grade auxiliary feedwater used is 1,140 m3 (300,000 gal). This demonstrates that the NCC to the shutdown cooling system entry conditions, according to the BTP 5-4 requirements, can be performed well within the limit of auxiliary feedwater storage tanks capacity (i.e., minimum capacity of 1,514 m3 [400,000 gal]). The NCC analysis results are provided in Figures 5.4.7-6 through 5.4.7-12.

5.4.7.3.1.3 Conclusions The NSSS NCC analysis results demonstrate that a cooldown and depressurization to the SCS entry conditions are achievable within the BTP 5-4 requirements. The total auxiliary feedwater usage is well within the minimum available capacity. It is concluded that the NSSS can be cooled and depressurized to the SCS entry conditions in conformance with the restrictive assumptions of the BTP 5-4.

5.4.7.4 Tests and Inspections 5.4.7.4.1 Preoperational Testing Preoperational tests are conducted to verify the proper operation of the SCS. The preoperational tests include calibration of instrumentation, verification of adequate cooling flow, and verification of the operability of all associated valves. In addition, a preoperational hot functional performance test is made on the installed SDCHXs as a part of the pre-core hot functional test programs. Refer to Chapter 14 for further details on these tests.

For the preoperational test for the SCP miniflow rate, ultrasonic flow meters are temporarily installed in the SCP miniflow heat exchanger inlet and outlet lines. The SCS also undergoes a series of preoperational hydrostatic tests conducted in accordance with ASME Section III.

Preoperational test results are used to perform analyses to confirm that the as-built SCS fulfills operability and provides a level of performance that satisfies design analyses for a safe cold shutdown.

5.4-61 Rev. 2

APR1400 DCD TIER 2 The LTOP relief valves, SI-179 and SI-189, located on the SCS suction line are shop-tested.

Relieving capacity of the valves is certified in accordance with ASME Section III, NC-7000. Valve set pressure is verified by actual shop testing with water.

An inspection of the as-built piping is conducted to verify that the SCP has no loop seals and is oriented downward or horizontal except for an upward section connecting to the pump suction flange.

5.4.7.4.1.1 Flow Testing Each installed SCS train is tested to measure SCP developed differential pressure at a flow rate equal to or greater than the pump design flow rate. An analysis is performed to convert the measured differential pressure at the test temperature to a pump head. Tests and analyses are performed with SCS suction and return aligned to the RCS, and aligned to the IRWST.

Functional tests are performed with flow aligned to the RCS to confirm that the maximum flow rate does not exceed the limit. These tests are performed at an RCS temperature of 176.7 °C (350 °F).

Testing is performed to confirm that the SCP return line to the IRWST allows each SCP to be operated at a flow equal to or greater than design flow during inservice testing.

Analyses are performed to convert the measured pump differential pressure to a pump head.

The available NPSH to the SCPs is determined based on as-built elevations, piping arrangements and system performance parameters measured during testing. Measured pump suction pressures and flow rates are used in an analysis to demonstrate that adequate NPSH is provided to each SCP assuming the following conditions:

a. Minimum RCS water level and maximum RCS water temperature for reduced inventory operation

b. Maximum design basis RCS water temperature for SCS operation (not at reduced inventory)

c. Maximum design basis IRWST water temperature and minimum IRWST water level for the SCS operating in the IRWST cooling mode

d. As-built pressure losses for pump inlet piping and components 5.4-62 Rev. 2

APR1400 DCD TIER 2 The calculated minimum available NPSH meets or exceeds the NPSH required by the pump vendor.

Testing is performed to demonstrate that a containment spray pump (CSP) performs the pumping function of the designated SCP. The CSP is tested by aligning its suction to the SCP suction piping and its discharge to the SCP discharge piping. The CSP provides a flow rate through the SDCHX that is greater than or equal to the SCP design flow rate.

5.4.7.4.1.2 Heat Removal Capability Tests are performed to measure shutdown cooling flow rates at the combined discharge of the SDCHX and heat exchanger bypass line using permanently installed instrumentation.

A test is performed on SDCHXs during pre-core hot functional testing. Shutdown cooling and component cooling water flow rates to each heat exchanger, reactor coolant temperatures at SDCHX inlet and outlet, and component cooling water temperature at SDCHX inlet are measured. Test results are used to verify that the heat removal capability of each SDCHX meets the heat removal capability required to achieve a safe cold shutdown. The performance demonstrates a heat removal capacity to remove heat from the reactor coolant and transfer heat to the component cooling water system.

5.4.7.4.2 Inservice Testing and Inspection Inservice testing of SCPs and safety-related valves is addressed in Subsection 3.9.6.

Inservice inspection of SCS piping and components is addressed in Section 6.6 and Subsection 5.2.4.

5.4.7.4.3 Design Features for Minimization of Contamination The APR1400 is designed with specific features to meet the requirements of 10 CFR 20.1406 and Regulatory Guide 4.21. The basic principles of NRC RG 4.21 and the methods of control suggested in the regulations are grouped into four design objectives and two operational objectives, as described in Subsection 12.4.2. The following evaluation summarizes the primary features that address the design and operational objectives for the shutdown cooling system.

The SCS has been evaluated for leakage identification from the SSCs that contain radioactive or potentially radioactive materials, the areas and pathways where probable 5.4-63 Rev. 2

APR1400 DCD TIER 2 leakage may occur, and the methods of leakage control incorporated in the design of the system. The leak identification evaluation indicated that the SCS is designed to facilitate early leak detection and the prompt assessment and response to manage collected fluids.

Thus, unintended contamination to the facility and the environment is minimized and/or prevented by the SSC design, operational procedures and programs, and inspection and maintenance activities.

Prevention/Minimization of Unintended Contamination

a. The SCS components are located in individual cubicles inside the auxiliary building. The floors are sloped, coated with epoxy, and provided with drains that are routed to the local drain hubs and sumps. This design approach prevents unintended contamination of the facility and the environment.

b. The SCS components (pumps, heat exchangers, piping) are fabricated from stainless steel and are of welded construction, thus minimizing leakage and unintended contamination of the facility and the environment.

Adequate and Early Leak Detection

a. The SCS is used only in post shutdown periods. Any leakage is drained to the floor and is collected in the local sump, which is equipped with a liquid level switch. If leakage exceeds a predetermined liquid level within the sump, the level switch initiates an alarm in the MCR for operator action to investigate the source of leakage.

Reduction of Cross-Contamination, Decontamination, and Waste Generation

a. The SSCs are designed with life-cycle planning through the use of nuclear industry-proven materials compatible with the chemical, physical, and radiological environment, thus minimizing waste generation.

b. The pumps are equipped with drains directly routed to the radioactive drain system.

This design approach minimizes contamination to the facility and the environment.

c. The SCS is isolated from the RCS when the RCS is at high pressure (during normal power operation). The interlocks associated with six valves on the two SCS suction lines are provided to prevent the valves from opening in the event that 5.4-64 Rev. 2

APR1400 DCD TIER 2 RCS pressure exceeds SCS operating pressure, thus minimizing cross-contamination between the systems.

Decommissioning Planning

a. The SSCs are designed for extended service life and are fabricated as individual assemblies for easy removal.

b. The SSCs are designed with decontamination capabilities. Design features, such as welding techniques and surface finishes, are included to minimize the need for decontamination and the resultant waste generation.

c. The SCS is designed with minimal embedded piping for contaminated or potentially contaminated fluid, which minimizes the potential for unintended contamination of the environment.

Operations and Documentation

a. The COL applicant is to prepare operational procedures and maintenance programs related to leak detection and contamination control of SCS (COL 5.4(3)).

Procedures and maintenance programs are to be completed before fuel is loaded for commissioning.

b. The COL applicant is to maintain complete documentation of the system design, construction, design modifications, field changes, and operations of SCS (COL 5.4(4)). Documentation requirements are included a COL Information Item.

Site Radiological Environmental Monitoring The SCS is on standby mode during normal power operation and is designed to have low levels of contamination. Through monitoring, in-service inspection, and lessons learned from industry experiences, the integrity of the SCS is maintained, resulting in a very low level of contamination of the facility. Hence, the SCS is not required to be part of the site radiological environmental monitoring program.

5.4.8 Reactor Water Cleanup System (Boiling Water Reactors Only)

This section is not applicable to the APR1400.

5.4-65 Rev. 2

APR1400 DCD TIER 2 5.4.9 [Reserved]

5.4.10 Pressurizer 5.4.10.1 Design Bases The pressurizer is designed to:

a. Maintain RCS operating pressure so that the minimum pressure during operating transients is above the setpoint for the safety injection actuation signal (SIAS) and low pressure reactor trip and so that the maximum pressure is below the high pressure reactor trip setpoint.

b. Withstand the consequences of the design transients of Table 3.9-1 without failure or malfunction.

c. Provide sufficient water volume in the pressurizer to prevent uncovering the heaters as a result of a reactor trip.

d. Provide sufficient water volume to prevent pressurizer heaters from being uncovered by the outsurge following step load decreases of 10 percent starting within the range of 100 percent to 15 percent of full-rated power or a 5 percent per minute ramp decrease from 100 percent to 15 percent of full-rated power.

e. Provide sufficient steam volume to allow acceptance of the insurge resulting from any loss of load transient without liquid or two-phase flow reaching the pressurizer pilot-operated safety relief valve nozzles.

f. Minimize the total reactor coolant mass change and associated charging and letdown flow rates in order to reduce the quantity of wastes generated by reactor power changes.

g. Provide sufficient pressurizer heater capacity to heat up the pressurizer, filled with water at the zero power level, at a rate that provides reasonable assurance of a pressurizer temperature (and thus pressure) that will maintain an adequate degree of subcooling of the water in the reactor coolant loop as it is heated by core decay heat and/or pump work from the reactor coolant pumps.

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APR1400 DCD TIER 2

h. Contain a total water volume that does not adversely affect the total mass and energy released to the containment during the maximum hypothetical accident.

i. Provide reasonable assurance that, in addition to being specified as seismic Category I, the pressurizer vessel, including heaters, baffles, and supports is designed so that no damage to the equipment is caused by the frequency ranges of 19-24 cps and 118-143 cps. The lower frequency is produced by vibratory excitations associated with RCP rotating speed. The design basis for the higher frequency consists of a pressure pulse of 0.56 kg/cm2 (8 psi), which diminishes internally within the vessel.

j. Maintain the pressurizer at normal operating pressure during hot standby conditions by taking into account the energy balance of maximum heat loss from the pressurizer and the pressurizer heater capacity. This capability is provided by redundant trains of heaters powered from off-site power and Class 1E emergency power. The Class 1E emergency power is used if off-site power is not available.

k. Maintain sufficient spray flows to keep the pressure below the reactor trip setpoint during power maneuvers and loss of load transients.

l. Provide the adequate pressurizer size and spray capacity so the pressurizer pilot-operated safety relief valves are not actuated by overpressure events initiated by normal operation transients.

5.4.10.2 System Description 5.4.10.2.1 Pressurizer The pressurizer, as shown in Figure 5.4.10-1, is a vertically mounted, bottom supported, cylindrical pressure vessel. Replaceable direct immersion electric heaters are vertically mounted in the bottom head. The pressurizer is furnished with nozzles for the spray, surge, and pilot-operated safety relief valves, and with pressure, temperature, and level instrumentation. A manway is provided in the top head for access for inspection of the pressurizer internals. The pressurizer surge line is connected to one of the reactor coolant hot legs and the spray lines are connected to two of the cold legs at the reactor coolant pump discharge. Heaters are supported inside the pressurizer to preclude damage from vibration and seismic loadings. Principal design parameters are listed in Table 5.4.10-1.

5.4-67 Rev. 2

APR1400 DCD TIER 2 The pressurizer heaters are single-unit, direct immersion heaters that protrude vertically into the pressurizer through sleeves welded in the lower head. Each heater is internally restrained from high amplitude vibrations and can be individually removed for maintenance during plant shutdown.

The pressurizer and surge line are located entirely above the reactor coolant loops. The surge line is continuously rising from the hot leg nozzle to the pressurizer, thus providing reasonable assurance that the line contains no water traps. The pressurizer surge line is sized and arranged to minimize the flow resistance.

Each pressurizer spray line includes an isolation valve (RC-442, RC-443), which can be remotely shut from the MCR to prevent RCS depressurization in the event the pressurizer spray valve in the line fails to close.

The maximum allowable pressure drop through the pressurizer spray line piping only is 1.62 kg/cm2D (23 psid) at a total flow rate of 28.4 L/s (450 gpm) and at a water temperature of 290.6 °C (555 °F).

The pressurizer is designed and fabricated in accordance with the ASME Code listed in Table 5.2-1. The interior surface is clad with weld deposited stainless steel or Ni-Cr-Fe alloy.

5.4.10.2.2 Instrumentation The pressurizer is equipped with nine nozzles for the pressurizer level, pressure and temperature measurements. Seven of the nine nozzles are installed on the top head of the pressurizer, and the other two are installed in the bottom head. Two temperature nozzles are installed in the lower shell portion of the pressurizer to monitor water temperature.

The bottom head level nozzles are provided with the internal nozzle extensions to minimize crud buildup in the nozzles. The temperature nozzles are compatible with the thermowells.

The instrument nozzles that require socket-welded end preparations meet the requirements of ASME B16.11.

See Section 7.7 for the instrumentation and control systems that are associated with the pressurizer pressure and water level.

5.4-68 Rev. 2

APR1400 DCD TIER 2 5.4.10.2.3 Operation The total volume of the pressurizer is established by consideration of the factors given in Subsection 5.4.10.1. To account for these factors and to provide adequate margin at all power levels, the water level in the pressurizer is programmed as a function of average coolant temperature as shown in Figure 5.4.10-2, in conjunction with Figure 5.4.10-3.

High or low water level error signals result in the control actions shown in Figure 5.4.10-4.

The pressurizer surge line is sized to accommodate the flow rates associated with the RCS expansion and contraction due to the transients specified in Subsection 3.9.1.

The pressurizer maintains RCS operating pressure and, in conjunction with the chemical and volume control system (CVCS), Subsection 9.3.4, compensates for changes in reactor coolant volume during load changes, heatup, and cooldown. During full-power operation, the pressurizer is about half full of saturated steam.

RCS pressure may be controlled automatically or manually by maintaining the temperature of the pressurizer fluid at the saturation temperature corresponding to the desired system pressure. A small continuous spray flow is maintained to the pressurizer to avoid stratification of pressurizer boron concentration and to maintain the temperature in the surge and spray lines, thereby reducing thermal shock as the spray control valves open.

An auxiliary spray line is provided from the charging pumps to permit pressurizer spray during plant heatup, or to allow cooling if the reactor coolant pumps are shut down.

During load changes, the pressurizer limits pressure variations caused by expansion or contraction of the reactor coolant. The average reactor coolant temperature is programmed to vary as a function of load as shown in Figure 5.4.10-3. A reduction in load is followed by a decrease in the average reactor coolant temperature to the programmed value for the lower power level. The resulting contraction of the coolant lowers the pressurizer water level, causing the reactor system pressure to decrease. This pressure reduction is partially compensated by flashing of pressurizer water into steam. In the event of a pressure level decrease, the two CVCS letdown orifice isolation valves close, and the throttling openings of the CVCS charging control valve are automatically controlled to add coolant to the RCS and restore pressurizer water level.

When the main steam demand is increased, the average reactor coolant temperature is raised in accordance with the coolant temperature program. The expanding coolant from the reactor coolant piping hot leg enters the bottom of the pressurizer through the surge line, 5.4-69 Rev. 2

APR1400 DCD TIER 2 compressing the steam and raising RCS pressure. The increase in pressure is moderated by the condensation of steam during compression and by the decrease in bulk temperature in the liquid phase. If the pressure increase is large enough, the pressurizer spray valves open and spray coolant from the reactor coolant pump discharges (cold leg) into the pressurizer steam space. The relatively cold spray water condenses some of the steam in the steam space, limiting the system pressure increase. The programmed pressurizer water level is a RCS average temperature dependent function. A high level error signal, produced by an in-surge, causes the charging control valve modulated to a closing direction, thus restoring the pressurizer to the programmed level. Small pressure and primary coolant volume variations are accommodated by the steam volume that absorbs flow into the pressurizer, and by the water volume that allows flow out of the pressurizer.

A number of the heaters are connected to proportional integral controllers, which adjust the heat input to account for steady-state losses and the continuous spray flow, and to maintain the desired steam pressure in the pressurizer. The remaining heaters are connected to on-off controllers. These heaters are normally de-energized but are automatically turned on by a low pressurizer pressure signal or a high level error signal. This latter feature is provided because load increases result in an in-surge of relatively cold coolant into the pressurizer, thereby decreasing the bulk water temperature. The CVCS acts to restore level, resulting in a transient pressure below normal operating pressure. To minimize the extent of this transient, the on-off controlled backup heaters are energized, contributing more heat to the water. A low-low pressurizer water level signal de-energizes all heaters to prevent heater damage before they are uncovered. The pressure control program is shown in Figure 5.4.10-5.

5.4.10.3 Design Evaluation It is demonstrated by analysis in accordance with requirements for ASME Section III, Class 1 vessels that the pressurizer is adequate for all normal operating and transient conditions expected during the life of the facility. Following completion of fabrication, the pressurizer is subjected to the required ASME Section III hydrostatic test and post-hydrostatic test nondestructive testing.

During hot functional testing, the transient performance of the pressurizer is checked by determining its normal heat losses and maximum depressurization rate. This information is used in setting the pressure controllers. Reasonable assurance of the structural integrity 5.4-70 Rev. 2

APR1400 DCD TIER 2 of the pressurizer is further obtained from the inservice inspections performed in accordance with ASME Section XI and described in Section 5.2.

Overpressure protection of the RCS is provided by four pilot-operated safety-relief valves.

See Subsection 5.4.14.

5.4.10.4 Test and Inspection Prior to and during fabrication of the pressurizer, nondestructive testing is performed in accordance with the requirements of ASME Section III. Table 5.4.10-2 summarizes the pressurizer inspection program, which also includes tests not required by the Code. See Subsection 5.2.4 for inservice inspections of the pressurizer.

5.4.11 Pressurizer Relief Tank The in-containment refueling water storage tank (IRWST) is used as the pressurizer relief tank. The IRWST collects and condenses the steam discharged from the pressurizer through the pilot-operated safety-relief valves (POSRVs) and the reactor coolant gas vent system (RCGVS).

The POSRVs on the pressurizer are described in Subsections 5.2.2.4.1 and 5.4.14. The RCGVS is described in Subsection 5.4.12.

5.4.11.1 Design Bases The IRWST is an integral part of the containment building internal structure and is a reinforced concrete structure with a stainless steel liner on the surfaces that are expected to be in direct contact with borated water. The IRWST is located below El. 100 ft in the floor slab between the secondary shield wall and the containment wall.

The IRWST and the discharge piping connected to the IRWST are designed to seismic Category I requirements to remain functional in the event of an SSE and are designed to prevent adverse effects on the performance of safety-related SSCs.

The IRWST is equipped with the spargers located at the end of the discharging piping and designed to effectively condense the steam and minimize the loads on the structure.

Protection from the overpressurization of and a vacuum in the IRWST is provided by swing panels on the side walls of four vent stacks. The vent stacks are located on the concrete 5.4-71 Rev. 2

APR1400 DCD TIER 2 slab at El. 100 ft, the top of the IRWST. The swing panels are installed on three side walls of each vent stack as pressure relief devices. The swing panels are closed to minimize the release of vaporized IRWST water into the containment atmosphere during normal plant operation. The swing panels are described in Subsection 6.8.2.2.5.

The IRWST is designed to accommodate the hydrodynamic loads and the thermal effects in the IRWST due to the steam discharged from the pressurizer.

5.4.11.2 System Description The IRWST is a component of the in-containment water storage system (IWSS), which is described in Section 6.8. The flow diagram of the IRWST is given in Figure 6.8-3. The elevation and plan views of the IRWST are shown in Figures 1.2-2 and 6.8-1, respectively.

Four pressurizer POSRVs are connected to the top of the pressurizer by separate inlet lines.

There are two main discharge lines to the IRWST. The steam from two POSRVs is combined into a common discharge line. The flow diagram, showing the pressurizer POSRVs and their discharge lines, is provided as Figure 5.1.2-3.

The RCGVS piping allows the operator to direct the RCGV discharge to the IRWST. The RCGVS flow diagram is shown in Figure 5.4.12-1.

5.4.11.3 Performance Evaluation The IRWST is designed as seismic Category I with a design temperature of 143.3 °C (290 °F). Pressure in the IRWST air space is relieved to the containment atmosphere through the vent stacks.

The evaluation of the hydrodynamic loads on the IRWST and the pool temperature of the IRWST are described in Subsections 6.8.4.3 and 6.8.4.4, respectively.

5.4.11.4 Instrumentation The IRWST is equipped with instrumentation that indicates water level, temperature, and pressure. The instrumentation is provided in the MCR and the RSR to allow the operator to monitor the status of the IRWST. The high and low alarms for level and temperature are provided in the MCR and the RSR.

The IRWST instrumentation is described in Subsection 6.8.3.

5.4-72 Rev. 2

APR1400 DCD TIER 2 5.4.12 Reactor Coolant System High Point Vents The reactor coolant gas vent system (RCGVS) is used to discharge noncondensable gases and steam from the high point of the RCS for venting or pressure control during post-accident conditions.

5.4.12.1 Design Bases The RCGVS is designed to provide a safety-grade means of remotely venting noncondensable gases from the reactor vessel closure head and the pressurizer steam space during post-accident conditions. The RCGVS is also designed to provide a safety-grade means of remotely and selectively removing steam from the pressurizer steam space and/or the reactor vessel for RCS pressure control purposes in the event that pressurizer main spray and auxiliary spray are unavailable during non-LOCA design basis events.

The RCGVS effluent from the pressurizer or the reactor vessel closure head is transported to the in-containment refueling water storage tank (IRWST) through the RCGVS sparger for the safety vent function. The IRWST provides a water reservoir to condense the steam effluent and collect the RCS discharge. The RCGVS effluent from the pressurizer or the reactor vessel closure head is transported to the reactor drain tank (RDT) or the IRWST for the non-safety gas vent operation during plant startup and shutdown.

The reactor vessel closure head vent portion of the RCGVS is designed to provide sufficient venting capacity to vent a steam bubble formed in the reactor vessel closure head during a natural circulation cooldown analysis, assuming a single failure. Reactor vessel closure head vent flow isolation is possible, assuming a single failure.

The pressurizer vent portion of the RCGVS is designed to provide sufficient venting capacity to reduce pressurizer pressure consistent with plant cooldown requirements, assuming a single failure. Pressurizer vent flow isolation is possible, assuming a single failure.

The RCGVS equipment and piping from the reactor vessel closure head vent up to and including the second vent valve, and from the pressurizer up to and including second vent valve are designed as seismic Category I, Class 1E and designed, fabricated, erected, tested and maintained to high quality standards in accordance with ASME Section III, Class 1 requirements.

5.4-73 Rev. 2

APR1400 DCD TIER 2 Each active RCGV valve is designed to be powered from the normal or the emergency power source. Power connections are through two independent power divisions so that in the event of an accident, in conjunction with a loss of normal power and a single failure of one emergency DC power division, a vent path from the pressurizer and the reactor vessel head can be established. The RCGV valves are remotely operated from the main control room and remote shutdown room.

Vent areas provide for mixing of the containment air. Swing panels at the top of the IRWST allow circulation of air for adequate mixing of any combustible gases with the containment atmosphere.

Venting does not adversely affect the performance of safety-related SSCs and does not aggravate the challenge to containment or the course of an accident.

The RCGVS is designed in accordance with the quality assurance acceptance criteria provided in Chapter 17.

The RCGVS satisfies applicable requirements and industry standards, including ASME Code classifications; 10 CFR 50.34(f)(2)(vi); 10 CFR 50.44; 10 CFR 50.46; 10 CFR 50.46a; 10 CFR 50.49; 10 CFR 50.55a; GDC 1, 14, 17, 19, 30, 34, and 36; and safety classifications and environmental qualifications.

5.4.12.2 System Design RCGVS provides a means of venting noncondensable gases and steam from the pressurizer and the reactor vessel closure head to the IRWST and the RDT. The functions are as follows:

a. RCGVS provides a safety-grade means of venting noncondensable gases and steam from the pressurizer and the reactor vessel closure head during post-accident conditions for non-LOCA design basis events.

b. Safety-grade means to depressurize the RCS in the event that pressurizer main spray and auxiliary spray systems are unavailable.

c. RCGVS provides a non-safety gas vent operation from the pressurizer or the reactor vessel closure head during plant startup and shutdown.

5.4-74 Rev. 2

APR1400 DCD TIER 2 RCGV connections to the RCS are located at the reactor vessel closure head vent pipe and at the steam sample/vent line off the pressurizer upper head. The RCGVS flow diagram is shown in Figure 5.4.12-1.

The RCGVS piping is designed to prevent any undrainable loops in the system piping from the vent entrance to the discharge locations. The RCGVS piping downstream of the gas vent isolation valves are maintained unclogged by the following physical aspect of the design:

a. Where possible, the RCGVS piping is pitched at least 10 from horizontal to facilitate drainage.

b. As a minimum, the piping is pitched at least 2 from horizontal and is routed to prevent buildup of drain water that may prevent venting.

In addition, the RCGVS includes a vacuum relief valve to ensure gravity drainage of the vent line.

5.4.12.2.1 Reactor Vessel Closure Head Vent This piping allows the operator to direct the RCGV discharge, through parallel valve divisions, to the IRWST, which is designed as seismic Category I.

The solenoid-operated valves of the parallel valve divisions are controlled from the MCR or RSR. Open and closed indications of the valves are provided and monitored from the MCR or RSR. Each valve is powered by the independent Class 1E power supply, and the valves are supplied with power by alternate alternating current power during an SBO. The valves are qualified using the ANSI/IEEE Std. 344 (Reference 24) as endorsed by NRC RG.1.100 (Reference 25).

The following information is available to the operator for initiating and terminating the reactor vessel closure head venting operation during post-accident conditions:

a. For initiating system operation: reactor vessel water level

b. For terminating system operation: reactor vessel water level If voids form in the reactor vessel closure head, the operator may open the RCGV valves on the top of the reactor vessel (RG-415, RG-414, RG-417, and RG-416) to vent steam from 5.4-75 Rev. 2

APR1400 DCD TIER 2 the reactor vessel closure head, allowing the reactor vessel to be refilled. The reactor vessel closure head vent has a capacity of 4,797 kg/hr (10,576 lb/hr) at 175.8 kg/cm2A (2,500 psia).

The noncondensable gases accumulating in the U-tubes of the steam generators are transferred to the reactor vessel closure head by using a procedure in which one or more RCPs per loop operate for short periods to force noncondensable gases out of the U-tubes.

The reactor vessel closure head is provided with gas removal capability for the shutdown operation using the connection from the reactor vessel closure head to the reactor coolant gas vent system (Figure 5.1.1-1 and 5.4.12-1). The vent piping is connected to the pressurizer vent and then is routed to the reactor coolant gas vent system (RCGVS)

(Figure 5.4.12-1). The RCGVS vent is routed to the reactor drain tank (RDT) for moisture separation in the CVCS while the isolation valves to the IRWST are closed. Venting operations of the reactor vessel closure head to the RDT for normal shutdown is to be performed during Mode 5, when reactor coolant temperature is less than 210 °F and the RCS pressure is fairly low, so that integrity of the RDT is not challenged. The RDT vent is then routed to the gaseous radwaste system (GRS) for processing.

The vent gas from the PZR and the RVCH may go the RDT or the IRWST (Figure 5.1.12-1).

When the RCS pressure is low for RCS filling, the vent gas is aligned to the RDT with the IRWST line (RC-419, 420) closed. While the RCS pressure is high, the vent gas is aligned to the IRWST with the RDT line (RC-418) closed.

5.4.12.2.2 Pressurizer Vent The RCGV piping allows the operator to direct the RCGV discharge, through parallel valve divisions, to the IRWST, which is designed as seismic Category I.

The solenoid-operated valves of the parallel valve divisions are controlled from the MCR or RSR. Open and closed indications of the valves are provided and monitored from the MCR or RSR. Each valve is powered by the independent Class 1E power supply, and the valves are supplied power by alternate alternating current power during an SBO. The valves are qualified using the ANSI/IEEE Std. 344 as endorsed by NRC RG.1.100.

The following information is available to the operator for initiating and terminating the pressurizer venting operation during post-accident conditions:

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APR1400 DCD TIER 2

a. For initiating system operation: pressurizer pressure and cold leg temperatures

b. For terminating system operation: pressurizer pressure and cold leg temperatures The operator may use the RCGV function to cool down and depressurize the plant in the event the pressurizer main spray and auxiliary spray systems are not operable. The operator manually opens the RCGV valves (RG-410, RG-411, RG-412, and RG-413) on the top of the pressurizer, releasing steam to the IRWST through valve RG-0419/RG-0420 while the isolation valve (RG-418) to the RDT is closed. This pressurizer vent has the capacity of 14,023 kg/hr (30,915 lb/hr) at the pressurizer condition of 175.8 kg/cm2A (2,500 psia). The RCGV flow and the depressurization rate are controlled by valves RG-410, RG-411, RG-412, and RG-413 in the vent lines from the top of the pressurizer, and by opening and closing the RCGV valves (RG-414, RG-415, RG-416, and RG-417) from the top of the reactor vessel closure head.

The noncondensable gases accumulating in the U-tubes of the steam generators are transferred to the pressurizer by using a procedure in which one or more RCPs per loop operate for short periods to force noncondensable gases out of the U-tubes.

The pressurizer is provided with gas removal capability for shutdown operation using the connections before the pressurizer pilot operated safety relief valves (POSRVs)

(Figure 5.1.2-3). The connections are joined together to form a header which is routed to the reactor coolant gas vent system (RCGVS) (Figure 5.4.12-1). The RCGVS vent is routed to the reactor drain tank (RDT) for moisture separation in the CVCS. Venting operations of the pressurizer to the RDT for normal shutdown is to be performed during Mode 5, when reactor coolant temperature is less than 210 °F and the RCS pressure is fairly low, so that integrity of the RDT is not challenged. The RDT vent is then routed to the gaseous radwaste system (GRS) for processing.

The vent gas from the PZR and the RVCH may go to the RDT or the IRWST (Figure 5.1.12-1). When the RCS pressure is low for RCS filling, the vent gas is aligned to the RDT with the IRWST line (RC-419, RC-420) closed. While the RCS pressure is high, the vent gas is aligned to the IRWST with the RDT line (RC-418) closed.

5.4.12.2.3 Design Features for Minimization of Contamination The RCGVS is designed with features that meet the requirements of 10 CFR 20.1406 (Reference 18) and NRC RG 4.21 (Reference 19). The basic principles of NRC RG 4.21, 5.4-77 Rev. 2

APR1400 DCD TIER 2 and the methods of control suggested in the regulations, are delineated in four design objectives and two operational objectives, as described in Subsection 12.4.2.

The reactor coolant gas vent system consists of piping and valves that are located inside the containment. The RCGVS vents noncondensable gases from the pressurizer and the reactor vessel closure head and depressurizes the RCS in the event that the pressurizer main spray or auxiliary spray systems are unavailable during plant cool down. The piping directs the vented gases to the IRWST or RDT and is sloped to facilitate the drainage of condensation. As the system is located entirely within containment, any leakage from the system components will be collected in the RDT or IRWST inside containment. Hence, the RCGVS has low potential to contaminate other areas of the plant or the environment.

This design is in conformance with the requirements of NRC RG 4.21.

Prevention/Minimization of Unintended Contamination The RCGVS is designed to vent non-condensable gases from the pressurizer and the reactor vessel closure head and depressurizes the reactor coolant system in the event that the pressurizer main spray or auxiliary spray systems are unavailable during plant cooldown.

The piping directs the vented gases to the IRWST or the RDT and is sloped to facilitate the drainage of condensation, thus minimizing leakage and unintended contamination of the facility and the environment.

Adequate and Early Leak Detection The RCGVS is designed not to be used during normal operation, and the piping is designed to slope downward to drain to the RDT and the IRWST. The potential for leakage is very low and a leak detection system is not required.

Reduction of Cross-Contamination, Decontamination, and Waste Generation The RCGVS piping is made of stainless steel material for life-cycle planning. The material is compatible with the chemical, physical, and radiological environment, thus minimizing waste generation.

Decommissioning Planning The RCGVS piping is designed for the full service life of the plant and is accessible for easy removal during decommissioning.

5.4-78 Rev. 2

APR1400 DCD TIER 2 Operations and Documentation The RCGVS piping is used during refueling or post-accidental conditions. Adequate instrumentation is provided to indicate the venting operations to prevent undue interruption.

Site Radiological Environmental Monitoring The RCGVS piping is part of the overall plant and is designed to vent noncondensable gases from the reactor vessel and the pressurizer. The RCGVS piping does not generate any radioactive materials and thus, site radiological environmental monitoring is not required.

5.4.12.3 Performance Evaluation The RCGVS is designed to provide remote noncondensable gas venting from the reactor vessel closure head and the pressurizer steam space during post-accident conditions.

Redundant flow paths are provided in the vent paths from the reactor vessel closure head and pressurizer, respectively, to provide reasonable assurance of flow under single failure conditions. A redundant flow path contains two valves in series, in each flow path, to preclude spurious flow path initiation upon single failures and inadvertent open flow path.

To achieve this, the two valves are powered by a different train of the Class 1E power source.

A break in the vent line on the reactor vessel closure head (RVCH) and pressurizer is categorized as a small break LOCA. A break phenomenon (or behavior) of the RVCH and pressurizer vent line is similar to the breaks that are analyzed in Subsection 15.6.5.

Hence, the results presented in Subsection 15.6.5 conservatively envelop the RVCH and pressurizer vent line break case.

The evaluation of the reactor coolant gas vent system operation is as follows:

a. The operations are needed when venting the noncondensable in the upper reactor vessel and the pressurizer are necessary.

b. The size of a noncondensable bubble is estimated from reading the reactor vessel water level indication.

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APR1400 DCD TIER 2

c. Initiating and terminating system operation are manually performed in accordance with the conditions as described in Subsections 5.4.7.3.1, 5.4.12.2.1, and 5.4.12.2.2.

d. The temperature and pressure instrumentation is provided to detect RCS leakage and pressure buildup, respectively.

e. The operator actions to open and close the RCGV valves are needed to vent steam in the reactor vessel closure head and the pressurizer or to release steam to the IRWST.

The venting operation is performed in accordance with system operating procedure for the RCGVS to discharge noncondensable gases and steam from the high point of the RCS during post-accident conditions. The system operating procedure for the RCGVS will be developed as part of COL 13.5(4) and COL 13.5(5).

5.4.12.4 Inspection and Testing Requirements Subsection 3.9.6 describes inservice testing and inspection of valves. Subsection 5.2.4 describes inservice inspection and testing of ASME Code, Class 1 components that are part of the reactor coolant pressure boundary.

5.4.12.5 Instrumentation Requirements Temperature instrumentation is provided downstream of the RCGV valves (RG-418, RG-419, and RG-420) to detect RCS leakage during normal operation when the valves are closed. These instruments are not required for post-accident operation. Temperature readouts are provided in the MCR and RSR.

A pressure instrument is provided downstream of the dual RCGV valves but before the isolation valves to the IRWST to detect pressure buildup in this region. Pressure readout is provided at the MCR and RSR.

All RCGV valves are operated in the MCR and the RSR.

5.4-80 Rev. 2

APR1400 DCD TIER 2 5.4.13 Main Steamline Flow Restrictor 5.4.13.1 Design Basis The steam nozzle of the steam generator is provided with a flow restrictor designed to limit steam flow in the unlikely event of a break in the main steamline. The flow rate is decreased by the small flow area and is limited to sonic velocity. Several protective advantages are thereby provided: rapid rise in containment pressure is prevented, the rate of heat removal from the reactor coolant is kept within acceptable limits, thrust forces on the main steamline piping are reduced, and stresses on internal steam generator components, particularly the tubesheet and tubes, are limited. The restrictor is also designed to minimize the unrecovered pressure loss across the restrictor during normal operation.

5.4.13.2 Design Description The steam generator steam nozzles are one-piece forgings with an integral venturi-type flow restrictor. The flow restrictor with throat diameter of 38.96 cm (15.34 in) is installed at 72.662 cm (28.607 in) inner diameter steam generator outlet nozzle.

5.4.13.3 Design Evaluation The flow restrictor design has been sufficiently analyzed to provide reasonable assurance of its structural adequacy. The maximum pressure drop through the restrictor at the full power flow rate of 2.04 x 106 kg/hr (4.49 x 106 lb/hr) is approximately 0.42 kg/cm2D (6 psid) in the nozzle divergent section, and 0.56 kg/cm2D (8 psid) from the steam generator steam dome to the steam nozzle outlet. Construction materials and manufacturing of the flow restrictor are in accordance with ASME Section III, Class 1.

5.4.13.4 Tests and Inspections Since the restrictor is not a part of the steam system boundary, no tests and inspections beyond those during fabrication are anticipated.

5.4.14 Safety and Relief Valves 5.4.14.1 Design Basis The POSRVs on the pressurizer are designed to protect the primary system, as required by ASME Section III.

5.4-81 Rev. 2

APR1400 DCD TIER 2 The design basis for establishing the relieving capacity of the pressurizer POSRVs is presented in Subsection 5.2.2. For the postulated transients presented in Chapter 15, the results indicate that relieving capacity of the POSRVs is sufficient to provide overpressure protection.

Safety valves on the steam side of each SG are designed to protect the steam system, as required by ASME Section III. They are conservatively sized to pass a steady-flow equivalent to the maximum expected power level at the design pressure of the steam system.

5.4.14.2 Description The RCS has four pressurizer POSRVs to provide overpressure protection. A typical POSRV is illustrated in Figure 5.4.14-1. The design parameters are given in Table 5.4.14-1. The valves are connected to the top of the pressurizer and meet ASME Section III requirements. Each valve has a body that comprises a nozzle, spindle, and disc. The pressurizer POSRVs pass sufficient pressurizer steam to limit the RCS pressure to 110 percent of design pressure (193.3 kg/cm2A (2,750 psia)) following a loss of load with a delayed reactor trip, which is assumed to be initiated by the secondly generated safety grade signal from the RPS. A delayed reactor trip is assumed on a high-pressurizer pressure signal. To determine maximum steam flow through the pressurizer POSRVs, the MSSVs are assumed to be operational.

Overpressure protection for the shell side of the SGs and the main steam lines up to the inlet of the turbine stop valve is provided by the MSSVs. These valves are each sized to pass a steam flow of 430,913 kg/hr (950,000 lb/hr) at 92.83 kg/cm2A (1,320 psia). This limits SG pressure to less than 110 percent of SG design pressure during worst-case transients. The MSSVs consist of 20 valves with staggered set pressures. The valves are spring-loaded safety valves fabricated in accordance with ASME Section III. Parameters for the MSSVs are given in Table 5.4.14-2.

The manual actuation of pressurizer POSRVs can be used for rapid depressurization for feed-and-bleed operation in a total loss of feedwater event.

5.4.14.3 Evaluation Overpressure protection is discussed in Subsection 5.2.2.

5.4-82 Rev. 2

APR1400 DCD TIER 2 5.4.14.4 Tests and Inspections The valves are inspected during fabrication in accordance with ASME Section III requirements.

The inlet and outlet portions of the POSRVs are hydrostatically tested with water at the appropriate pressures as required by the applicable section of the ASME Section III. Set pressure and seat leakage tests can be performed with steam. Final seat leakage tests are performed before shipment using either hot air or hot nitrogen.

5.4.15 Component Supports 5.4.15.1 Design Basis The criteria applied in the design of the RCS supports are that the specific function of the supported equipment be achieved during the conditions of normal, earthquake, POSRV actuation, IRWST discharge, and branch line pipe break (BLPB) conditions. BLPB includes feedwater line breaks, main steam line breaks and all LOCA conditions resulting from breaks not eliminated by leak-before-break analysis in piping to branch nozzles of the RCS. Specifically, the supports are designed to support the RCS components and to restrain the components in accordance with the stress and deflection limits of ASME Section III under the combined SSE, IRWST discharge and BLPB loadings.

5.4.15.2 Description Figure 5.4.15-1 illustrates the RCS support points. A description of the supports for each supported component is as follows:

a. Reactor vessel supports The RV is supported by four vertical columns located under the vessel inlet nozzles. These columns are designed to be flexible to the horizontal direction to allow horizontal thermal expansion during heatup and cooldown. They also support the RV in the vertical direction.

Horizontal keyways along the upper portion of the column guide the RV during thermal expansion and contraction of the RCS and maintain the vessel centerline.

The clearance between the key and the supporting structure is shimmed and verified during hot functional testing.

5.4-83 Rev. 2

APR1400 DCD TIER 2 Four horizontal keys welded to the vessel bottom head and keyways of the column base plates allow free thermal expansion and contraction of the RV. The column base plate acts as a keyway to restrain the bottom of the RV for dynamic load conditions. The clearance between the key and the supporting structure is shimmed and verified during hot functional testing.

The supports are designed to accommodate normal, seismic, IRWST discharge, and BLPB loads. In addition to the design basis loads, irradiation effects are also considered in the fracture mechanics analysis of the columns.

Reactor vessel supports are shown in Figure 5.4.15-2.

b. Steam generator supports The steam generator supports are shown in Figure 5.4.15-3. The steam generator is supported by a conical skirt welded to the steam generator lower head. The skirt provides a bolting surface for a heavy steel sliding base. Preloaded studs transfer loads from the skirt to the sliding base. Four low friction spherical head bearings under the plate are the sliding interface, which allows horizontal motion parallel to the hot leg due to thermal expansion. Machined cutouts in the sliding base act as keyways for embedded keys that support the generator horizontally during earthquakes, IRWST discharge, and a postulated pipe break. The keys are designed to resist dynamic event loads in a direction perpendicular to the hot leg piping. In the keyways, lower expansion plates (low friction bearings) are used to minimize resistance to thermal motion. The clearances between the lower expansion plate (low friction bearings) and the keys are shimmed and verified during hot functional testing.

Horizontal support at the top of the steam generator is provided by two keys and two hydraulic snubber assemblies. The keys and assemblies act as horizontal supports for the steam generator during earthquakes, IRWST discharge, and a postulated pipe break while allowing motion parallel to the hot leg due to thermal expansion. Upper expansion plates (low friction bearings) are bolted to the sides of the keyway. The clearances between the key and the upper horizontal supporting structures are shimmed and verified during hot functional testing.

Each snubber assembly consists of a lug welded to the steam generator, a lever, two links, a snubber, one clevis bracket pinned to the lever, and one clevis bracket 5.4-84 Rev. 2

APR1400 DCD TIER 2 pinned to the snubber as shown in Figure 5.4.15-3. Each clevis bracket is drilled to accept anchor bolts. Preloaded anchor bolts and the clevis brackets are the mechanism by which loads are transmitted to the concrete structure.

c. RCP supports The supports control movement of the reactor coolant pump in the horizontal and vertical planes during earthquakes, IRWST discharge, and postulated pipe breaks, but accommodate motion due to thermal expansion.

The reactor coolant pump supports are shown in Figure 5.4.15-4. The reactor coolant pump and motor assembly is supported by four vertical columns pinned to the pump mounting skirt. It is supported for seismic, IRWST discharge, and postulated pipe break loads by two horizontal columns pinned to the top of the motor mount, two horizontal columns pinned to the pump support skirt, and a horizontal snubber system attached to the top of the motor mount.

Each column, horizontal and vertical, and the snubber assembly end in a clevis bracket drilled to accept anchor bolts. The loads are transmitted to the concrete structure through the clevis brackets and preloaded anchor bolts.

d. Pressurizer supports The pressurizer is supported by a cylindrical skirt welded to the bottom head of the pressurizer. The skirt ends in a flange that is drilled to accept anchor bolts.

Support loads are transmitted to the foundation through the skirt flange.

Although most thermal growth is in the vertical direction, the pressurizer skirt design accommodates radial growth without bolt slippage.

Four keys welded to the upper portion of the pressurizer shell give additional support to the pressurizer during an earthquake, POSRV actuation, IRWST discharge, and a postulated pipe break. The clearance between the key and the supporting structure is shimmed and verified during hot functional testing.

5.4.15.3 Evaluation Reasonable assurance of the structural integrity of the RCS support components is provided by quality assurance inspections in accordance with ASME Section III during fabrication of 5.4-85 Rev. 2

APR1400 DCD TIER 2 the supports. The non-integral supports are procured by individual equipment specifications that impose appropriate quality assurance requirements commensurate with the functions of the component.

During pre-operational testing of the RCS, the support displacements are measured to check the consistency with the calculated displacements and/or clearances. Subsequent inspections of supports that support RCS components are conducted in accordance with the ASME Section XI.

The COL applicant is to verify that the as-built RV support material properties and 60-year neutron fluence (COL 5.4(5)) are consistent with the following:

a. Maximum phosphorous, 0.015 percent per heat, and 0.018 percent per product analysis

b. Maximum copper, 0.15 percent per heat and per product analysis

c. Other chemical compositions consistent with SA508 chemistry

d. 60-year neutron fluence of 2.0 x 1018 n/cm2 (E > 1.0 MeV)

If the requirements above are not met, a revised fracture mechanics analysis is performed.

5.4.16 Intersystem Loss of Coolant Accidents The NRC has developed a position on design requirements to minimize the potential for the Intersystem LOCA (ISLOCA). The APR 1400 design has been evaluated to identify the vulnerability of the APR1400 plants to ISLOCAs. The evaluation and results are described in Appendix 5A.

5.4.17 Combined License Information COL 5.4(1) The COL applicant is to prepare operational procedures and maintenance programs related to leak detection and contamination control of RCS.

COL 5.4(2) The COL applicant is to maintain complete documentation of system design, construction, design modifications, field changes, and operations.

Documentation requirements are included as a COL information item.

5.4-86 Rev. 2

APR1400 DCD TIER 2 COL 5.4(3) The COL applicant is to prepare operational procedures and maintenance programs related to leak detection and contamination control of SCS.

COL 5.4(4) The COL applicant is to maintain complete documentation of system design, construction, design modifications, field changes, and operations of SCS.

COL 5.4(5) The COL applicant is to verify the as-built RV support material properties and 60-year neutron fluence.

COL 5.4(6) The COL applicant is to provide a procedure to protect the plant personnel from harsh environment and lengthen the work time within containment during hatch closure.

COL 5.4(7) The COL applicant is to prepare an inspection and monitoring program for the cladding material integrity of SG channel heads.

5.4.18 References

1. ASME Boiler and Pressure Vessel Code,Section III, Rules for Construction of Nuclear Facility Components, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

2. 10 CFR Part 50, Appendix A, General Design Criteria for Nuclear Power Plants.

U.S. Nuclear Regulatory Commission.

3. Regulatory Guide 1.14, Reactor Coolant Pump Flywheel Integrity, Rev. 1, U.S.

Nuclear Regulatory Commission, August 1975.

4. APR1400-A-M-NR-14001-P, KHNP APR1400 Flywheel Integrity Report, Rev. 3, KHNP, July 2017.

5. ASME Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

6. APR1400-A-M-NR-14002-P, Extended Loss of AC Power Capability for APR1400 KSB RCP Seals, Rev. 1, KHNP, May 2016.

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APR1400 DCD TIER 2

7. ASME PTC 8.2, Centrifugal Pumps, The American Society of Mechanical Engineers, 1990.

8. NEMA MG-1, Motors and Generators, National Electrical Manufacturers Association, 2009 (with 2010 Revision 1).

9. Regulatory Guide 1.121, Bases for Plugging Degraded PWR Steam Generator Tubes, Revision 0, U.S. Nuclear Regulatory Commission, August 1976.

10. ASME Section III, Appendix N, Dynamic Analysis Methods, The American Society of Mechanical Engineers, the 2007 Edition with the 2008 Addenda.

11. Bulletin 79-13, Cracking in Feedwater System Piping, Rev. 1, U.S. Nuclear Regulatory Commission, August 30, 1979.

12. NEI 97-06, Steam Generator Program Guidelines, Rev. 3, Nuclear Energy Institute, January 2011.

13. EPRI Report 1013706, Pressurized Water Reactor Steam Generator Examination Guidelines, Rev. 7, Electric Power Research Institute, October 2007.

14. EPRI Report 1022832, PWR Primary-to-Secondary Leak Guidelines, Rev. 4, Electric Power Research Institue, September 2011.

15. EPRI Report 1019038, Steam Generator Integrity Assessment Guidelines, Rev. 3, Electric Power Research Institue, November 2009.

16. EPRI Report 1016555, Pressurized Water Reactor Secondary Water Chemistry Guidelines, Rev. 7, Electric Power Research Institue, February 2009.

17. EPRI Report 1014986, Pressurized Water Reactor Primary Water Chemistry Guidelines, Rev. 6, Electric Power Research Institue, December 2007.

18. 10 CFR 20.1406, Minimization of Contamination, U.S. Nuclear Regulatory Commission.

19. Regulatory Guide 4.21, Minimization of Contamination and Radioactive Waste Generation-Life Cycle Planning, Rev. 0, U.S. Nuclear Regulatory Commission, June 2008.

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20. NUREG-0800, Standard Review Plan, BTP 5-4, Design Requirements of the Residual Heat Removal System, Rev. 4, U.S. Nuclear Regulatory Commission, March 2007.

21. Bulletin 88-04, Potential Safety-Related Pump Loss, U.S. Nuclear Regulatory Commission, May 5, 1988.

22. GL 89-10, Safety-Related Motor-Operated Valve Testing and Surveillance, U.S.

Nuclear Regulatory Commission, June 28, 1989.

23. APR1400-E-N-NR-14005-P, Shutdown Evaluation Report, Rev. 0, KHNP, December 2014.

24. IEEE Std. 344-2004 (R2009), Recommended Practice for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations, Institute of Electrical and Electronics Engineers (IEEE), 2005.

25. Regulatory Guide 1.100, Seismic Qualification of Electric and Mechanical Equipment for Nuclear Power Plants, Rev. 3, U.S. Nuclear Regulatory Commission, September 2009.

5.4-89 Rev. 2

APR1400 DCD TIER 2 Table 5.4.1-1 Reactor Coolant Pump Parameters Parameter Value Number of units 4 Type Vertical, single-stage centrifugal (1)

Rated total dynamic head, m (ft) 109.7 (360)

Rated flow, L/min (2) (gpm) 460,256 (121,600) 2 Design pressure, kg/cm A (psia) 175.8 (2,500)

Design temperature, °C (°F) 343.3 (650)

Normal operating pressure, kg/cm2A (psia) 158.2 (2,250)

Normal operating temperature, (1) °C (°F) 290.6 (555)

NPSH available (at rated flow), m (ft) 152.4 (500)

Suction temperature, (1) °C (°F) 290.6 (555)

Water volume, each, m3 (ft3) 3.26 (115)

Weight (including motor), dry, kg (lb) 144,515 (318,600)

Rotating inertia, pump, and motor: 6,717 (159,400)

Assembly, minimum, kg-m2 (lbs-ft2)

Shaft seals Mechanical face seals (1)

Pump speed, rpm 1,190 Motor synchronous speed, rpm 1,200 Motor type AC induction (1)

Horsepower, hot, kW (hp) 7,457 (10,000) cold, kW (hp) 10,067 (13,500)

Rated brake horsepower, kW (hp) 7,457 (10,000)

Voltage, V 13,200 Phase 3 Frequency, Hz 60 Insulation class F Starting current, at 100 % voltage, amps 3,426 (1) Parameters are related to four-pump, full-power operating conditions.

(2) RCP rated flow exceeds RCS design minimum flow in Sections 4.4 and 5.1 to provide reasonable assurance that the minimum flow is achieved.

5.4-90 Rev. 2

APR1400 DCD TIER 2 Table 5.4.2-1 (1 of 2)

Steam Generator Design Parameters Parameter (1) Value Number of units 2 Heat transfer rate per SG, kcal/hr (Btu/hr) 1.721 x 109 (6.830 x 109)

Number of tubes per SG 13,102 Average active tube length per SG, m (ft) 19.391 (63.62)

Heat transfer area per SG (approximate), m2 (ft2) 15,205 (163,670)

Primary Side 2

Design pressure/temperature (kg/cm A/°C) (psia/°F) 175.76/343.33 (2,500/650)

Coolant inlet temperature, °C (°F ) 323.88 (615)

Coolant outlet temperature, °C (°F) 290.55 (555)

Coolant flow rate, each, kg/hr (lb/hr) 37.78 x 106 (83.3 x 106)

Coolant volume at 68 °F each, m3 (ft3) 86.84 (3,066.99)

Tube size, OD, mm (in) 19.05 (0.75)

Tube thickness, nominal, mm (in) 1.0668 (0.042)

Primary inlet nozzle, number/inside diameter (ID), 1/1,066.8 (42) mm (in)

Primary outlet nozzle, number/ID, mm (in) 2/762 (30)

Secondary Side Design pressure/temperature, kg/cm2A/°C (psia/°F) 84.36/298.88 (1,200/570) 2 Steam pressure, kg/cm A (psia) 70.3 (1,000) (2)

Steam flow rate (at 0.25 % moisture) per SG, 4.070 x 106 (8.975 x 106) kg/hr (lb/hr)

Feedwater temperature at full power, °C (°F) 232.22 (450)

Moisture carryover, weight maximum, % 0.25 Steam nozzle, number/ID, mm (in) 2/711.2 (28)

Feedwater nozzles, number/size/schedule (economizer) 2/14/120 Feedwater nozzles, number/size/schedule (downcomer) 1/6/(Special) 5.4-91 Rev. 2

APR1400 DCD TIER 2 Table 5.4.2-1 (2 of 2)

Parameter (1) Value Overall heat transfer coefficient:

Evaporator, kcal/hr-m2 °C (Btu/hr-ft2 °F) 6,483.864 (1,328)

Economizer, kcal/hr-m2 °C (Btu/hr-ft2 °F) 2,875.750 (589)

Inventory per SG at normal water level and full power, kg 98,895 (218,027)

(lbm)

Boil dry time from normal water level of full power 26.67 (approximate), min Boil dry time from nominal low SG level of reactor trip 26.30 (approximate), min (1) Includes operation with continuous SG blowdown flow of 0.2 % of the steam flow rate (2) Measured at the SG steam dome area 5.4-92 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-1 (1 of 3)

Shutdown Cooling System Design Parameters Parameter Value System Design Parameters Shutdown cooling system initiation Approximately 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after reactor shutdown RCS maximum cooldown rate 41.7 (75)

(at initiation of shutdown cooling), °C/hr (°F/hr)

Maximum shutdown cooling flow, L/min (gpm)/HX 18,927 (5,000)

Component Design Parameters Shutdown cooling heat exchanger:

Quantity 2 Type Shell and tube, horizontal U-tube Service transfer rate, kcal/hr-m2-°C (Btu/hr-ft2-°F) 1,872.9 (383.6)

Effective heat transfer area, m2/HX(ft2/HX) 776.9 (8,362.5)

Tube side:

Fluid Reactor coolant Design pressure, kg/cm2G (psig) 63.3 (900)

Design temperature, °C (°F) 204.4 (400)

Material Austenitic stainless steel Code ASME Section III, NC (1)

Fouling resistance, m2-K/W (hr-ft2-°F/Btu) 0.000088(0.0005)

Shell side:

Fluid Component cooling water Design pressure, kg/cm2G (psig) 14.1 (200)

Design temperature, °C (°F) 93.3 (200)

Material Carbon steel Code ASME Section III, ND (2)

Fouling resistance, m2-K/W (hr-ft2-°F/Btu) 0.000088(0.0005) 5.4-93 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-1 (2 of 3)

Parameter Value Component Design Parameters (cont.)

At 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after shutdown Tube side:

Flow, kg/hr (lb/hr) 1.08 x 106 (2.38 x 106)

Inlet temperature, °C (°F) 48.9 (120)

Outlet temperature, °C (°F) 40.2 (104.4)

Shell side:

Flow, million kg/hr (lb/hr) 2.49 x 106 (5.48 x 106)

Inlet temperature, °C (°F) 35 (95)

Outlet temperature, °C (°F) 38.8 (101.8)

Heat transfer rate, W (Btu/hr) 11.0 x 106 (37.4 x 106)

Shutdown cooling pump:

Quantity 2 Type Single stage, vertical, centrifugal Safety classification 2 Code ASME Section III, NC Design pressure, kg/cm2G (psig) 63.3 (900)

Design temperature, °C (°F) 204.4 (400)

Design flow rate, L/min (gpm) 20,536 (5,425) (3)

Design head, m (ft) 140.2 (460)

Materials Stainless steel type 304,316 Seals Mechanical Brake power, kW (HP) 746 (1,000)

Minimum NPSH Available 5.79 m at 20,536 L/min (19 ft at 5,425 gpm) (3)

NPSH Required 5.49 m at 20,536 L/min (18 ft at 5,425 gpm) (3)

Shutdown cooling miniflow heat exchanger:

Quantity 2 Type Shell and tube, horizontal U-tube Service transfer rate, kcal/hr-m2-°C (Btu/hr-ft2-°F) 1831.4 (375.1)

Effective heat transfer area, m2/HX (ft2/HX) 14.0 (150.2) 5.4-94 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-1 (3 of 3)

Parameter Value Component Design Parameters (cont.)

Tube side:

Fluid Reactor coolant Design pressure, kg/cm2G (psig) 63.3 (900)

Design temperature, °C (°F) 204.4 (400)

Material Austenitic stainless steel Code ASME Section III, NC Shell side:

Fluid Component cooling water Design pressure, kg/cm2G (psig) 14.1 (200)

Design temperature, °C (°F) 149 (300)

Material Carbon steel Code ASME Section III, ND (1) ASME Boiler and Pressure Vessel Code,Section III, Rules for Construction of Nuclear Power Plant Components, Division 1, Subsection NC: Class 2 Components, ASME, the 2007 Edition and the 2008 Addenda.

(2) ASME Boiler and Pressure Vessel Code,Section III, Rules for Construction of Nuclear Power Plant Components, Division 1, Subsection ND: Class 3 Components, ASME, the 2007 Edition and the 2008 Addenda.

(3) Including the minimum bypass flow 5.4-95 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (1 of 13)

SCS Failure Modes and Effects Analysis Symptoms and Local Inherent Failure Effects Including Method of Compensating Remarks and No. Name Modes Cause Dependent Failure Detection Provision Other Effects

1. SCS a) Fails Mechanical Prevention of decay heat Periodic testing; Redundant SCS train Suction closed binding removal from core via Valve position Line Electrical one SCS train during indication in Isolation malfunction normal shutdown cooling control room Valve or long term cooling Corrosion SI-651 following LOCA SI-652 b) Fails Same as 1a None, LTOP transient Same as 1a The redundant series Interlocks associated SI-653 open alarm while SI-651/653 valve ensures that with the valves prevent or SI-652/654 are not full SCS is protected overpressurization.

SI-654 closed with high RCS from normal RCS These interlocks pressure transients and pressure during prevent the valves in LTOP inhibited alarm power operation the suction line of the while either valve not full SCS from being open during a low RCS opened if RCS temperature pressure exceeds 31.6 kg/cm2A (450 psia).

2. SCS a) Fails Mechanical Inability to align one Periodic testing Redundant SCS train Suction closed binding shutdown cooling Valve position Line Electrical subsystem for shutdown indication in Isolation malfunction cooling control room Valve Corrosion SI-655 b) Fails Same as 2a None Same as 2a None required Valve is normally SI-656 open locked closed in control room 5.4-96 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (2 of 13)

Symptoms and Local Inherent Failure Effects Including Method of Compensating Remarks and No. Name Modes Cause Dependent Failure Detection Provision Other Effects

3. SCP a) Fails Mechanical Effective loss of one SCS Periodic testing Redundant SCS train Suction closed binding train Low flow Isolation Corrosion indication Valve (F-302A, 305B)

Operator SI-106 error SI-107 b) Fails Same as 3a None Periodic testing None open

4. Shutdown a) Fails to Mechanical Effective loss of one SCS Low flow Redundant SCP and When used in a Cooling start failure train indication CSP might permit containment spray Pump 1, 2 Electrical (F-302A, 305B) shutdown cooling configuration, the SCPs malfunction Periodic testing although the cooling are capable of being time will be extended automatically started by Pump run light an SIAS or CSAS

5. SCP a) Fails Mechanical Possible damage to Periodic testing Redundant SCS train Valve is normally MFHX closed binding associated SCP locked open Isolation Corrosion Valve b) Fails Same as 5a None Periodic testing None SI-265 open SI-269

6. SCP a) Loss of Single failure in Possible damage to Periodic testing Redundant SCS train Miniflow cooling component associated SCP Heat cooling water Exchanger system (CCWS) 1, 2 b) Cross Corrosion Leakage from SCP Radiation and/or Redundant SCS train leakage miniflow to the CCWS level indication in CCWS 5.4-97 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (3 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

7. SCP a) Fails Mechanical Effective loss of one Periodic testing Redundant SCS train Valve is normally Discharge closed binding shutdown cooling pump Low flow locked open; min. flow Isolation Corrosion indication line will provide the Valve (F-302A, 305B) min. flow required to SI-578 protect the pump SI-579 b) Fails Same as 7a None Periodic testing None open

8. Shutdown a) Loss of Insufficient Diminished ability of one Periodic testing Redundant SCS train The SDCHXs are used Cooling cooling component subsystem to provide High temperature during long term Heat water cooling water RCS heat removal indication from cooling following a Exchanger flow T-302A, T-305B LOCA 1, 2 Excessive fouling b) Cross Corrosion Leakage from SCS Radiation and/or Redundant SCS train Same as 8.a) leakage system to the CCWS level indication in CCWS c) Corrosion No flow through one Position indication Redundant SCS train Plugged Foreign SDCHX in control room, no Tube material in Reduced cooling delta temperature RCS capability across SDCHX as indicator by T-302A, 305B 5.4-98 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (4 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

9. SDCHX a) Fails Mechanical During initial stage of Periodic testing Operator can turn off Bypass Flow closed binding shutdown cooling, one Valve position the SCS subsystem.

Control Electrical shutdown cooling The RCS is pre-Low temperature Valve malfunction subsystem would pump borated to provide indication from SI-312 excessively cooled sufficient shutdown Corrosion T-302A, 305B SI-313 water to the reactor margin core.

Reduction in shutdown cooling margin b) Fails Same as 9a Reduced reactor coolant Periodic testing Redundant SCS open flow through one SDCHX Valve position subsystem will assure shutdown High temperature cooling although indication from cooling time will be T-302A, 305B extended

10. SDCHX a) Fails Mechanical No flow through one Position indication Redundant SCS train Outlet Flow closed binding SDCHX in control room, no Control Electrical Reduced cooling delta temperature Valve malfunction capability across SDCHX as SI-310 indicator by Corrosion SI-311 T-302A, 305B b) Fails Same as 10a Inability to regulate and Valve position Operator can turn off open maintain cooldown rate indication in control the SCS subsystem.

room; Low The RCS is pre-temperature borated to provide indication from sufficient shutdown T-302A, 305B cooling margin 5.4-99 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (5 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

11. SCS Flow False Electrical Inability to control Periodic testing Redundant SCS Indicator Indication malfunction cooldown rate in Comparison with train F-302A affected train redundant Redundant flow F-305B Possible isolation of indicator, with all indicators functional SCS train other process instrumentation and valve position indications

12. SCS False Electrical Inability to control Periodic testing Redundant SCS Temperature Indication malfunction cooldown rate in Comparison with train Indicator affected train redundant Redundant T-302A Inconsistent reading indicator, with all temperature T-305B with other temperature other process indicators T-300A indicators instrumentation T-303B and valve position T-301A indications T-304B

13. SCS False Electrical Inconsistent reading with Periodic testing Redundant SCS Pressure Indication malfunction other pressure indicators Comparison with train Indicator redundant Redundant P-302 indicator pressure indicators P-305 P-300 P-301 5.4-100 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (6 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

14. Shutdown a) Fails Mechanical Inability to remove Periodic testing Redundant Purification closed binding contaminants from one The failure to purification Isolation Corrosion SCS flow path during purify would be connections to other Valve shutdown cooling detected by SCS subsystem SI-421 periodic sampling SI-420 b) Fails Same as 14a None Periodic testing Series isolation Valve is normally open valves in CVCS locked closed and only valve open for shutdown purification

15. SCS Test a) Fails Mechanical No effect on SCS Periodic testing None Return Line closed binding operation Valve position Isolation Corrosion Inability to perform indication in Valve IRWST cooling control room SI-314 operation (SCP flow SI-315 testing) or reactor cavity SI-688 fill operation SI-693 (SI-314/688 only) b) Fails Same as 15a None High temperature Series isolation Valve is normally open indication from valves (SI-300/301) locked closed in T-301A, 304B in IRWST return line control room Periodic testing 5.4-101 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (7 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

16. IRWST a) Fails Mechanical No effect on SCS Periodic testing None Return Line closed binding operation Isolation Corrosion Inability to perform Valve IRWST cooling SI-300 operation (SCP flow SI-301 testing) or reactor cavity fill operation (SI-300 only) b) Fails Same as 16a None High temperature Series isolation open indication from valves (SI-688/693)

T-301A, 304B in SCS test return Periodic testing line

17. Reactor a) Fails Mechanical Inability to perform Periodic testing None Cavity closed binding reactor cavity fill Isolation Corrosion operation.

Valve SI-393 b) Fails Same as 17a None Periodic testing Series in isolation Valve is normally SI-391 open valves SI-393/391 locked closed in are closed control room 5.4-102 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (8 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

18. IRWST a) Fails Mechanical Inability to perform Periodic testing None Valve is normally Return Line closed binding IRWST cooling operation locked open Isolation Corrosion (SCP flow testing)

Valve b) Fails Same as 18a No effect on IRWST Periodic testing None required SI-395 open cooling operation.

SI-959 Inability to perform reactor cavity fill operation (SI-395 only)

19. SCS a) Fails Mechanical Inability to gradually Periodic testing Redundant shutdown The safety injection Warmup closed binding warm up the shutdown Valve position cooling subsystem piping and nozzles are Line Flow Electrical cooling line during the indication in train will not be designed for a limited Control malfunction shutdown cooling control room affected number of thermal Valve alignment procedure cycles that could result Corrosion SI-691 from operating the SI-690 SCS without prior warmup b) Fails Same as 19a Diversion of flow from Periodic testing Redundant shutdown These valves are open discharge leg to suction Valve position cooling subsystem gradually closed once leg of SCS without indication in train will not be warmup and flowrate passing through the control room affected stability have been reactor core during reached shutdown cooling operation 5.4-103 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (9 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

20. SCS Line a) Fails Mechanical Inability to inject cooled Periodic testing Redundant SCS train Isolation closed binding coolant into one of the Valve position Valve Electrical DVI injection line indication in the SI-601 malfunction control room SI-600 Corrosion b) Fails Same as 20a Inability to gradually Same as 20a Redundant shutdown The safety injection open warm up the shutdown cooling subsystem piping and nozzles are cooling line during the will not be affected designed for a limited shutdown cooling number of thermal alignment procedure cycles which could result from operating the SCS without prior warmup

21. SCS/CSS a) Fails Mechanical No effect on SCS Periodic testing None These valves can be Pump closed binding operation Valve position aligned for SCS/CSS Suction Electrical Inability to perform indication in the interconnection Cross malfunction SCS operation using control room Connect CSP or containment Valve spray operation using SI-340 SCP SI-342 b) Fails Same as 21a Loss of one SCS train Low flow in SCS Redundant SCS train Valve is normally open Periodic testing locked closed in control room Valve position indication in the control room 5.4-104 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (10 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

22. SCS/CSS a) Fails Mechanical No effect on SCS Periodic testing None These valves can be Pump closed binding operation Valve position aligned for SCS/CSS Discharge Electrical Inability to perform indication in the interconnection Cross malfunction SCS operation (or control room Connect IRWST cooling Valve operation) using CSP or SI-341 containment spray SI-343 operation using SCP b) Fails Same as 22a Loss of one SCS train Low flow in SCS Redundant SCS train Valve is normally open Periodic testing, locked closed in Valve position control room indication in the control room

23. SCP a) Fails Mechanical No effect on SCS Periodic testing None Suction closed binding operation Valve position Isolation Electrical Inability to perform indication in the Valve malfunction IRWST cooling control room SI-344 operation (SCP flow testing) or reactor cavity SI-346 fill operation b) Fails Same as 23a None Same as 23a Series in check valve Valve is normally open SI-159/160 are closed locked closed in control room 5.4-105 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (11 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

24. CSP a) Fails Mechanical No effect on SCS Periodic testing Redundant SCS train Valve is normally Suction closed binding operation Valve position locked open in control Isolation Electrical Inability to perform indication in the room Valve malfunction IRWST cooling control room SI-347 operation using CSP or SI-348 containment spray operation using SCP b) Fails Same as 24a None Same as 24.a) None open

25. Test a) Fails Mechanical Inability to perform None None required for Connection closed binding leakage test of shutdown cooling Isolation Corrosion containment isolation Valve valve SI-967 b) Fails Same as 25a None Operator Series isolation Valve is normally SI-977 open valves SI-968/978 are closed closed

26. Test a) Fails Mechanical Inability to perform None None required for Connection closed binding hydrostatic test of shutdown cooling Isolation Corrosion SI-653/654 downstream Valve piping SI-965 b) Fails Same as 26a None Operator End of downstream Valve is normally SI-975 open line is capped stub closed 5.4-106 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (12 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

27. Sampling a) Fails Mechanical Unable to sample Operator Other SCS sample System closed binding shutdown cooling water locations Isolation Corrosion at this location Valve b) Fails Same as 27a None None Series isolation valve SI-252 open is closed SI-253

28. Shutdown a) One Contaminants Effective loss of one Low flow indications Redundant shutdown Periodic sampling and Cooling line shutdown cooling from F-302A or subsystem flow check will Line clogs subsystem F-305B; monitor buildup of contaminants b) Limited Seal failure Release of coolant and Local leak detection The leak can be leakage radio- activity outside of isolated without in one containment affecting the train redundant subsystem

29. SDCHX a) Fails Mechanical Unable to vent SDCHX Periodic testing None required for Vent Valve closed binding shutdown cooling SI-170 Corrosion SI-180 b) Fails Same as 29a None Periodic testing None Valve is normally open closed

30. SDCHX a) Fails Mechanical Unable to drain SDCHX Periodic testing None required for Drain closed binding shutdown cooling Valve Corrosion SI-172 b) Fails Same as 30a None Periodic testing End of downstream Valve is normally SI-182 open line is flanged closed 5.4-107 Rev. 2

APR1400 DCD TIER 2 Table 5.4.7-2 (13 of 13)

Symptoms and Local Inherent Failure Effects Including Compensating Remarks and No. Name Modes Cause Dependent Failure Method of Detection Provision Other Effects

31. SCP a) Fails Mechanical Unable to vent SCP Periodic testing None required for MFHX closed binding MFHX shutdown cooling Vent Valve Corrosion SI-570 b) Fails Same as 31a None Periodic testing None Valve is normally SI-571 open closed

32. SCP a) Fails Mechanical Unable to vent SCP Periodic testing None required for MFHX closed binding MFHX shutdown cooling Drain Corrosion Valve b) Fails Same as 32a None Periodic testing End of downstream Valve is normally SI-576 open line is flanged closed SI-577 5.4-108 Rev. 2

APR1400 DCD TIER 2 Table 5.4.10-1 Pressurizer Design Parameter Property Parameter Design pressure, kg/cm2A (psia) 175.8 (2,500)

Design temperature, °C (°F) 371.1 (700)

Normal operating pressure, kg/cm2A (psia) 158.2 (2,250)

Normal operating temperature, °C (°F) 344.8 (652.7) 3 3 Internal free volume, m (ft ) 68.0 (2,400)

Normal (full power) operating water volume, m3 (ft3) 33.2 (1,171)

Normal (full power) steam volume, m3 (ft3) 35.7 (1,260)

Installed heater capacity, kW 2,400 Heater type Immersion Spray flow, minimum design capacity, L/min (gpm) 1,703.4 (450)

Bypass spray flow, continuous, L/min (gpm) 1.9~22.7 (0.5~6)

Nozzles:

Surge, in (nominal) 12, schedule 160 Spray, in (nominal) 4, schedule 160 POSRV, in 6, Liner ID 7.75, nozzle ID Instrument:

Level, in (nominal) 3/4, schedule 160 Temperature, in (nominal) 1, schedule 160 Pressure, in (nominal) 3/4, schedule 160 Heater, OD, mm (in) 31.75 (1-1/4) 5.4-109 Rev. 2

APR1400 DCD TIER 2 Table 5.4.10-2 Pressurizer Tests Component Test Heads Plates UT, MT Cladding UT, PT Shell Plates UT, MT Cladding UT, PT Heaters Tubing UT, PT Centering of elements RT End plug UT, PT Nozzle (forgings) UT, MT Studs UT, MT Welds Shell, longitudinal RT, MT Shell, circumferential RT, MT Cladding UT, PT Nozzles RT, MT Nozzle safe ends RT, PT Instrument connections PT Support skirt MT, RT Temporary attachment after removal MT All welds after hydrostatic test MT or PT Heater assembly, end plug weld PT UT = Ultrasonic testing MT = Magnetic particle testing PT = Dye-penetrant testing RT = Radiographic testing 5.4-110 Rev. 2

APR1400 DCD TIER 2 Table 5.4.12-1 Reactor Coolant Gas Vent System - Active Valve List Valve Power Source Number Type Line Size - Schedule 125V DC Bus Actuator Safety Class RG-410 Globe 50 mm (2 in) - 160 A Solenoid 1 RG-411 Globe 50 mm (2 in) -160 B Solenoid 1 RG-412 Globe 50 mm (2 in) - 160 C Solenoid 1 RG-413 Globe 50 mm (2 in) - 160 D Solenoid 1 RG-414 Globe 25 mm (1 in) - 160 A Solenoid 1 RG-415 Globe 25 mm (1 in) - 160 B Solenoid 1 RG-416 Globe 25 mm (1 in) - 160 C Solenoid 1 RG-417 Globe 25 mm (1 in) - 160 D Solenoid 1 RG-419 Globe 80 mm (3 in) - 160 B Solenoid 2 RG-420 Globe 80 mm (3 in) - 160 A Solenoid 2 5.4-111 Rev. 2

APR1400 DCD TIER 2 Table 5.4.14-1 Pilot-Operated Safety Relief Valve Parameters Parameter Value Type Pilot operated Design pressure, kg/cm2A (psia) 175.8 (2,500)

Design temperature, °C (°F) 371.1 (700)

Fluid Boric Acid Water, Saturated Steam, Two-phase mixture pH = 4.5 to 10.6 Set pressure, kg/cm2A (psia) 173.7 (2,470)

Set pressure uncertainty, % +/- 0.75 Minimum capacity, kg/hr (lb/hr) 244,900 (540,000)

Maximum capacity, kg/hr (lb/hr) 285,700 (630,000)

Maximum opening/closing dead time, sec 0.2/0.4 (hydraulic actuation)

Maximum opening/closing time Open (hydraulic): 0.5 (including dead time), sec Close (hydraulic): 0.9 Closing pressure, kg/cm2A (psia) 87 % of opening pressure Typical materials:

Body Type 304 or 316, austenitic stainless steel Spindle Type 304 or 316, austenitic stainless steel Inlet/outlet flange Type 304 or 316, austenitic stainless steel 5.4-112 Rev. 2

APR1400 DCD TIER 2 Table 5.4.14-2 Main Steam Safety Valve Parameters Parameter Value Design pressure, kg/cm2G (psig) 86.48 (1,230)

Design temperature, °C (°F) 299 (570)

Fluid Saturated steam 2

Set pressure, kg/cm G (psig) 82.5 (1,174) 84.7 (1,205) 86.5 (1,230) 86.5 (1,230) 86.5 (1,230)

Set pressure uncertainty, +/-1/+/-3 manufacture/operation, %

Minimum capacity, kg/sec (lbm/hr) at 110 % of 2,394 (19 x 106) total steam generator design pressure (20 valves)

Type Spring loaded 2 2 Orifice area, cm (in ) 106.45 (16.5)

Accumulation, % 3 Back pressure:

Maximum buildup/maximum superimposed, 10.19/0 (145/0) kg/cm2G (psig)

Approximate dry weight, kg (lbs) 771 (1,700)

Blowdown, % 5 Typical materials:

Body ASME SA 105 Disc ASME SB 637 UNS N07718 Nozzle ASME SA 182, GR. F316 5.4-113 Rev. 2

APR1400 DCD TIER 2 MOTOR FLEXIBLE THRUST BEARING COUPLING ASSEMBLY MOTOR SUPPORT ASSEMBLY SEAL ASSEMBLY RIGID COUPLING JOURNAL BEARING DIFFUSER IMPELLER CASING SUCTION Figure 5.4.1-1 Reactor Coolant Pump 5.4-114 Rev. 2

APR1400 DCD TIER 2 Figure 5.4.1-2 Flow Diagram for Reactor Coolant Pump Shaft Seal System 5.4-115 Rev. 2

APR1400 DCD TIER 2 Figure 5.4.2-1 Steam Generator 5.4-116 Rev. 2

APR1400 DCD TIER 2 TUBE BUNDLE SHROUD EGGCRATE TUBE SUPPORT FLOW DISTRIBUTION CENTER PLATE SUPPORT MAIN FEEDWATER CYLINDER NOZZLE (ENTRANCE)

Figure 5.4.2-2 Steam Generator Economizer and Lower Tube Bundle Region 5.4-117 Rev. 2

APR1400 DCD TIER 2 406.4 mm (16 in)

Figure 5.4.2-3 Steam Generator Cold Side Recirculating Fluid Entrance Region 5.4-118 Rev. 2

APR1400 DCD TIER 2 50.8 mm (2 in) 25.4 mm (1 in)

Figure 5.4.2-4 Steam Generator Tube Eggcrate Support 5.4-119 Rev. 2

APR1400 DCD TIER 2 Figure 5.4.2-5 Steam Generator Tube Vertical Supports 5.4-120 Rev. 2

APR1400 DCD TIER 2 200 380 331 150 RCS Temp. (deg.C) RCS Temp. (deg.F) 282 233 100 184 135 50 86 0 10 20 30 40 50 60 Time after Reactor Shutdown (hr)

Figure 5.4.7-1 Shutdown Cooling System; Two Train Cooldown 5.4-121 Rev. 2

APR1400 DCD TIER 2 437 200 392 RCS Temp. (deg.C) RCS Temp. (deg.F) 347 150 302 257 100 212 167 13 14 15 16 17 18 19 20 Time after Reactor Shutdown (hr)

Figure 5.4.7-2 Shutdown Cooling System; One Train Cooldown 5.4-122 Rev. 2

CSS CONTAINMENT SPRAY PUMP 1 M SI-341 CSS M

M SI-340 SCS TRAIN 1 SHUTDOWN COOLING SHUTDOWN COOLING HEAT EXCHANGER 1 LINE LOOP 1 SI-310 SCS SI-568 SI-578 SCS SI-106 SHUTDOWN CCWS M COOLING PUMP 1 SI-312 SCS MINIFLOW HEAT EXCHANGER 1 CSS 5.4-123 CONTAINMENT SPRAY PUMP 2 M SI-343 APR1400 DCD TIER 2 CSS M

M SI-342 SCS TRAIN 2 SHUTDOWN COOLING SHUTDOWN COOLING HEAT EXCHANGER 2 LINE LOOP 2 SI-579 SI-311 SCS SI-569 SCS SI-107 SHUTDOWN CCWS M COOLING PUMP 2 SI-313 SCS MINIFLOW HEAT EXCHANGER 2 Figure 5.4.7-3 Shutdown Cooling System Flow Diagram; Shutdown Cooling Mode (1 of 2)

Rev. 2

SCS SCS SCS SCS SHUTDOWN COOLING SCS TRAIN 1 SHUTDOWN COOLING SCS TRAIN 2 PUMP 2 PUMP 1 SI-178 SI-168 M SI-656 M SI-600 M SI-601 M SI-655 OUTSIDE OUTSIDE CONTAINMENT CONTAINMENT INSIDE INSIDE CONTAINMENT CONTAINMENT SI-123 SI-143 5.4-124 M SI-654 M SI-653 APR1400 DCD TIER 2 SI-541 SI-543 M SI-652 M SI-651 SHUTDOWN COOLING SHUTDOWN COOLING LINE LOOP 2 LINE LOOP 1 RCS RCS DVI N0ZZLE 2B DVI N0ZZLE 1A RCS RCS SI-227 SI-247 Figure 5.4.7-3 Shutdown Cooling System Flow Diagram; Shutdown Cooling Mode (2 of 2)

Rev. 2

APR1400 DCD TIER 2 700 200 600 150 500 Head (ft) 400 Head (m) 100 300 200 50 100 0 0 0 5000 10000 15000 20000 25000 Flow (L/min)

Figure 5.4.7-4 Shutdown Cooling Pump Characteristic Curve (Typical) 5.4-125 Rev. 2

APR1400 DCD TIER 2 9A 5A 8A 1A 6A 7A 3A 2A 4A Reactor Vessel 4B 2B 3B 6B 7B 1B 5B 8B 9B Figure 5.4.7-5 Shutdown Cooling System Mode Diagram (1 of 2) 5.4-126 Rev. 2

APR1400 DCD TIER 2 Location 1A 2A 3A 4A 5A 6A 7A 8A 9A 1B 2B 3B 4B 5B 6B 7B 8B 9B Normal Pressure (kg/cm2A) 31.6 1.3 44.2 44.2 44.2 44.2 44.2 44.2 44.2 31.6 1.3 44.2 44.2 44.2 44.2 44.2 44.2 44.2 Shutdown Temperature (°C) ~176.7 ~48.9 ~176.7 ~151.1 <176.7 ~176.7 ~53.3 ~53.3 ~53.3 ~176.7 ~48.9 ~176.7 ~151.1 <176.7 ~176.7 ~53.3 ~53.3 ~53.3 Flow Rate (L/min) 18,927 0 1,609 1,609 20,536 18,927 18,927 18,927 0 18,927 0 1,609 1,609 20,536 18,927 18,927 18,927 0 2

Safety Pressure (kg/cm A) 28.1 1.3 44.2 44.2 44.2 44.2 44.2 44.2 44.2 28.1 1.3 44.2 44.2 44.2 44.2 44.2 44.2 44.2 Shutdown Temperature (°C) ~193.3 ~48.9 ~193.3 ~151.1 ~193.3 ~193.3 ~53.3 ~53.3 ~53.3 ~193.3 ~48.9 - - - - - - -

Flow Rate (L/min) 18,927 0 1,609 1,609 20,536 18,927 18,927 18,927 0 0 0 0 0 0 0 0 0 0 Refueling Pressure (kg/cm2A) 1.3 1.3 19.8 19.8 19.8 19.8 19.8 19.8 19.8 1.3 1.3 19.8 19.8 19.8 19.8 19.8 19.8 19.8 Temperature (°C) 48.9 ~48.9 48.9 ~46.7 48.9 48.9 ~40.0 ~40.0 ~40.0 48.9 ~48.9 48.9 ~46.7 48.9 48.9 ~40.0 ~40.0 ~40.0 Flow Rate (L/min) 18,927 0 1,609 1,609 20,536 18,927 18,927 18,927 0 18,927 0 1,609 1,609 20,536 18,927 18,927 18,927 0 2

Startup Pressure (kg/cm A) 31.6 1.3 44.2 44.2 44.2 44.2 44.2 44.2 44.2 31.6 1.3 44.2 44.2 44.2 44.2 44.2 44.2 44.2 Temperature (°C) ~176.7 ~48.9 ~176.7 ~151.1 ~176.7 ~176.7 ~176.7 ~176.7 ~176.7 ~176.7 ~48.9 ~176.7 ~151.1 ~176.7 ~176.7 ~176.7 ~176.7 ~176.7 Flow Rate (L/min) 18,927 0 1,609 1,609 20,536 0 0 18,927 18,927 18,927 0 1,609 1,609 20,536 0 0 18,927 18,927 Figure 5.4.7-5 Shutdown Cooling System Mode Diagram (2 of 2) 5.4-127 Rev. 2

APR1400 DCD TIER 2 100 80 Level Decreases Due To RVUH Void Collapsing 60 Pressurizer Level, %

Safety Injection Flow Initiated 40 20 Level Increases Due To RVUH Void Formation 0

0 2 4 6 8 10 12 Time, Hours Figure 5.4.7-6 Pressurizer Level vs. Time for NCC Transient 5.4-128 Rev. 2

APR1400 DCD TIER 2 98 1400 4 Hours At Hot Standby 84 1200 Commence Cooldown 70 1000 Steam Generator Pressure, kg/cm2A Steam Generator Pressure, Psia 56 800 42 600 Resume Cooldown 28 400 Start Final Cooldown Stop Cooldown And 14 Initiate Depressurization 200 0 0 0 2 4 6 8 10 12 Time, Hours Figure 5.4.7-7 Steam Generator Pressure vs. Time for NCC Transient 5.4-129 Rev. 2

APR1400 DCD TIER 2 640 Outlet 324 Average Commence Cooldown 576 288 Reactor Coolant Temperatures, oC Inlet Reactor Coolant Temperatures, oF 512 Resume Cooldown 252 448 216 Start Final Cooldown 384 Stop Cooldown To Prevent 180 RCS Overcooling 320 144 256 108 0 2 4 6 8 10 12 Time, Hours Figure 5.4.7-8 Reactor Coolant Temperatures vs. Time for NCC Transient 5.4-130 Rev. 2

APR1400 DCD TIER 2 Depressurize RCS By Opening Pressurizer Vent Valve 156 2220 130 1850 Pressurizer Pressure, kg/cm2A Pressurizer Pressure, psia Stop Cooldown And Start Depressurization 104 Stop Depressurization, 1480 Start Cooldown And Initiate Safety Injection Flow 78 1110 Stop Depressurization And Start Void Collapsing 52 740 Stop Void Collapsing And Start Cooldown 26 Stop Depressurization 370 And Start Void Collapsing Stop Void Collapsing And Start Final Cooldown 0 0 0 2 4 6 8 10 12 Time, Hours Figure 5.4.7-9 Pressurize Pressure vs. Time for NCC Transient 5.4-131 Rev. 2

APR1400 DCD TIER 2 110 198 Stop Cooldown And Start 100 Depressurization 180 90 162 80 144 Hot Leg Subcooling Margin, oC Hot Leg Subcooling Margin, oF 70 126 60 108 Start Initial Depressurization 50 90 40 72 Start Final Cooldown 30 Stop Void Collapsing 54 And Resume Cooldown 20 36 Stop Depressurization 10 Due To Decrease In 18 RCS Subcooling Margin 0 0 0 2 4 6 8 10 12 Time, Hours Figure 5.4.7-10 Hot Leg Subcooling Margin vs. Time for NCC Transient 5.4-132 Rev. 2

APR1400 DCD TIER 2 80 Start Void Collapsing Due To Safety Injection Flow Stop Void Collapsing By RVUH Gas Vent And Start Cooldown 64 2280 RVUH Steam Void Start To Form RVUH Water Volume, m3 RVUH Water Volume, ft3 48 1710 32 1140 Start Void Collapsing By RVUH Gas Vent When Void Increases 16 570 0 0 0 2 4 6 8 10 12 Time, Hours Figure 5.4.7-11 RVUH Water Volume vs. Time for NCC Transient 5.4-133 Rev. 2

APR1400 DCD TIER 2 1400 Approximately 1,140 m3 (300,000 gallons) 1260 Of Auxiliary Feedwater Used In Achieving 333 Shutdown Cooling Entry Conditions 1120 296 Integrated Auxiliary Feedwater Usage, 1000 gallons Integrated Auxiliary Feedwater Usage, m3 980 259 840 222 700 185 560 148 420 111 280 74 140 37 0 0 0 2 4 6 8 10 12 Time, Hours Figure 5.4.7-12 Integrated Auxiliary Feedwater Usage vs. Time for NCC Transient 5.4-134 Rev. 2

APR1400 DCD TIER 2 NOZZLE SCHEDULE NO.

NO. SERVICE REQUIRED 1 MANWAY 1 2 SURGE 1 3 SPRAY 1 4 POSRV 4 5 LEVEL-UPPER 3 6 LEVEL-LOWER 2 7 TEMPERATURE 2 8 HEATER 48 9 PRESSURE 4 10 RCGVS 4 Figure 5.4.10-1 Pressurizer 5.4-135 Rev. 2

APR1400 DCD TIER 2 100.0 PRESSURIZER LEVEL SETPOINT, %

50.0 30.0 0.0 293.7 307.2 (560.6) (585.0)

REACTOR COOLANT TEMPERATURE, ()

Figure 5.4.10-2 Pressurizer Level Setpoint Program 5.4-136 Rev. 2

APR1400 DCD TIER 2 337.8 (640) 326.7 (620) 323.9 (615)

REACTOR COOLANT TEMPERATURE ()

315.6 (600)

TH 307.2 304.2 (585)

(580) TAV 293.3 TC (560) 291.3 290.6 (556.3) (555) 282.2 (540) 271.1 (520) 20 40 60 80 100 STEAM GENERATOR POWER, PERCENT OF WARRANTY Figure 5.4.10-3 Temperature Control Program 5.4-137 Rev. 2

APR1400 DCD TIER 2 Pressurizer Level Error, mm (in) Action

+1,244.6 (+49) High-level error alarm

+1,168.4 (+46) Letdown orifice isolation value (CH-110Z) open

+1,117.6 (+44) Clear high-level error alarm

+431.8 (+17) Letdown orifice isolation valve (CH-110Z) close Energize backup heaters

+355.6 (+14) Backup heaters off

-355.6 (-14) Clear low-level error alarm

-482.6 (-19) Low-level error alarm

-1,955.8 (-77) Letdown orifice isolation valve (CH-110Y) open

-3,251.2 (-128) Letdown orifice isolation valve (CH-110Y) close

Level increasing relative to setpoint

Level decreasing relative to setpoint Figure 5.4.10-4 Pressurizer Level Error Program 5.4-138 Rev. 2

APR1400 DCD TIER 2 Figure 5.4.10-5 Pressurizer Pressure Control Program 5.4-139 Rev. 2

APR1400 DCD TIER 2 NOTES

1. SIGHT GLASS MUST BE CONNECTED ONLY WHEN VENTING OPERATION FOR RCS FILLING IS REQUIRED. DURING ALL MODES OF OPERATION EXCEPT ABOVE OPERATION, THE STRAIGHT REMOVAL SPOOL WITHOUT SIGHT GLASS MUST BE CONNECTED.

SHEET 5 CV:RDT TEW 106 IAH 418 BI D LC, FC S

3"X2" TEW 107 IAH 419 REMOVAL SPOOL S

(NOTE 1) 3" 4" FG LC ,FC 3"X4" SY01 V1430 D CI 1421 TEW 4"

108 3"

IAH 420 S 4" LC,FC 3"X4" 11/2" 413 411 BI DII S S 3" 3"X2" 2" LC ,FC LC,FC BI AI PT 3/4" 106 ISAH 412 410 S S RC:PRESSURIZER 3" 2" SHEET 3 3"X2" LC,FC LC, FC BI AI 4"

3" 417 415 S S 1" 1" RCGVS SPARGER 1"X3" LC ,FC LC ,FC BI AI 416 S S 414 IRWST RC:REACTOR VESSEL VENT 1" 1" 3/4" SHEET 1 LC ,FC LC ,FC 1"X3/4" BI AI Figure 5.4.12-1 Reactor Coolant Gas Vent System Flow Diagram 5.4-140 Rev. 2

APR1400 DCD TIER 2 V1 V2 M VS66 VS66 M P1 P2 V-1 V-4 VS99 P1 PDE P2 M M V3 V-3 V-2 VS99 : Main Valve VS66 : Spring Loaded Pilot Valve PDE : Motor Operated Pilot Valves M: Motor Operated Valve Vi : Pilot Discharge Pi : Impulse Line Figure 5.4.14-1 Pilot Operated Safety Relief Valve Schematic Diagram 5.4-141 Rev. 2

APR1400 DCD TIER 2 Figure 5.4.15-1 Reactor Coolant System Arrangement and Support Points 5.4-142 Rev. 2

APR1400 DCD TIER 2 Figure 5.4.15-2 Reactor Vessel Support 5.4-143 Rev. 2

APR1400 DCD TIER 2 Figure 5.4.15-3 Steam Generator Supports 5.4-144 Rev. 2

APR1400 DCD TIER 2 Figure 5.4.15-4 Reactor Coolant Pump Supports 5.4-145 Rev. 2

APPENDIX 5A EVALUATION OF THE APR1400 DESIGN TO INTERSYSTEM LOSS-OF-COOLANT ACCIDENT CHALLENGES Rev. 2

APR1400 DCD TIER 2 APPENDIX 5A - EVALUATION OF THE APR1400 DESIGN TO INTERSYSTEM LOSS-OF-COOLANT ACCIDENT CHALLENGES TABLE OF CONTENTS NUMBER TITLE PAGE APPENDIX 5A - Evaluation of the APR1400 Design TO InterSystem Loss-of-Coolant Accident Challenges ......................................................................................... 5A-1 5A.1 Introduction ...................................................................................................... 5A-1 5A.1.1 Background ........................................................................................ 5A-1 5A.1.2 Objectives .......................................................................................... 5A-1 5A.1.3 Scope .................................................................................................. 5A-2 5A.2 Conclusions ....................................................................................................... 5A-3 5A.3 Design Requirements and Approach .............................................................. 5A-4 5A.3.1 ISLOCA Definition............................................................................ 5A-4 5A.3.2 ISLOCA Acceptance Criteria ............................................................ 5A-4 5A.3.3 Conformance Methods ....................................................................... 5A-4 5A.3.4 ISLOCA Evaluation Process ............................................................. 5A-5 5A.4 Design Responses .............................................................................................. 5A-8 5A.4.1 Shutdown Cooling System................................................................. 5A-9 5A.4.1.1 Description of Interface .................................................. 5A-9 5A.4.1.2 Design Evaluation ........................................................... 5A-9 5A.4.2 Safety Injection System ................................................................... 5A-10 5A.4.2.1 Description of Interface ................................................ 5A-10 5A.4.2.2 Design Evaluation ......................................................... 5A-10 5A.4.3 Containment Spray System .............................................................. 5A-10 5A.4.3.1 Description of Interface ................................................ 5A-10 5A.4.3.2 Design Evaluation ......................................................... 5A-11 5A.4.4 Letdown Line ................................................................................... 5A-12 5A.4.4.1 Description of Interface ................................................ 5A-12 5A.4.4.2 Design Evaluation ......................................................... 5A-12 i Rev. 2

APR1400 DCD TIER 2 5A.4.5 Charging Line .................................................................................. 5A-15 5A.4.5.1 Description of Interface ................................................ 5A-15 5A.4.5.2 Design Evaluation ......................................................... 5A-16 5A.4.6 Reactor Coolant Pump Seal Injection Line...................................... 5A-17 5A.4.6.1 Description of Interface ................................................ 5A-17 5A.4.6.2 Design Evaluation ......................................................... 5A-18 5A.4.7 Reactor Coolant Pump Controlled Bleedoff Line............................ 5A-19 5A.4.7.1 Description of Interface ................................................ 5A-19 5A.4.7.2 Design Evaluation Change ............................................ 5A-19 5A.4.8 Sampling System ............................................................................. 5A-20 5A.4.8.1 Hot Leg Sampling ......................................................... 5A-20 5A.4.8.2 Pressurizer Surge Line Sampling .................................. 5A-21 5A.4.8.3 Pressurizer Steam Space Sampling ............................... 5A-22 5A.4.9 Component Design Responses......................................................... 5A-23 5A.4.9.1 Flanges .......................................................................... 5A-23 5A.4.9.2 Valves ........................................................................... 5A-24 5A.4.9.3 Pump Seals .................................................................... 5A-26 5A.4.9.4 Heat Exchangers ........................................................... 5A-27 5A.4.9.5 Vents, Drains, and Local Samples ................................ 5A-33 5A.5 Detection of ISLOCA ..................................................................................... 5A-35 5A.5.1 Valve Position Indication................................................................. 5A-35 5A.5.2 Pressure Indication ........................................................................... 5A-36 5A.5.3 Tank Level Indication ...................................................................... 5A-36 5A.5.4 Radiation Monitoring ....................................................................... 5A-36 5A.6 References ....................................................................................................... 5A-37 ii Rev. 2

APR1400 DCD TIER 2 LIST Of TABLES NUMBER TITLE PAGE Table 5A-1 APR1400 ISLOCA Design ........................................................................ 38 Table 5A-2 Systems Interfacing with the CVCS Downstream of the Letdown Control Valve .............................................................................. 39 Table 5A-3 Low-Pressure Equipment of the CVCS ..................................................... 40 Table 5A-4 Heat Exchangers that may be Exposed to Full RCS Operating Pressure ...................................................................................................... 41 Table 5A-5 Containment Isolation Valve Position Indication ...................................... 42 Table 5A-6 Pressure Indication ..................................................................................... 43 Table 5A-7 Tank Level Indication ................................................................................ 44 iii Rev. 2

APR1400 DCD TIER 2 LIST OF FIGURES NUMBER TITLE PAGE Figure 5A-1 Shutdown Cooling System ......................................................................... 45 Figure 5A-2 Safety Injection System.............................................................................. 46 Figure 5A-3 Letdown Line ............................................................................................. 47 Figure 5A-4 Charging Line............................................................................................. 48 Figure 5A-5 RCP Seal Injection ..................................................................................... 49 Figure 5A-6 RCP Controlled Bleedoff ........................................................................... 50 Figure 5A-7 Sampling - Hot Leg ................................................................................... 51 Figure 5A-8 Sampling - Pressurizer Surge Line ............................................................ 52 Figure 5A-9 Sampling - Pressurizer Steam Space ......................................................... 53 Figure 5A-10 Shutdown Cooling System ......................................................................... 54 Figure 5A-11 Safety Injection System (Low-Pressure Line Interface) ............................ 55 Figure 5A-12 Containment Spray System ........................................................................ 56 Figure 5A-13 Letdown Line (including Pressure Alarm) ................................................. 57 Figure 5A-14 Charging Line (including Pressure Alarm) ................................................ 58 Figure 5A-15 Seal Injection Line ..................................................................................... 59 Figure 5A-16 Controlled Bleedoff Line ........................................................................... 60 Figure 5A-17 Sampling System - Hot Leg ...................................................................... 61 Figure 5A-18 Sampling System - Pressurizer Surge Line ............................................... 62 Figure 5A-19 Sampling System - Pressurizer Steam Space ............................................ 63 iv Rev. 2

APR1400 DCD TIER 2 APPENDIX 5A- EVALUATION OF THE APR1400 DESIGN TO INTERSYSTEM LOSS-OF-COOLANT ACCIDENT CHALLENGES 5A.1 Introduction 5A.1.1 Background Studies conducted to identify the vulnerability of pressurized water reactor (PWR) plants to intersystem loss-of-coolant accidents (ISLOCAs) have concluded that ISLOCAs could cause core damage substantially more often than probabilistic safety assessments (PSAs) from some PWR plants have indicated. According to U.S. Nuclear Regulatory Commission (NRC) Information Notice 92-36 (Reference 1), these PSAs are typically limited to modeling ISLOCA sequences that include only a catastrophic failure of check valves that isolate the reactor coolant system (RCS) from low-pressure systems and give little consideration to human errors that could lead to an ISLOCA. The PSAs also include little consideration of harsh environments such as flooding that could be caused by an ISLOCA and their effects on plant equipment and recovery activities.

The results of the studies suggest that ISLOCA precursors are most likely human error and procedural deficiencies and are attributed to a lack of awareness of the possibility or consequences of an ISLOCA.

The NRC has developed a position on design requirements to minimize the potential for ISLOCAs (NRC Information Notice 92-36 (Reference 1); NRC Letter (Reference 2);

SECY-90-016 (Reference 4); NUREG/CR-5102 (Reference 7)). The APR1400 design has been evaluated, and several design improvements necessary to conform with the NRC position have been identified. The evaluation and improvements are described in this appendix.

5A.1.2 Objectives The objectives of this appendix are to (1) evaluate the design of systems that interface with the RCS, (2) provide reasonable assurance that the systems would retain structural integrity in an ISLOCA, and (3) provide reasonable assurance that any leakage would be a small fraction of the makeup system capability and that the consequential offsite dose would be a small fraction of that allowed in 10 CFR 100.11.

5A-1 Rev. 2

APR1400 DCD TIER 2 The evaluation goes beyond the traditional approach of assessing the ability of the systems that interface with the RCS to withstand an overpressurization event. Instead, the approach is to assume that the system design incorporates all of the requirements necessary to satisfy the General Design Criteria and then to consider the exposure of a low-pressure system to full RCS pressure.

5A.1.3 Scope The scope of the evaluation is applicable to the APR1400 design and the systems and subsystems that interface directly or indirectly with the RCS and that are susceptible to ISLOCA challenges.

5A-2 Rev. 2

APR1400 DCD TIER 2 5A.2 Conclusions The improvements to the APR1400 design that facilitate accommodating an ISLOCA and that are described in this appendix include a 63.3 kg/cm2G (900 psig) design of several portions of low-pressure systems, additional pressure instrumentation to provide warning of a high-pressure condition, and relocation of the refueling water storage tank inside containment. The APR1400 design, including these improvements, conforms with all NRC requirements concerning ISLOCA events.

The improvements made to the APR1400 design resulting from this ISLOCA evaluation include:

a. Increasing the design pressure rating of equipment or systems

b. Adding equipment and instrumentation that alert the operator to an ISLOCA challenge or terminate and limit the scope of an ISLOCA event These improvements are made together with the following:

a. Capability to leak test pressure isolation valves

b. Pressure isolation valve position indications and controls in the main control room (MCR)

c. High pressure alarms to warn the operator when rising pressure approaches the design pressure of low-pressure systems to provide reasonable assurance of conformance with the applicable NRC requirements Table 5A-1 summarizes the design improvements made to the APR1400 design as a result of the ISLOCA evaluation.

5A-3 Rev. 2

APR1400 DCD TIER 2 5A.3 Design Requirements and Approach 5A.3.1 ISLOCA Definition An ISLOCA is defined in NRC Information Notice 92-36 as a class of accidents in which a break occurs in a system connected to the reactor coolant system (RCS), causing a loss of the primary system inventory. An ISLOCA is interpreted as a beyond design basis event for systems that are connected directly or indirectly to the RCS. The pressurization pathway is established by an inadvertent opening of a valve or valves, a failure of containment isolation, or the postulation that valves are fully open (e.g., check valves).

This interpretation is believed to address all sources that may challenge low-pressure systems. Based on this definition of ISLOCA, evaluations were performed to assess the ability of the APR1400 design to withstand an overpressurization event.

5A.3.2 ISLOCA Acceptance Criteria The design responses to ISLOCA challenges described in this appendix are evaluated against acceptance criteria consistent with the guidance in NRC Information Notice 92-36.

The systems that are susceptible to an ISLOCA are to be designed so that the following conditions are satisfied:

a. The system retains its structural integrity throughout the event. Structural integrity is preserved if the system maintains its pressure boundary despite distortion and/or loss of function.

b. Any leakage caused by the event is limited to the makeup system capabilities.

c. Offsite doses are limited to a small fraction of the limit specified in 10 CFR 100.11, as assumed in the design bases for the Chapter 15 analyses.

5A.3.3 Conformance Methods The design responses to ISLOCA challenges described in this appendix consist of:

a. Increasing the design pressure rating of equipment or systems Systems or subsystems susceptible to an ISLOCA are designed to a pressure of at least 40 percent (63.3 kg/cm2G (900 psig)) of the RCS normal operating pressure.

5A-4 Rev. 2

APR1400 DCD TIER 2 Austenitic stainless steel piping uses a minimum wall thickness corresponding to the standard weight for sizes less than 406.4 mm (16 in.) nominal pipe size (NPS) and schedule 40 for 406.4 mm (16 in.) NPS and larger sizes (NUREG/CR-5603, Reference 3).

b Incorporating the following design features that alert the operator to an ISLOCA challenge or terminate and limit the scope of the ISLOCA event:

1) Locating the systems or subsystems susceptible to an ISLOCA completely within containment

2) Isolating the systems or subsystems from the RCS during conditions when the RCS pressure exceeds its design pressure

3) Providing pressure relief to limit the pressurization to within the design capabilities of the systems or subsystems 5A.3.4 ISLOCA Evaluation Process The APR1400 was designed by reflecting the traditional design bases events. The evaluation of ISLOCA events performed for this appendix and the subsequent determination of the appropriate design responses consisted of the following:

a. The RCS flow diagram described in Chapter 5 was reviewed to identify all systems or subsystems that interface with the RCS. All systems and subsystems within containment or designed to full RCS operating pressure were noted to meet the acceptance criteria. The systems or subsystems located outside containment and designed for less than RCS pressure were evaluated to determine the pressurization pathways from the RCS. The pathways represent all of the possible ways to pressurize the low-pressure systems connected to the RCS.

b. The pressurization pathways were further evaluated to determine the impact of the interface of systems or subsystems with the initiating pressurization pathway. The pressurization pathways are illustrated in Figures 5A-1 to 5A-9. The figures show a pyramid structure beginning at the top with a system or subsystem that is directly connected with the RCS. A given pyramid represents a class of potential ISLOCA events characterized by a finite set of pressurization pathways. The systems that 5A-5 Rev. 2

APR1400 DCD TIER 2 could be pressurized if all of the interfacing system valves are postulated to be open are identified in the pressurization pathways.

c. The pressurization pathways were analyzed to identify any pattern that could suggest a hierarchy of design responses to prevent or mitigate an ISLOCA event.

Any hierarchical pattern would be motivated by the desire to satisfy the ISLOCA acceptance criteria with a design response commensurate with the perceived benefit and without degradation of safety.

d. Each interface in the pressurization pathways was analyzed to identify the type and location of design response to satisfy the ISLOCA acceptance criteria.

A review of the pressurization pathways in Figures 5A-1 to 5A-9 led to the following observations:

a. The following systems or subsystems are directly connected to the RCS for one or more ISLOCA events (i.e., are in one or more pressurization pathways), and all ISLOCA events (pressurization pathways) begin with these systems or subsystems:

1) Safety injection system (SIS)

2) Shutdown cooling system (SCS)

3) Chemical and volume control system (CVCS)

4) Sampling system (SS)

b. The following nine classes of pressurization pathways were identified:

1) Shutdown cooling line

2) Safety injection delivery line

3) Letdown line

4) Charging line

5) RCP seal injection

6) RCP controlled bleedoff 5A-6 Rev. 2

APR1400 DCD TIER 2

7) Sampling - hot leg

8) Sampling - pressurizer surge line

9) Sampling - pressurizer steam space

c. The containment spray system (CSS) is not directly connected to the RCS for the ISLOCA events that are identified. For more information, see Subsection 5A.4.3.

d. A given system can occupy several levels in the interface hierarchy for any ISLOCA event.

d. The design response applied to a system should be commensurate with the highest interface level (i.e., the highest position in the pyramid) that a system may have for any ISLOCA event. The rationale is that there is a correlation between a systems position in the hierarchy and the scope of the event (number of interfacing systems affected), which is one measure of consequence of the event.

e. Increasing the design pressure rating of a system high in a pyramid, such as a design response to ISLOCA precursors, does not protect connected subsystems lower in the pyramid. These subsystems still require a design response of their own. For example, designing the SCS to 40 percent of normal RCS operating pressure does not address the protection of the systems that interface with the SCS against ISLOCAs.

f. The application of a design response that terminates and limits the scope of the event to a system high in the pyramid can protect subsystems lower in the pyramid.

For example, isolation of the letdown flow terminates the event and protects downstream portions of the CVCS as well as interconnecting systems (e.g., SS, waste management system). Such downstream effects, which are characteristic of some design responses, are important considerations in selecting an appropriate design response.

5A-7 Rev. 2

APR1400 DCD TIER 2 5A.4 Design Responses This section presents an evaluation of the systems and subsystems that are directly connected to the RCS during some mode of operation, which are identified in Subsection 5A.3.4 as the classes of pressurization pathways in relation to an ISLOCA. Any ISLOCA event begins with one of the systems or subsystems. The systems and subsystems are as follows:

a. Shutdown cooling line (Subsection 5A.4.1)

b. Safety injection delivery line (Subsection 5A.4.2)

c. Letdown line (Subsection 5A.4.4)

d. Charging line (Subsection 5A.4.5)

e. RCP seal injection (Subsection 5A.4.6)

f. RCP controlled bleedoff (Subsection 5A.4.7)

g. Sampling - hot leg (Subsection 5A.4.8.1)

h. Sampling - pressurizer surge line (Subsection 5A.4.8.2)

i. Sampling - pressurizer steam space (Subsection 5A.4.8.3)

The evaluation of each system and subsystem that is presented in this section is structured as follows:

a. Description of the interface and related system under evaluation to provide orientation to the system and the components affected by the design response

b. Design evaluation - description of the mechanical and electrical features of the design that have been incorporated to resolve the ISLOCA challenge; schematic drawing of the features; and description of any impact from the design response on the PSA, emergency operation guidelines (EOGs), or configuration management 5A-8 Rev. 2

APR1400 DCD TIER 2 5A.4.1 Shutdown Cooling System 5A.4.1.1 Description of Interface The SCS supply line is directly connected to the RCS and is a primary interface through which an ISLOCA event can begin. Pressurization is postulated from the hot leg and out of containment through the containment isolation valves to the low-pressure sections of the SCS. Once pressurized, other low-pressure systems are susceptible.

Figure 5A-1 shows the various pathways an ISLOCA in this class can take and the interfacing systems it would affect, assuming all downstream interfacing valves are open.

The SCS interface with the atmosphere is described in Subsection 5A.4.9.5. The interface with the SIS, CSS, and sampling system (SS) is described in Subsections 5A.4.2, 5A.4.3, and 5A.4.8, respectively.

The SCS return line is directly connected to the RCS and is a primary interface through which an ISLOCA event can begin. Pressurization is postulated from the direct vessel injection (DVI) nozzles and out of containment through the containment isolation valves to the low-pressure sections of the SCS. Once pressurized, other low-pressure systems are susceptible to damage from the high-pressure condition.

Figure 5A-1 shows the various pathways an ISLOCA in this class can take and the interfacing systems it would affect assuming all downstream interfacing valves are open.

The SCS interface with the atmosphere is described in Subsection 5A.4.9.5. The interfaces with the SIS and SS are described in Subsections 5A.4.2 and 5A.4.8, respectively. The CVCS, SS, and SIS have a direct interface with the RCS, and the enhancements satisfy the indirect interface through the SCS.

5A.4.1.2 Design Evaluation The design pressure for most of the SCS supply and return lines is equal to or greater than 63.3 kg/cm2G (900 psig). This design response satisfies the ISLOCA acceptance criteria (i.e., at least 40 percent of normal RCS pressure or 63.3 kg/cm2G [900 psig]).

Figure 5A-10 shows the design responses for this class of ISLOCA. This is in accordance with the NRC's position presented in the NRC Letter (Reference 2).

The design response to an ISLOCA has no impact on the PSA or EOGs.

5A-9 Rev. 2

APR1400 DCD TIER 2 5A.4.2 Safety Injection System 5A.4.2.1 Description of Interface The SIS injection line is directly connected to the reactor vessel and is a primary interface through which an ISLOCA can begin. Pressurization is postulated from the DVI nozzle and out of containment through the containment isolation valves to the low-pressure sections of the system. Once pressurized, other low-pressure systems are susceptible.

Figure 5A-2 shows the various pathways an ISLOCA in this class can take and the interfacing systems it would affect assuming all downstream interfacing valves are open.

The SIS interfaces with the CSS, SS, and atmosphere are described in Subsections 5A.4.3, 5A.4.8, and 5A.4.9.5, respectively. The interface with the SCS is described in Subsection 5A.4.1; the SCS has a direct interface with the RCS and the enhancements that have been made satisfy the indirect interface through the SIS.

5A.4.2.2 Design Evaluation The design pressure for most of the SIS is 144.1 kg/cm2G (2,050 psig), which satisfies the ISLOCA acceptance criteria (i.e., at least 40 percent of normal RCS pressure or 63.3 kg/cm2G [900 psig]). The design pressures of all other sections outside of containment not designed to 144.1 kg/cm2G (2,050 psig) are designed to 63.3 kg/cm2G (900 psig) including the sections from the containment to the SIS pump suctions. Figure 5A-11 shows the design response for this class of ISLOCAs.

These design responses protect the SIS lines and all interfacing systems from an ISLOCA challenge without adversely affecting performance or operations. These design responses satisfy the ISLOCA acceptance criteria for the SIS lines since all sections of the system and interfaces are designed to at least 40 percent of the RCS operating pressure criteria in accordance with the NRC position presented in the NRC Letter.

The design response to an ISLOCA has no impact on the PSA or EOGs.

5A.4.3 Containment Spray System 5A.4.3.1 Description of Interface The CSS is not directly connected to the RCS during the modes of operation in which an ISLOCA challenge can occur.

5A-10 Rev. 2

APR1400 DCD TIER 2 Technical Specifications require the CSS to be aligned for the containment spray function during Modes 1, 2, 3, and 4. This requires the CSS pumps to be aligned for suction from the IRWST and discharge to the containment spray headers. With this alignment, the CSS does not interface directly with the RCS, but there is an indirect interface through the SCS.

The shutdown cooling pumps (SCPs) can be aligned to perform containment spray for limited periods of time. With this alignment, the CSS still does not interface directly with the RCS since the SCPs are aligned for suction from the IRWST and discharge to the containment spray headers.

When shutdown cooling operations are performed, the containment spray pumps (CSPs) may be substituted for SCPs. This requires the CSPs to be realigned for suction from the RCS hot legs (through the SCS) and discharge to the DVI nozzles (again, through the SCS).

While the CSPs are directly connected to the RCS during this configuration, ISLOCAs are not postulated since the RCS pressure is less than the design pressure of the CSS during this operation mode.

For purposes of this ISLOCA evaluation, the CSS is not directly connected to the RCS.

Figures 5A-1 through 5A-9 show the various pathways an ISLOCA can progress to reach the CSS and the interfacing systems it would affect, assuming all downstream interfacing valves are open.

5A.4.3.2 Design Evaluation These design responses protect the CSS and all interfacing systems from an ISLOCA challenge without adversely affecting performance or operations. These design responses satisfy the ISLOCA acceptance criteria for the CSS since all sections of the system and interfaces are designed to at least 40 percent of RCS operating pressure criteria in accordance with the NRC position presented in the NRC Letter.

Installation of a spool piece in the refueling pool fill line provides physical separation of the low-pressure system from any pressurization sources in the CSS and thereby satisfies the ISLOCA acceptance criteria.

Figure 5A-12 shows the design response for this class of ISLOCAs.

5A-11 Rev. 2

APR1400 DCD TIER 2 5A.4.4 Letdown Line 5A.4.4.1 Description of Interface The letdown line is directly connected to the RCS and is a primary interface through which an ISLOCA event can begin. Pressurization is postulated from the letdown nozzle, through the regenerative heat exchanger (HX), letdown orifices, letdown HX, containment isolation valves, and letdown control valves to the low-pressure sections of the system out of containment. Once pressurized, other low-pressure interfacing systems are susceptible.

Figure 5A-3 shows the various pressurization pathways that this class of ISLOCAs can take and the systems it would affect assuming all downstream interfacing valves are open.

5A.4.4.2 Design Evaluation The letdown line design was evaluated to satisfy the ISLOCA acceptance criteria for the APR1400 design. Figure 5A-13 shows the design response for this class of ISLOCAs. An additional high-pressure alarm has been provided to the letdown line and is located downstream of the letdown control valves. The alarm provides information to the operator that operating pressure is exceeding the design pressure. Thus, the control room operator can isolate the letdown line to prevent any further pressure communication downstream of the containment isolation valve.

This design response satisfies the ISLOCA acceptance criteria because:

a. System integrity is preserved since the portion of the letdown line pressurized by the ISLOCA is designed to full RCS design pressure.

b. The portion of the letdown line downstream of the letdown control valves and all other downstream interfacing systems are protected from an ISLOCA by the operators manual action and therefore do not have an integrity challenge.

c. Primary coolant is not lost, and offsite doses do not change since system integrity is preserved.

The following design response to this event was also evaluated: increasing the design pressure of the entire CVCS to 40 percent of full RCS operating pressure (i.e.,

63.3 kg/cm2G (900 psig)) and necessarily all systems that interface with the CVCS downstream of the letdown control valves (see Table 5A-2). Although this design response satisfies the ISLOCA acceptance criteria, it is not considered practical because of the 5A-12 Rev. 2

APR1400 DCD TIER 2 increased complexity to the CVCS, the addition of new systems, the number of systems affected, and the reliance on new unproven systems, equipment, and fabrication techniques.

In addition, these features are not perceived to be commensurate with the benefit, especially when compared with the other design responses that were also considered.

Increasing the design pressure of the low-pressure portion of the CVCS may initially appear to be desirable simply because no operator action is required to mitigate the event.

However, there are many other low-pressure systems that interface with the CVCS (Table 5A-2) that could also be exposed to RCS pressure given the ground rules for postulating ISLOCA precursors. Thus, these additional systems would also need to be designed to a higher pressure to mitigate the effects of this event.

Table 5A-3 shows the low-pressure CVCS equipment. The magnitude of the effect on the equipment has been estimated based on NUREG/CR-5603, as follows:

a. Ion exchangers - These components, having a wall thickness of 8.0 mm (5/16 in.),

would be required to have their wall thicknesses increased by a factor of approximately 3 to 5.

b. Purification filters - These components, having a wall thickness of 4.8 mm (3/16 in.) to 9.5 mm (3/8 in.), would be required to have their wall thicknesses increased by a factor of 2.

c. Volume control tank - The wall thicknesses of the tanks would be increased by a factor of 10.

d. Field-fabricated tanks - The impact to very large field-fabricated tanks, such as the reactor makeup water tank (RMWT), with a volume of 1,495 m3 (395,000 gal), is estimated to be even more significant. These tanks are fabricated in the field because of their size. Fabrication of high-pressure tanks of this size would constitute new technology since new fabrication techniques would have to be developed to accommodate the increased plate thickness, and a redesign of structural supports and basemats would be required to support the increased load.

The complexity of such equipment and systems is directly proportional to the effects of increasing design pressure, namely:

5A-13 Rev. 2

APR1400 DCD TIER 2

a. These kinds of design changes to commercially available equipment would require special designs that are not readily available.

b. Heavier components would require redesigning supporting structures such as pipe supports and building floors.

c. Heavier components would require a re-evaluation of the seismic analyses to account for the additional loads.

In addition, there are several low-pressure tanks in the CVCS (Table 5A-3) that are vented to the atmosphere and are used during various plant modes to process water for RCS operations. These vents prevent the pumps from drawing an excessive vacuum on the tank and subsequently damaging the tank or cavitating the pumps during draining and prevent the tanks from pressurizing during fill operations. If the design pressure of the subsystems in which these tanks are located were increased to 63.3 kg/cm2G (900 psig), the tanks would have to be designed to the same pressure. As a result, the vents would have to be eliminated and a new supporting system designed to facilitate filling and draining operations. The new systems would in turn need to have a high-pressure design (at least 63.3 kg/cm2G (900 psig)) and have a flow rate capacity sufficient to support the simultaneous operation of all of the tanks. Additionally, a failure to the new system would restrict the ability to control plant operations requiring RCS inventory and boron control.

These examples illustrate the impracticality of increasing the design pressure of the CVCS as a design response for the letdown line because:

a. New systems would have to be added

b. The complexity of the overall design would increase

c. Many additional systems would be affected (see Table 5A-2)

To satisfy the ISLOCA acceptance criteria, the enhanced design of the letdown line also satisfies the requirements of SECY-90-016 by providing:

a. High pressure alarm in the control room to warn the operators of the event

b. Containment isolation valve position indication and control in the MCR

c. Periodic leak testing of the containment isolation valves 5A-14 Rev. 2

APR1400 DCD TIER 2 The design response shown in Figure 5A-13 satisfies the ISLOCA acceptance criteria, defined by the NRC in the NRC Letter, and also accomplishes the following:

a. The operator limits the scope of the event by terminating the event at a location that prevents the rest of the CVCS and its interfacing systems from being pressurized.

b. The design response avoids the need to design and procure special equipment to withstand the high pressures characteristic of this event, some of which may not be considered available technology.

c. A pressure relief valve in the letdown line limits the pressurization to the design capability of this system.

Increasing the complexity of all the low-pressure systems interfacing with the CVCS downstream of the letdown control valve to mitigate an event such as an ISLOCA is impractical.

Based on these observations, the design response shown in Figure 5A-13 is considered the preferred approach for this class of ISLOCAs.

It was determined that additional Technical Specifications are not required and that the selected design response does not affect the PSA or EOGs.

5A.4.5 Charging Line 5A.4.5.1 Description of Interface The charging line is directly connected to the RCS and is a primary interface through which an ISLOCA event can begin. Pressurization is postulated from the charging nozzle, through the shellside of the regenerative HX, charging control valve, and charging pump to the low-pressure sections of the system. Once pressurized, other low-pressure interfacing systems are susceptible. This process also assumes that the charging pump and the auxiliary charging pump (ACP) are not operating. Figure 5A-4 shows the various pathways the ISLOCAs in this class can take and the systems they would affect assuming all downstream interfacing valves are open. There are a total of three check valves in the charging line from the RCS nozzle to the charging pump discharge.

5A-15 Rev. 2

APR1400 DCD TIER 2 5A.4.5.2 Design Evaluation The charging line design was evaluated to satisfy the ISLOCA acceptance criteria for the APR1400 design. Figure 5A-14 shows the installation of a pressure sensor to the charging line in the common suction line.

The pressure indicator provides information to the operator that the operating pressure is exceeding the design pressure.

This design response satisfies the ISLOCA acceptance criteria because:

a. System integrity is preserved since the portion of the charging line (charging pump discharge line) pressurized by the ISLOCA is designed to full RCS design pressure.

b. The portion of the charging line upstream of the charging pumps (including charging pump miniflow heat exchanger (MFHX) and all other upstream interfacing systems are protected from an ISLOCA by the operators action and therefore do not have an integrity challenge.

c. Primary coolant is not lost, and offsite doses do not change since system integrity is preserved.

The justification for installing the pressure indicator follows the same rationale as presented in Subsection 5A.4.4.2 for the letdown line. Therefore, this section summarizes the justification and expands on items specific to the charging line.

The examples presented in Subsection 5A.4.4.2 illustrate the impracticality of increasing the design pressure of the CVCS as a design response.

The design of the charging line satisfies the requirements in the NRC Letter by providing:

a. A high-pressure alarm in the control room to warn the operators of the event

c. Containment isolation valve position indication and control in the control room

b. Periodic leak testing of the containment isolation valve The design response shown in Figure 5A-14 satisfies the ISLOCA acceptance criteria in the NRC Letter and also accomplishes the following:

5A-16 Rev. 2

APR1400 DCD TIER 2

a. It limits the scope of the event by terminating the event at a location that prevents the rest of the CVCS and its interfacing systems from being pressurized.

b. It avoids the need to design and procure special equipment to withstand the high pressures characteristic of this event, some of which may not be considered available technology.

There is a difference between the letdown line and the charging line. In the letdown line, the postulated pressurization pathway is with the normal flow direction. This means that the letdown line has been designed to reduce and control the fluid pressure under normal and ISLOCA operating conditions. Additionally, a backup relief valve is provided. This relief valve has been sized to provide reasonable assurance that the design pressure in the low-pressure section is not exceeded.

The direction of the pressurization of the charging line, on the other hand, is opposite to the flow. The charging line has three check valves in series to prevent overpressurization of the CVCS. It is unlikely that three check valves would fail simultaneously with both the charging pump and ACP stopped. However, the pressure indicator upstream of the charging pumps is installed.

In addition, relief valves are provided in the volume control tank (VCT) discharge line, charging pump miniflow line, charging pump discharge line, and ACP discharge line.

Increasing the complexity of all of the low-pressure systems interfacing with the CVCS upstream of the charging pumps to mitigate an event such as an ISLOCA is therefore impractical. Based on these observations, the design response shown in Figure 5A-14 is considered the preferred approach for this class of ISLOCAs.

An evaluation was also conducted to assess the impact of this design change to the Technical Specifications, PSA, and EOGs. It was determined that additional Technical Specifications are not required and that the selected design response does not affect the PSA or EOGs.

5A.4.6 Reactor Coolant Pump Seal Injection Line 5A.4.6.1 Description of Interface The seal injection line is directly connected to the RCS and is a primary interface through which an ISLOCA event can begin. Pressurization is postulated (1) from the charging 5A-17 Rev. 2

APR1400 DCD TIER 2 nozzle through the shellside of the regenerative HX to the seal injection line and (2) from the RCP seals through the tubeside of the high-pressure seal cooler to the discharge side of the charging pump. Once pressurized, other low-pressure interfacing systems are susceptible. This process also assumes that the charging pump and the ACP are not operating. Figure 5A-5 shows the various pathways ISLOCAs in this class can take and the systems it would affect assuming all downstream interfacing valves are open. This section addresses the seal injection line and the interfaces to the CVCS. The seal injection interface with the atmosphere is described in Subsection 5A.4.9.5.

5A.4.6.2 Design Evaluation The evaluation of the RCP seal injection line design resulted in a determination that no design improvements for an ISLOCA are required. The sections that are susceptible to an ISLOCA are the vent and drain lines from the filters. Figure 5A-15 shows the design response for this class of ISLOCAs.

The design pressure of the seal injection line is 212.7 kg/cm2G (3,025 psig), which satisfies the ISLOCA acceptance criteria. However, the design pressure for the filter vent and drain lines is 1.4 kg/cm2G (20 psig) in order to be compatible with the equipment drain header and the equipment drain tank (EDT). It is considered impractical and unnecessary to increase the design pressure of the EDT, as described in Subsection 5A.4.4.

The design response protects the interfacing systems from an ISLOCA without adversely affecting performance or operations. This design response satisfies the ISLOCA acceptance criteria for the seal injection line. It is considered acceptable since the flow rate would be low, would not cause a rapid fill of the EDT, and would allow sufficient time for operator action to terminate the event. The EDT is provided with pressure, level, and temperature instrumentation that indicates and alarms in the MCR. Thus, the design of the seal injection line satisfies the requirements in the NRC Letter by providing:

a. A high EDT pressure alarm in the control room to warn the operators of the event

b. Containment isolation valve position indication and control in the control room

c. Periodic leak testing of the containment isolation valves In addition, the failure of the vent and drain lines is immediately detected by loss or a reduction of the RCP seal injection flow because of flow diversion through the vent or drain 5A-18 Rev. 2

APR1400 DCD TIER 2 line. The leak tightness of the filter vent and drain valves is confirmed during normal operation because seal injection pressure is normally 185.0 kg/cm2 G (2,630 psig).

5A.4.7 Reactor Coolant Pump Controlled Bleedoff Line 5A.4.7.1 Description of Interface The controlled bleedoff line is directly connected to the RCS and is a primary interface through which an ISLOCA event can begin. Pressurization is postulated from the RCP seals through a flow-limiting orifice and a flow meter out of containment to the charging pump MFHX or VCT. Once pressurized, other low-pressure interfacing systems are susceptible. Figure 5A-6 shows the various pathways ISLOCAs in this class can take and the systems it would affect assuming all downstream interfacing valves are open. This section addresses the controlled bleedoff line and the interfaces to the CVCS. The controlled bleedoff with the atmosphere is described in Subsection 5A.4.9.5.

5A.4.7.2 Design Evaluation Change The evaluation of the RCP controlled bleedoff line resulted in a determination that no design improvements are required for an ISLOCA. Figure 5A-16 shows the design response for this class of ISLOCAs. The design provides a pressure rating of 174.7 kg/cm2G (2,485 psig) to the outermost section of the system that could be pressurized.

The design pressure for the controlled bleedoff system is divided into high- and low-pressure sections. The high pressure, 174.7 kg/cm2G (2,485 psig), exceeds the minimum design pressure requirement for an ISLOCA, as provided in SECY-90-016. The low-pressure section outside containment is designed to 5.3 kg/cm2G (75 psig) and 14.1 kg/cm2G (200 psig) to be compatible with the design pressure of the VCT and charging pump MFHX, respectively.

The low-pressure section of the RCP controlled bleedoff line meets the ISLOCA requirements since there is no plausible scenario in which this line could be pressurized above its design pressure. The upstream pressure is limited by a fixed-resistance flow control orifice, and the only means of isolating the flow in the low-pressure section requires isolation of the VCT and charging pump MFHX inlet, which are already protected from overpressurization by relief valves. The relief valves discharge to the EDT. The flow through the controlled bleedoff line during normal operation is 48.5 L/min (12.8 gpm),

5A-19 Rev. 2

APR1400 DCD TIER 2 which is within the makeup capability and can be collected in the reactor drain tank (RDT) for more than 30 minutes before requiring operator action. Furthermore, the VCT and EDT are provided with an indication and alarm for liquid level, temperature, and pressure. The indication and alarm serve to alert the operator in conjunction with the indication of the RCP controlled bleedoff line pressure of any pressurization occurrence.

5A.4.8 Sampling System 5A.4.8.1 Hot Leg Sampling 5A.4.8.1.1 Description of Interface The SS has a direct connection to the RCS hot leg, which results in a primary interface through which an ISLOCA can begin. Pressurization is postulated from the sampling nozzle on the hot leg through the containment isolation valves and out of containment to the low-pressure sections of the system. Figure 5A-7 shows the various pathways an ISLOCA in this class can take and the interfacing systems it would affect. All other interfaces are resolved by resolving the direct interface to the RCS.

5A.4.8.1.2 Design Evaluation The design of the hot leg sampling line provides a fixed-resistance orifice and a small line size that limits the flow and pressure during all modes of plant operation. This line discharges to the VCT, which is already protected from overpressurization by a relief valve.

The relief valve discharges to the EDT.

The only means of isolating the flow in the low-pressure section requires isolating the discharge to the VCT and the recycle drain header and opening the containment isolation valves. For this event, a relief valve has been added to provide protection for the system.

The relief valve is sized to pass a flow rate that is equivalent to the hot leg sample line flow rate prior to sample collection. With this flow rate, the flow control orifice upstream of the pressure relief valve creates a pressure drop that limits the pressure in the system to an acceptable value. This flow rate is limited to within makeup capability. Furthermore, the EDT is provided with indication and alarm for liquid level, temperature, and pressure to alert the operator, in conjunction with the indication of the containment isolation valve (CIV) position, with sufficient time for operator action to terminate the event. Figure 5A-17 shows the design response for this class of ISLOCAs.

5A-20 Rev. 2

APR1400 DCD TIER 2 There is no impact to the SS as a result of this design response. Leakage from the relief valve is detected in the EDT and appropriate operator action is taken to terminate the event.

In addition, none of the changes affect the PSA or EOGs for this event.

5A.4.8.2 Pressurizer Surge Line Sampling 5A.4.8.2.1 Description of Interface The SS has a direct connection to the pressurizer surge line, which results in a primary interface through which an ISLOCA can begin. Pressurization is postulated from the sampling nozzle on the surge line through the containment isolation valves and out of containment to the low-pressure sections of the system. Figure 5A-8 shows the various pathways an ISLOCA in this class can take and the interfacing systems it would affect.

This subsection addresses the pressurizer surge line interface. By resolving the direct interface to the RCS, all other interfaces are resolved.

5A.4.8.2.2 Design Evaluation The design of the SS for the pressurizer surge line provides a fixed-resistance orifice and a small line size that limits the flow and pressure during all modes of plant operation. This line discharges to the VCT, which is already protected from overpressurization by a relief valve. The relief valve discharges to the EDT.

The only means of isolating the flow in the low-pressure section requires isolating the discharge to the VCT and the recycle drain header and opening the containment isolation valves. For this event, a relief valve has been added to provide protection for the system.

The relief valve is sized to pass a flow rate that is equivalent to the pressurizer surge line flow rate prior to sample collection. With this flow rate, the flow control orifice upstream of the pressure relief valve creates a pressure drop that limits the pressure in the system to an acceptable value. This flow rate is limited to within makeup capability. Furthermore, the EDT is provided with indication and alarm for liquid level, temperature, and pressure to alert the operator, in conjunction with the indication of the CIV position, with sufficient time for operator action to terminate the event. Figure 5A-18 shows the design response for this class of ISLOCAs.

There is no impact to the SS as a result of this design response. Leakage from the relief valve is detected in the EDT, and appropriate operator action is taken to terminate the event. In addition, none of the changes affect the PSA or EOGs for this event.

5A-21 Rev. 2

APR1400 DCD TIER 2 5A.4.8.3 Pressurizer Steam Space Sampling 5A.4.8.3.1 Description of Interface The SS has a direct connection to the pressurizer steam space, which results in a primary interface through which an ISLOCA can begin. Pressurization is postulated from the sampling nozzle on the pressurizer steam space through the containment isolation valves and out of containment to the low-pressure sections of the system. Figure 5A-9 shows the various pathways an ISLOCA in this class can take and the interfacing systems it would affect. This section addresses the pressurizer steam space interface. By resolving the direct interface to the RCS, all other interfaces are resolved.

5A.4.8.3.2 Design Evaluation The design of the sampling system for the pressurizer steam space provides a fixed-resistance orifice and a small line size that limits the flow and pressure during all modes of plant operation. This line discharges to the VCT, which is already protected from overpressurization by a relief valve. The relief valve discharges to the EDT.

The only means of isolating the flow in the low-pressure section requires isolating the discharge to the VCT and the recycle drain header and opening of the containment isolation valves. For this event, a relief valve has been added to provide protection for the system.

The relief valve is sized to pass a flow rate that is equivalent to the pressurizer steam space sample line flow rate prior to sample collection. With this flow rate, the flow control orifice upstream of the pressure relief valve creates a pressure drop that limits the pressure in the system to an acceptable value. This flow rate is limited to within makeup capability.

Furthermore, the EDT is provided with indication and alarm for liquid level, temperature, and pressure to alert the operator, in conjunction with the indication of the CIV position, with sufficient time for operator action to terminate the event. Figure 5A-19 shows the design response for this class of ISLOCAs. There is no impact to the SS as a result of this design response. Leakage from the relief valve is detected in the EDT, and appropriate operator action is taken to terminate the event. In addition, none of the changes affect the PSA or EOGs for this event.

5A-22 Rev. 2

APR1400 DCD TIER 2 5A.4.9 Component Design Responses 5A.4.9.1 Flanges 5A.4.9.1.1 Description of Interface For the systems that may be subjected to an ISLOCA event, all gasketed flange connections represent a possible leakage pathway leading to the atmosphere. This pathway is applicable only in the systems for which designing to 40 percent of RCS operating pressure is chosen; other systems that are isolated from the RCS because of alternative design responses (such as those described in Subsections 5A.4.4 and 5A.4.5) are not pressurized to full RCS pressure. Flanged connections in the former case therefore have a minimum pressure rating of 40 percent of RCS operating pressure or 63.3 kg/cm2G (900 psig). This section addresses the gasketed flanged connections in the systems that may be subjected to full RCS pressure.

5A.4.9.1.2 Design Evaluation The flanges that may be subjected to full RCS pressure are located in systems designed to 63.3 kg/cm2G (900 psig) (40 percent of RCS operating pressure). These flanges are designed to a minimum of Class 600 of ANSI B16.5 (Reference 5).

All bolting for flanges meet or exceed SA193 GR B7, SA-193 GR B8, or SA-540 B23 allowable stress limits. These material specifications provide for higher preloading stress than used in the NUREG/CR-5603 analysis and therefore increase the maximum allowable pressure without leakage.

All systems with design conditions requiring flanges with a rating higher than Class 600 satisfy the ISLOCA acceptance criteria because the pressure at which these flanges are tested(1) is greater than RCS operating pressure.

ANSI B16.5 requires that Class 600 flanges meet, at a minimum, the design conditions of 66.1 kg/cm2G (940 psig) at 204.4 °C (400 °F). NUREG/CR-5603 presents an analysis to determine the leakage rate from the gasketed flange connections from pressurization for (1)

Per ANSI B16.5, flanged joints and flanged fittings may be subjected to system hydrostatic tests at a pressure not to exceed 1.5 times the 38 °C (100 °F) rating rounded off to the next higher 1.76 kg/cm2D (25 psid) increment.

5A-23 Rev. 2

APR1400 DCD TIER 2 existing power plant designs. The calculated leak rate at the gross leak pressure(2) is 1 to 2 mg/sec or approximately 3.6 to 7.2 cc/hr. This leakage rate is considered acceptable for beyond design basis events. In addition, NUREG/CR-5603 states that the Gross Leak Pressures for all sizes of Class 600 rated flanges are very high and greater than the range of interest. Thus, Class 600 flanges are not expected to leak when subject to pressures as high as the Reactor Coolant System operating pressure.

NUREG/CR-5603 indicates that the leak rate from a flanged joint is dependent, in part, on the preloading on the gasket. The flange bolts used in the NUREG/CR-5603 study were SA-193 GR B8, which, for a Class 600 flange, caused the bolts to be stressed beyond their yield point. The bolts in the APR1400 design are SA-193 GR B7, SA-193 GR B8, or SA-540 B23, which will allow for higher preloading stresses and therefore increase the maximum allowable pressure without leakage.

The hydrostatic test pressure for all classes of flanges above Class 600 is at least 189.8 kg/cm2G (2,700 psig), which exceeds the normal RCS operating pressure and therefore meets the ISLOCA acceptance criteria.

5A.4.9.2 Valves 5A.4.9.2.1 Description of Interface For systems that may be subjected to full RCS pressure, all valves represent a possible leakage pathway leading to an ISLOCA event. This pathway is applicable only in the systems for which designing to 40 percent of RCS operating pressure is chosen; other systems that are isolated from the RCS because of alternative design responses (such as those described in Subsections 5A.4.4 and 5A.4.5) are not pressurized to full RCS pressure.

Valves in the former case therefore have a minimum pressure rating of 40 percent of RCS operating pressure or 63.3 kg/cm2G (900 psig). This section addresses valves in the systems that may be subjected to full RCS pressure.

(2)

Gross leak pressure is defined as the system pressure that produce stresses on the bolts equal to the preload stresses. For the Class 600 flanges, this pressure is between 223.8 kg/cm2G (3,183 psig) and 498.1 kg/cm2G (7,085 psig), depending on the size of the flange.

5A-24 Rev. 2

APR1400 DCD TIER 2 5A.4.9.2.2 Design Evaluation Valves that may be subjected to full RCS pressure are located in systems designed to 63.3 kg/cm2G (900 psig) (40 percent of normal RCS operating pressure). According to the ANSI Standard, ANSI B16.34 (Reference 6), all valves in 63.3 kg/cm2G (900 psig) systems must be at least Class 600 valves. The requirements in this standard indicate that a Class 600 valve will maintain system integrity in the event the system is pressurized to 158.2 kg/cm2G (2,250 psig), normal RCS operating pressure.

All systems with design conditions requiring valves of a rating higher than Class 600 satisfy the ISLOCA acceptance criteria because the pressure at which these valves are tested is greater than RCS operating pressure.

ANSI B16.34 requires the use of at least Class 600 stainless steel valves to meet the design conditions of 63.3 kg/cm2G (900 psig) at 204.4 °C (400 °F). The actual allowable working pressure for the Class 600 valve is 72.4 kg/cm2G (1,030 psig), which exceeds the 63.3 kg/cm2G (900 psig) (40 percent of RCS operation pressure) design criteria for systems exposed to RCS pressure. The working pressure is considered adequate to provide reasonable assurance that the structural integrity of the valves is maintained when pressurized to 158.2 kg/cm2G (2,250 psig), normal RCS operating pressure.

The evaluation presented in NUREG/CR-5603 supports this observation. NUREG/

CR-5603 states that failure of the adjacent piping will occur prior to the failure of the valve body and the types of valve stem packings currently used in most nuclear plants tends to compress under high-pressure conditions providing greater resistance to leakage. Thus, according to NUREG/CR-5603, the only concern with respect to failure of valves subject to normal RCS operating pressures is the integrity of the valve bonnet seal.

The integrity of the valve bonnet seal is proven during the valve body hydrostatic testing.

The hydrostatic test pressure for all classes of valves higher than Class 600 have a design operating condition of at least 151.9 kg/cm2G (2,160 psig) at 38 °C (100 °F) of test temperature. For a Class 900 valve, the hydrostatic test is performed at 228.5 kg/cm2G (3,250 psig), which is well above RCS operating pressure., and shows that any valve with a rating higher than Class 600 meets the ISLOCA acceptance criteria.

5A-25 Rev. 2

APR1400 DCD TIER 2 5A.4.9.3 Pump Seals 5A.4.9.3.1 Description of Interface For the systems that may be subjected to full RCS pressure, all pump seals represent a possible leakage pathway leading to an ISLOCA event. This pathway is applicable only in systems for which designing to 40 percent of normal RCS operating pressure is chosen; other systems that are isolated from the RCS because of alternative design responses (such as those described in Subsections 5A.4.4 and 5A.4.5) are not pressurized to full RCS pressure. This section addresses the pump seals in the systems that may be subject to full RCS pressure.

5A.4.9.3.2 Design Evaluation The pumps of interest for an ISLOCA event are the SCP, safety injection pumps (SIP), the CSP, and charging pumps. These pumps are centrifugal and are located in systems that are designed to at least 63.3 kg/cm2G (900 psig) or 40 percent of RCS operating pressure. The design pressure of the CSPs and SCPs is 63.3 kg/cm2G (900 psig), the design pressure of the SIPs is 144.1 kg/cm2G (2,050 psig), and the design pressure of the charging pumps is 225.0 kg/cm2G (3,200 psig). Because the hydrostatic test pressure of SIPs is above the normal RCS operating pressure, the pump seals are not expected to leak and the ISLOCA acceptance criteria are met. The hydrostatic test pressure of CSPs and SCPs is approximately 79 kg/cm2G (1,125 psig). NUREG/CR-5603 indicates that the nominal leak rate through the pump seals can be predicted to be 100~200 mg/sec (360~720 cc/hr) with an uncertainty variability of approximately 0.20. This leakage rate is within the makeup capability of the charging pumps and therefore meets the ISLOCA acceptance criteria.

NUREG/CR-5603 indicates that failure of pumps is related to leakage through the spring-loaded mechanical shaft seals. In this study, the mechanical seals for the subject pumps were designed to withstand a pressure of 84.37 kg/cm2G (1,200 psig) to 87.9 kg/cm2G (1,250 psig) without leaking. For greater pressures, the leakage was limited to 100~200 mg/sec (360~720 cc/hr) with an uncertainty variability of 20 percent.

The seal design of the APR1400 pumps for the systems that may be exposed to normal RCS operating pressure is expected to yield similar results. With a nominal leak rate of 100~200 mg/sec (360~720 cc/hr), the ISLOCA acceptance criteria are met due to the fact that the charging capability can make up the lost inventory. In the APR1400 design, the 5A-26 Rev. 2

APR1400 DCD TIER 2 SCP and CSP design pressure is increased to 63.3 kg/cm2G (900 psig), which allows for a higher pressure before seal leakage.

5A.4.9.4 Heat Exchangers 5A.4.9.4.1 Description of Interface A number of systems that interface with the RCS contain HXs as an integral part of the system design. The postulated rupture of a HX tube provides a pressurization pathway for an ISLOCA event. This section addresses HXs located in systems that may be exposed to full RCS pressure.

5A.4.9.4.2 Design Evaluation The HXs located in systems that interface with the RCS are designed to at least 40 percent (63.3 kg/cm2G (900 psig)) of full RCS pressure. The HXs that are in operation during Mode 1 are designed to pressures greater than RCS operating pressure except for the charging pump MFHX.

The preliminary design pressures for the HXs that directly connect to the RCS satisfy the ISLOCA acceptance criteria. These HXs and their design pressures are listed in Table 5A-4.

The rationale for excluding a HX tube rupture as an ISLOCA pathway is based on the following factors:

a. Heat exchanger design - the design rating of the HXs is at least 63.3 kg/cm2G (900 psig) except for the charging pump MFHX

b. Tube rupture size - the diameter of the HX tubing is small (no larger than19.1 mm

[3/4 in]), thereby limiting the total loss of inventory in the event of a tube rupture

c. Offsite dose limits - the offsite doses due to a HX tube rupture do not challenge the acceptance criteria for an ISLOCA

d. Event detection - the detection of the event is provided in the MCR to give the operator with ample time to secure the affected HX

e. HX isolation - the isolation capability of the affected HX is provided in the MCR 5A-27 Rev. 2

APR1400 DCD TIER 2 Heat Exchanger Design The design of the HXs takes into account several parameters that provide reasonable assurance of maximum protection against tube failure. The selection of the parameters is based on a consideration of normal and abnormal operating conditions, including ISLOCAs. The following summarizes the key considerations for HX sizing as applicable to the ISLOCA concerns:

a. The chemistry of the fluid is closely controlled on both sides of the HXs so that there are no significant changes in impurity levels. In addition, the HXs are designed to preclude the potential for impurity concentration within the HX, such as would occur with fluid boiling at the tube-to-coolant interface. These characteristics are consistent with long-term trouble-free operation.

b. Flow rates and pressure losses are established to retain single-phase flow throughout the HXs to minimize the potential for erosion and maximize component life.

c. The pressure-retaining parts of the HXs are based on simple geometry, which enhances the ability to properly size the component and provide reasonable assurance of a high level of confidence in the design. All HX parts are either flat plates or tubes without any configurations that would produce excessive local stress concentrations. In addition, the ISLOCA acceptance criterion (40 percent of RCS normal operating pressure) that is applied to system piping is also applicable to the tubes inside the HX except charging pump MFHX.

d. The wall thickness of the HX tubes is specified in accordance with Tubular Exchanger Manufacturers Association (TEMA) Standards. These standards are more conservative than ASME Code requirements. Therefore, the tubes are specified with a greater design wall thickness than required. As an example, the shutdown cooling HX tubing can withstand approximately 33 percent greater design pressure than is required by the ASME Code. This margin in HX tubing is typical of the HXs shown in Table 5A-4.

The pressure-retaining parts of the HXs that are required to be in service during normal operation (i.e., Mode 1) are designed to the same pressure as the attached piping. This pressure is in excess of normal RCS operation pressure except for the charging pump MFHX. Furthermore, the HXs are tested to 125 percent of their design pressure, which 5A-28 Rev. 2

APR1400 DCD TIER 2 provides additional reasonable assurance that the HX tubes can maintain system integrity.

This position is consistent with the results of NUREG/CR-5603, excluding high-pressure HXs, as a potential for ISLOCA. This position is also consistent with the NRC position for valves in NUREG/CR-5102 that the valve design is acceptable if tested to a pressure in excess of normal operating pressure.

The letdown HX is an example of a high-pressure design HX. The design pressure of the letdown HX for the APR1400 design is 174.7 kg/cm2G (2,485 psig). Therefore, in accordance with NUREG/CR-5603, the design is acceptable for ISLOCA. All design conditions presented above (i.e., chemistry control, single-phase flow, and TEMA sizing requirements) are incorporated in the letdown HX.

The charging pump MFHX design pressure is 14.1 kg/cm2G (200 psig), which is based on the approaches similar to those in Subsection 5A.4.5. In addition, a backup relief valve is provided in the charging pump miniflow line.

HXs that can be aligned to the RCS but are isolated from the RCS during Modes 1, 2 and 3 satisfy the ISLOCA acceptance criteria based on their design pressure of 40 percent of RCS operating pressure. The SCS HX is an example of a low-pressure design HX normally isolated from the RCS. The design pressure of the SCS HX is 63.3 kg/cm2G (900 psig).

This is consistent with the NRC position on piping as presented in NUREG/CR-5102. All design conditions presented above (i.e., chemistry control, single-phase flow, and TEMA sizing requirements) are incorporated in the SCS HXs.

The normal operating pressure for the SCS HX is between approximately 7.0 kg/cm2G (100 psig) and 31.6 kg/cm2G (450 psig) and is only in use during shutdown conditions.

These conditions do not challenge the design conditions (63.3 kg/cm2G [900 psig] at 204.4 °C [400°F]) of the HX. The HXs are designed for more robust conditions than required for their normal use. Therefore, they have the margin to provide reasonable assurance of integrity.

The design requirements for the CSS are to provide containment pressure control following a design basis event. Because the CSS is also designed to back up the SCS, the HX design must include the same conditions as the SCS HX. Therefore, the normal operating pressure for the CSS HX must be considered to be between approximately 7.0 kg/cm2G (100 psig) and 31.6 kg/cm2G (450 psig).

5A-29 Rev. 2

APR1400 DCD TIER 2 These conditions, as with the SCS, do not challenge the design conditions (63.3 kg/cm2G

[900 psig] at 204.4 °C [400°F]) of the HX. The HXs are designed for more robust conditions than required for their normal use. Therefore, they inherently have margin to provide reasonable assurance of integrity.

Based on these observations, postulating a HX tube rupture as part of the ISLOCA evaluation is not considered necessary.

Tube Rupture Size The ISLOCA pathway through an HX is limited by the diameter of a tube based on a double-ended guillotine break. Table 5A-4 provides the best estimate for the tube diameter of the HXs that is potentially subjected to operating RCS pressure. Since these diameters are all much less than the letdown line diameter, the consequences of an HX tube rupture is bounded by the consequences of a letdown line break. This implies that RCS inventory is easily controlled by the makeup systems capability.

As an example, the letdown HX tube is 15.9 mm (5/8 in.) in diameter and the letdown line is 50.8 mm (2 in.) in diameter, more than a factor of 3 larger. Mass flow rate out of a break is proportional to the square of the diameter, which implies that, for the same pressure drop across the break, the mass flow rate out of a letdown line break is more than 10 times larger than the flow rate out of a HX tube rupture. The safety analysis in Subsection 15.6.2 considers letdown line breaks that clearly bound the consequences of HX tube ruptures.

Offsite Dose Limits The ISLOCA acceptance criteria for offsite dose limits are bounded by the leakage rate and total discharge of the postulated letdown line break presented in Subsection 15.6.2.

Assuming that all leakage from a tube rupture is discharged directly to the auxiliary building instead of the secondary system, a HX rupture still satisfies the ISLOCA acceptance criteria since the tube diameters are all less than the letdown line diameter.

Event Detection The various means to detect a tube rupture in HXs include pressure, temperature, flow, liquid level, valve position indication, and radiation indications and alarms. All of these 5A-30 Rev. 2

APR1400 DCD TIER 2 methods are provided in the MCR. Examples of the method of detection are presented in the following subsections on high- and low-pressure HXs.

Heat Exchanger Isolation All HXs except for the charging pump MFHX can be isolated from the MCR with equipment designed to operate under the worst-case flow and pressure.

Detection and isolation of the affected HX are provided, going beyond the credited acceptance criteria for ISLOCA and assuming a failure of a letdown HX tube. The detection and isolation are provided to protect the component cooling water system (CCWS) and all system interfaces off the CCWS.

The CCWS is a closed system whose only interface with the RCS is through other systems HXs. The major components of the system are the pumps, HXs, relief valves, and surge tanks. Of these components, the surge tank and relief valves at each of the HXs listed in Table 5A-4 provide the necessary protection for an ISLOCA. The surge tank provides a reservoir of water for the expansion and contraction of the component cooling water (CCW) due to thermal effects and leakage and provides a reservoir for dampening pressure transients. These capabilities allow the system to accommodate mass additions without pressurization. The relief valves, located in the outlet line from each HX, provide additional thermal and mass addition relief protection. Further, since all HXs have a relief valve, the combined effect provides redundant protection.

Example of a High-Pressure Heat Exchanger The letdown HX is subjected to full RCS pressure and designed to a pressure in excess of RCS operating pressure. A postulated letdown HX tube rupture during high RCS pressure opens a pathway to the CCW. The result of this ISLOCA event is mitigated by the CCWS relief valve for the letdown HX. The mass flow rate through the postulated break is discharged through the CCW/letdown HXs relief valve to the sump in containment. Since the event is totally within containment and the CCW system is protected from overpressurization, the ISLOCA acceptance criteria are satisfied. Isolation of a letdown HX tube rupture is provided by the RCS PIVs in the letdown line.

5A-31 Rev. 2

APR1400 DCD TIER 2 Example of a Low-Pressure Heat Exchanger The shutdown cooling HX is aligned to the RCS but is only subjected to RCS pressure during low-pressure operation. Therefore, it is designed to 63.3 kg/cm2G (900 psig) in accordance with the NRC position presented in the NRC Letter. However, if the system is misaligned during high RCS pressure and a tube is postulated to rupture, a pathway to the CCWS would be provided. For this ISLOCA event, the CCWS integrity is maintained, as with the letdown HX ISLOCA event since the mass flow rate added to the CCWS would be discharged through the CCW/SCS HXs relief valve to the respective sump.

Detection for a SCS HX tube rupture is provided by the instrumentation of the SCS, CCW, and local area monitors throughout the plant. Subsection 5A.5 provides a general overview of the instrumentation provided in the primary systems necessary to detect an ISLOCA.

The following details the indication and alarms provided in the MCR for a SCS HX tube rupture.

Prior to a SCS HX tube rupture, the operator is alerted to a pressurization event from either the return line or supply line (Figure 5A-1) through indication and alarms in the MCR. The return line requires three normally locked closed valves (that have the power removed from their motor operator) to open. These valves all have position indication in the MCR and alarm if they are not fully closed concurrent with high RCS pressure.

Furthermore, the RCS low-temperature overpressure protection (LTOP) relief provides another source of overpressure protection since these valves open at 38.32 kg/cm2A (545 psia) after the first two SCS isolation valves open and discharge to the IRWST within containment. Although the design criteria for the LTOP valves are to protect the RCS during a low-temperature transient, they are operable under this scenario and assist in mitigating the severity of a postulated tube rupture.

From the supply line, four check valves in series would have to fail and two normally closed isolation valves would have to open. Indication and alarm are provided in this pathway through continuous monitoring of the SCS pressure upstream of the DVI check valve. The intent is to monitor the integrity of the DVI check valve during plant operation.

For normal pressurization, the operating requirements provide the necessary instructions for relieving pressure to the RDT, within containment, upon high pressure of 70.3 kg/cm2G (1,000 psig) or the alarm setpoint. The two isolation valves in this line have position indication in the MCR.

5A-32 Rev. 2

APR1400 DCD TIER 2 The CCWS is protected from overpressurization by a relief valve at each HX, as described above. Therefore, the instrumentation provided in the control room is intended for monitoring the impact on the entire system. The instrumentation includes a radiation monitor in each train of the CCWS, level indication in each surge tank, CCW pump differential and discharge pressure, and CCW system temperature.

Finally, area radiation alarm provides immediate identification of an event. Chapter 12 describes such radiation monitors and their use.

Isolation of the SCS HX is performed from the MCR by closing any of the valves in the SCS supply and return lines. Since all of the SCS outside containment are designed to 40 percent of the RCS operating pressure in accordance with the NRC position in the NRC Letter, the ISLOCA acceptance criteria are met. Based on the primary side systems design pressure, pressure isolation provisions, indications, alarms, and relief protection provided in the plant, the design pressure of the shellside of the SCS HX and all other low design pressure HXs need not be set at 63.3 kg/cm2 G (900 psig) solely for tube rupture isolation.

5A.4.9.4.3 RCP High-Pressure Seal Cooler The RCP high-pressure seal cooler tubeside in the APR1400 design is the same as the design pressure of the RCS. A description of the overpressure protection provided in the component cooling water system is provided in Subsection 9.2.2.

5A.4.9.5 Vents, Drains, and Local Samples 5A.4.9.5.1 Description of Interface Various systems that interface directly or indirectly with the RCS have vents and drains that provide a potential pathway for an ISLOCA event. These vents and drains are necessary for thermal and pressure relief, for venting and draining operations, and for the collection of samples from local sections in the systems. This section addresses vents, drains, and local sample connections in the systems that may be subjected to full RCS pressure.

5A.4.9.5.2 Design Evaluation For the systems that may be subjected to normal RCS operating pressure, all vents and drains represent a possible leakage pathway leading to an ISLOCA event. This pathway is applicable only in the systems for which designing to 40 percent of normal RCS operating pressure is chosen; other systems that are isolated from the RCS because of alternative 5A-33 Rev. 2

APR1400 DCD TIER 2 design responses (such as those described in Subsections 5A.4.4 and 5A.4.5) are not pressurized to full RCS pressure.

The APR1400 design provides an isolation capability against pressures equal to or greater than 158.2 kg/cm2G (2,250 psig) or RCS normal operating pressure.

The justification of this design response is based on recognizing that:

a. All vent and drain lines are of a sufficiently small diameter that discharge flow rates are limited(3)

b. The discharge flow rates and the resulting offsite doses are bounded by the results described in Chapter 15.

All system vents and drains are directed to a collecting tank either directly to the EDT or to the liquid waste management system (LWMS) through sump drains to allow sufficient time for operator response because of the limited flow rates characterizing these events and the size of the collecting tank. Furthermore, local radiation monitors alert the operator of an event.

Unlike discharges to tanks, discharges to the atmosphere are not characterized by collection or pressure containment capabilities. Therefore, it is considered sufficient, in view of the practical limitations of such interfaces, to design these interfaces with isolation capabilities to withstand normal RCS operating pressure without unacceptable leakage. The design of normally closed isolation valves conforms to the requirements described in Subsection 5A.4.9.2.

(3)

Assuming all isolation valves are open 5A-34 Rev. 2

APR1400 DCD TIER 2 5A.5 Detection of ISLOCA Section 5A.4 describes the various ISLOCA events that have been postulated to occur in the APR1400 design. The design responses implemented for all of these events meet the ISLOCA acceptance criteria described in Subsection 5A.3.2. In particular, these design responses provide reasonable assurance that the structural integrity of systems is maintained and that any leakages are limited to a small fraction of makeup capabilities. In general, the design responses described in Subsection 5A.4 are intended to prevent ISLOCAs from occurring.

Based on the evaluation presented in Subsection 5A.4, the ISLOCA detection capability emphasizes the detection of ISLOCA precursors (i.e., primarily events that pressurize a system) since ISLOCA events (i.e., events characterized by the actual loss of coolant outside containment) are limited to very small leakages. The detection of ISLOCA events relies on the ability to detect relatively small flow rates of reactor coolant, such as leakages within a system (e.g., through valves) or to atmosphere (e.g., through seals and valve packings).

As a result, the following instrumentation types were reviewed to provide reasonable assurance of their inclusion in the MCR:

a. Valve position indication

b. Pressure indication

c. Tank level indication

d. Radiation monitoring 5A.5.1 Valve Position Indication In accordance with the ISLOCA definition provided in Subsection 5A.3.1, ISLOCA precursors can occur because of the inadvertent opening of valves, failure of containment isolation, or the postulation that valves are fully opened. In any case, information in the MCR concerning the position of valves appears to be critical to detecting such precursor events. This observation is consistent with SECY-90-016 and SECY-93-087 (Reference 8),

which require that valve position indication be available in the MCR when CIV operators are de-energized. Table 5A-5 identifies all CIVs and their indication capabilities for the systems and subsystems for which ISLOCAs have been identified to potentially begin.

5A-35 Rev. 2

APR1400 DCD TIER 2 Table 5A-5 shows that all valves that could initiate an ISLOCA precursor have appropriate valve position indication in the MCR with which operators can detect any misalignment.

5A.5.2 Pressure Indication ISLOCA precursor events can be characterized by leakages (i.e., relatively small flow rates) through valves within systems. Such events can result in the pressurization of a lower-pressure system. Table 5A-6 identifies pressure indication in the MCR for the regions of systems and subsystems described in Section 5A.4 that are susceptible to such precursor events. These pressure indicators allow operators to detect pressurization events that are caused by leakages too small to be measured reliably using existing equipment.

5A.5.3 Tank Level Indication ISLOCA precursor events can also be characterized by leakages to tanks (e.g., through vents and drains to the EDT). Such events result in overfilling of the tanks with associated overpressurization. Table 5A-7 identifies the level indication in the MCR for all of the tanks described in Section 5A.4 that would collect leakages during such precursor events.

These level indicators allow operators to detect tank filling and with the design changes described in Section 5A.4, allow the operator time to determine the source of the leakage.

5A.5.4 Radiation Monitoring ISLOCA events can be characterized by leakages from systems to the atmosphere, such as through valve packings and pump seals, or by misaligned vent or drain valves. Because the flow rates involved can be too small to detect reliably using existing instrumentation and because the sources of such leakages are too many and distributed widely throughout the plant, it is concluded that leakages of this type can be detected most effectively with radiation area monitors throughout the plant. Chapter 12 discusses such radiation monitors and their use.

5A-36 Rev. 2

APR1400 DCD TIER 2 5A.6 References

1. Information Notice 92-36, Intersystem LOCA Outside Containment, U.S. Nuclear Regulatory Commission, May 7, 1992.

2. NRC Letter, Preliminary Evaluation of the Resolution of the Intersystem Loss-of-Coolant-Accident (ISLOCA) Issue for the Advanced Boiling Water Reactor (ABWR)

- Design Pressure for Low Pressure Systems, Docket Number 52-001.

3. NUREG/CR-5603, Pressure-Dependent Fragilities for Piping Components: Pilot Study on Davis-Besse Nuclear Power Station, U.S. Nuclear Regulatory Commission, October 1990.

4. SECY-90-016, Evolutionary Light Water Reactor (LWR) Certification Issues and Their Relationship to Current Regulatory Requirement, U.S. Nuclear Regulatory Commission, January 12, 1990.

5. ANSI B16.5, Pipe Flanges and Flanged Fittings, American National Standards Institute, 2009.

6 ANSI B16.34, Steel Valves, American National Standards Institute, 2009.

7 NUREG/CR-5102, Interfacing Systems LOCA: Pressurized Water Reactors, U.S.

Nuclear Regulatory Commission, February 1989.

8 SECY-93-087, Policy, Technical, and Licensing Issues Pertaining to Evolutionary and Advanced Light-Water Reactor Designs, U.S. Nuclear Regulatory Commission, April 2, 1993.

5A-37 Rev. 2

APR1400 DCD TIER 2 Table 5A-1 APR1400 ISLOCA Design Pressurization Pathway Design Figure Shutdown The design pressure for all sections outside containment is at least 5A-10 Cooling System 63.3 kg/cm2G (900 psig).

SIS Delivery The design pressure for all sections outside containment is at least 5A-11 Line 63.3 kg/cm2G (900 psig).

Containment All piping sections outside containment have been designed to 5A-12 Spray System 63.3 kg/cm2G (900 psig).

Connections to the refueling pool fill line in CSS IRWST return line have been relocated from the SCS return line and a spool piece has been included.

Letdown Line A high-pressure alarm has been installed downstream of the 5A-13 letdown control valves to initiate a manual isolation of the letdown line by the containment isolation valve when high pressure is sensed.

Charging Line A pressure sensor has been installed upstream of the charging 5A-14 pumps to initiate a manual isolation of the charging line by the containment isolation valve when high pressure is sensed.

Hot Leg A pressure relief valve has been added upstream of discharge 5A-17 Sampling isolation valves to VCT and recycle drain header.

Pressurizer A pressure relief valve has been added upstream of discharge 5A-18 Surge Line isolation valves to VCT and recycle drain header.

Sampling Pressurizer A pressure relief valve has been added upstream of discharge 5A-19 Steam Space isolation valves to VCT and recycle drain header.

Sampling 5A-38 Rev. 2

APR1400 DCD TIER 2 Table 5A-2 Systems Interfacing with the CVCS Downstream of the Letdown Control Valve Hydrogen Supply System Nitrogen Supply System Gaseous Waste Management System Solid Waste Management System Liquid Waste Management System Makeup/Boron Recovery System Sampling System 5A-39 Rev. 2

APR1400 DCD TIER 2 Table 5A-3 Low-Pressure Equipment of the CVCS Diameter, Height, Equipment Fabrication Location Volume Design Pressure 3

Boric Acid Field fabricated 946.0 m 0.11 kg/cm2G (1.5 psig)

Storage Tank (250,000 gal)

Volume Control 2,438.4 mm (8 ft) diameter 25.4 m3 Internal 5.3 kg/cm2G (75 psig)

Tank 5,852 mm (19.2 ft) high (6,700 gal) External 1.05 kg/cm2G (15 psig)

Equipment Drain 3,048.0 mm (10 ft) diameter 36.0 m3 Internal 2.1 kg/cm2G (30 psig)

Tank 5,486.0 mm (18 ft) long (9,500 gal) External 1.05 kg/cm2G (15 psig)

Boric Acid 1,524.0 mm (5 ft) diameter 2.38 m3 Atmospheric Batching Tank 914.4 m (3 ft) high (630 gal)

Holdup Tank Field fabricated 1,590.0 m3 0.11 kg/cm2G (1.5 psig)

(420,000 gal)

Reactor Makeup Field fabricated 1,495 m3 0.56 kg/cm2G (8 psig)

Water Tank (395,000 gal)

Purification Ion 1,066.8 mm (3.5 ft) diameter 1.6 m3 14.1 kg/cm2G (200 psig)

Exchangers 3,013.0 mm (9.9 ft) high (416.7 gal)

Deborating Ion 1,066.8 mm (3.5 ft) diameter 1.6 m3 14.1 kg/cm2G (200 psig)

Exchanger 3,013.0 mm (9.9 ft) high (416.7 gal)

Pre-Holdup Ion 1,066.8 mm (3.5 ft) diameter 1.6 m3 14.1 kg/cm2G (200 psig)

Exchanger 3,013.0 mm (9.9 ft) high (416.7 gal) 5A-40 Rev. 2

APR1400 DCD TIER 2 Table 5A-4 Heat Exchangers that may be Exposed to Full RCS Operating Pressure Tubeside Design Pressure, Typical Tube Heat Exchanger kg/cm2G (psig) OD, mm (in.)

Normally High Pressure Seal Cooler 212.7 (3,025) 9.5 (3/8)

Aligned to RCS Regenerative 212.7 (3,025) (1) 9.5 (3/8)

Charging Pump Miniflow 14.1 (200) 15.9 (5/8)

Letdown 174.7 (2,485) 15.9 (5/8)

Isolated from Shutdown Cooling 63.3 (900) 19.1 (3/4)

RCS by Valves SCP Miniflow 63.3 (900) 15.9 (5/8)

Containment Spray 63.3 (900) 19.1 (3/4)

CSP Miniflow 63.3 (900) 15.9 (5/8)

(1) Shellside design pressure; tubeside design pressure is 174.7 kg/cm2G (2,485 psig) 5A-41 Rev. 2

APR1400 DCD TIER 2 Table 5A-5 Containment Isolation Valve Position Indication System Interface CIV Type Indication (1)

SCS Supply Line SI-653/654 ZS SI-655/656 ZS SCS Return Line SI-600/601 ZI and ZS Safety Injection System SI-616/626 ZI and ZS 636/646 SI-322/332 ZS SI-602/603 ZI and ZS SI-321/331 ZI and ZS Letdown Line CV-515/516 ZS CV-522/523 ZS Charging System CV-240 ZS CV-524 ZS Seal Injection Line CV-241/242 ZS 243/244/255 RCP Controlled Bleed off CV-505/506 ZS Hot Leg Sampling SS-001/002 ZS Pressurizer Surge Line Sampling SS-003/004 ZS Pressurizer Steam Space Sampling SS-005/006 ZS Containment Spray System All CSS interfaces with the RCS are through the SCS CIVs (1) ZI designates position indication, and ZS designates a position switch indication in the MCR.

5A-42 Rev. 2

APR1400 DCD TIER 2 Table 5A-6 Pressure Indication System Interface Instrument Location SCS Supply Line P-300/301 Pump suction SCS Return Line P-302/305 Pump discharge P-329/349 DVI line Safety Injection System P-319/329/339/349 DVI line Letdown Line P-201 Upstream of the letdown control valves P-220 Pressure indicator downstream of the letdown control valves P-251 Equipment drain tank Charging System P-212A Upstream of the regenerative HX P-211 Pressure indicator in the charging pump suction line.

Seal Injection Line P-251 Indication in the EDT.

Controlled Bleedoff P-215 Combined bleedoff discharge line.

Containment Spray System All CSS interfaces with the RCS are through the SCS CIVs 5A-43 Rev. 2

APR1400 DCD TIER 2 Table 5A-7 Tank Level Indication System Interface Instrument Equipment Drain Tank L-251 Volume Control Tank L-226/227 5A-44 Rev. 2

APR1400 DCD TIER 2 SYSTEM SHUTDOWN DIRECTLY COOLING INTERFACING SYSTEM WITH RCS SYSTEMS INDIRECTLY CVCS ATM SS CSS SIS INTERFACING WITH RCS SS CSS GWMS SYSTEMS H2 CVCS SIS ATM TWICE REMOVED AIR SUPPLY SIS ATM CSS FROM RCS N2 CSS CVCS SS PCPS ATM SS LWMS ATM SWMS Figure 5A-1 Shutdown Cooling System 5A-45 Rev. 2

APR1400 DCD TIER 2 SYSTEM SAFETY DIRECTLY INJECTION INTERFACING SYSTEM WITH RCS SYSTEMS INDIRECTLY ATM SCS CSS SS INTERFACING WITH RCS SYSTEMS CVCS SCS CVCS TWICE REMOVED CSS ATM SCS FROM RCS SS CVCS CSS ATM SS ATM Figure 5A-2 Safety Injection System 5A-46 Rev. 2

APR1400 DCD TIER 2 SYSTEM LETDOWN DIRECTLY LINE INTERFACING WITH RCS

- BORON SYSTEMS H2 RECOVERY INDIRECTLY SS SCS N2 ATM INTERFACING GWMS

- MAKEUP WITH RCS SWMS CSS SFP SCS SYSTEMS ATM SIS TWICE REMOVED SS CSS FROM RCS LWMS SS SWMS SIS SCS ATM Figure 5A-3 Letdown Line 5A-47 Rev. 2

APR1400 DCD TIER 2 SYSTEM CHARGING DIRECTLY LINE INTERFACING WITH RCS

- BORON SYSTEMS H2 RECOVERY INDIRECTLY N2 ATM SS INTERFACING GWMS

- SEAL WITH RCS SWMS INJECTION

- MAKEUP SYSTEMS SFP TWICE REMOVED SCS ATM FROM RCS SS CSS LWMS SWMS SIS SCS Figure 5A-4 Charging Line 5A-48 Rev. 2

APR1400 DCD TIER 2 SYSTEM SEAL DIRECTLY INJECTION INTERFACING WITH RCS SYSTEMS BORON INDIRECTLY RECOVERY ATM INTERFACING WITH RCS PURIFICATION SYSTEMS MAKEUP TWICE REMOVED CCWS FROM RCS SWMS LWMS GWMS SS Figure 5A-5 RCP Seal Injection 5A-49 Rev. 2

APR1400 DCD TIER 2 SYSTEM RCP DIRECTLY CONTROLLED INTERFACING BLEEDOFF WITH RCS SYSTEMS INDIRECTLY BORON PURIFICATION ATM INTERFACING RECOVERY WITH RCS BORON RECOVERY PURIFICATION MAKEUP SYSTEMS MAKEUP ATM TWICE REMOVED CCWS SS FROM RCS SWMS SCS LWMS GWMS GWMS SWMS SS H2 N2 Figure 5A-6 RCP Controlled Bleedoff 5A-50 Rev. 2

APR1400 DCD TIER 2 SYSTEM HOT LEG DIRECTLY SAMPLING INTERFACING WITH RCS SYSTEMS INDIRECTLY SCS ATM CVCS LWMS SIS CSS INTERFACING WITH RCS CSS ATM SIS SYSTEMS SCS ATM TWICE REMOVED SIS GWMS CVCS FROM RCS SWMS CSS ATM H2 ATM N2 BORN RECOVERY MAKEUP Figure 5A-7 Sampling - Hot Leg 5A-51 Rev. 2

APR1400 DCD TIER 2 SYSTEM PRESSURIZER DIRECTLY SURGE LINE INTERFACING SAMPLING WITH RCS SYSTEMS INDIRECTLY SCS ATM CVCS MLWMS SIS CSS INTERFACING WITH RCS CSS ATM SIS SYSTEMS SCS ATM TWICE REMOVED SIS GWMS CVCS FROM RCS SWMS CSS ATM H2 ATM N2 BORN RECOVERY MAKEUP Figure 5A-8 Sampling - Pressurizer Surge Line 5A-52 Rev. 2

APR1400 DCD TIER 2 SYSTEM PRESSURIZER DIRECTLY STEAM SPACE INTERFACING SAMPLING WITH RCS SYSTEMS INDIRECTLY SCS ATM CVCS MLWMS SIS CSS INTERFACING WITH RCS CSS ATM SIS SYSTEMS SCS ATM TWICE REMOVED SIS GWMS CVCS FROM RCS SWMS CSS ATM H2 ATM N2 BORN RECOVERY MAKEUP Figure 5A-9 Sampling - Pressurizer Steam Space 5A-53 Rev. 2

APR1400 DCD TIER 2 CONTAINMENT COLD LEG HOT LEG INSIDE OUTSIDE RV SC PUMP M M M SC HX 2485 900 M

DVI LINE 2485 900 M

IRWST RETURN LINE IRWST 100 900 DESIGN PRESSURE IS 900 PSIG Figure 5A-10 Shutdown Cooling System 5A-54 Rev. 2

APR1400 DCD TIER 2 HOT LEG M

HOT-LEG INJECTION LINE RV M

DVI LINE M

IRWST RETURN LINE M

DESIGN PRESSURE IS 900 PSIG SAFETY INJECTION IRWST PUMP INSIDE OUTSIDE CONTAINMENT Figure 5A-11 Safety Injection System (Low-Pressure Line Interface) 5A-55 Rev. 2

APR1400 DCD TIER 2 DESIGN PRESSURE IS 900 PSIG M M HOT LEG 200 900 RV M M M TO SC PUMPS 2485 900 M

M SPOOL PIECE FOR REFUELING 100 900 CS PUMP M POOL FILL IRWST TO REFUELING POOL TOP FILL M

M 900 200 100 900 INSIDE OUTSIDE CONTAINMENT Figure 5A-12 Containment Spray System 5A-56 Rev. 2

APR1400 DCD TIER 2 REGENERATIVE HEAT EXCHANGER RCS COLD LEG LETDOWN HEAT EXCHANGER LETDOWN ORIFICES INSIDE CONTAINMENT HH PI A OUTSIDE CONTAINMENT 2485 200 SAMPLE HX F

CONTAINMENT ISOLATION VALVE EQUIPMENT DRAIN TANK Figure 5A-13 Letdown Line (including Pressure Alarm) 5A-57 Rev. 2

APR1400 DCD TIER 2 EDT VCT MINIFLOW HEAT 200 3200 EDT EXCHANGER EDT H 3200 3025 REGENERATIVE 200 3200 A PI HEAT M EXCHANGER 75 200 CHARGING NOZZLE CHARGING PUMPS VCT MAKEUP 200 3200 BYPASS LINE DIRECT BORATE LINE EDT 200 3025 BAST GRAVITY FEED LINE CHEMICAL AUXILIARY OUTSIDE INSIDE ADDITION CHARGING CONTAINMENT SYSTEM PUMP Figure 5A-14 Charging Line (including Pressure Alarm) 5A-58 Rev. 2

APR1400 DCD TIER 2 3025 20 VENT TO EDT M

RCP SEAL F INJECTION DRAIN INSIDE OUTSIDE TO EDT CONTAINMENT 3025 20 REGENERATIVE 3200 3025 HEAT 200 3200 M EXCHANGER CHARGING NOZZLE CHARGING PUMPS Figure 5A-15 Seal Injection Line 5A-59 Rev. 2

APR1400 DCD TIER 2 RCP M CONTROLLED BLEEDOFF 200 75 FT VCT 2485 200 CURRENT DESIGN MEETS ISLOCA REQUIREMENTS TO CCP INSIDE OUTSIDE MFHX INLET CONTAINMENT Figure 5A-16 Controlled Bleedoff Line 5A-60 Rev. 2

APR1400 DCD TIER 2 RELIEF VALVE FOR SAMPLING SYSTEM NORMAL PRIMARY NORMAL TO EDT SAMPLE PRIMARY COOLER RACK SAMPLE SINK HOT LEG SAMPLE COOLER RV s s s VCT s

TO RECYCLE DRAIN HEADER 2485 200 INSIDE OUTSIDE CONTAINMENT Figure 5A-17 Sampling System - Hot Leg 5A-61 Rev. 2

APR1400 DCD TIER 2 RELIEF VALVE FOR SAMPLING SYSTEM NORMAL PRIMARY NORMAL TO EDT PRESSURIZER SAMPLE PRIMARY SURGE LINE COOLER RACK SAMPLE SINK SAMPLE COOLER RV HOT LEG s s s VCT s

TO RECYCLE DRAIN HEADER 2485 200 INSIDE OUTSIDE CONTAINMENT Figure 5A-18 Sampling System - Pressurizer Surge Line 5A-62 Rev. 2

APR1400 DCD TIER 2 PRESSURIZER RELIEF VALVE STEAM SPACE FOR SAMPLING SYSTEM NORMAL PRIMARY NORMAL TO EDT SAMPLE PRIMARY COOLER RACK SAMPLE SINK SAMPLE COOLER RV HOT LEG s s s VCT s

TO RECYCLE DRAIN HEADER 2485 200 INSIDE OUTSIDE CONTAINMENT Figure 5A-19 Sampling System - Pressurizer Steam Space 5A-63 Rev. 2