ML18079A460

Korea Hydro-Nuclear Power Co., Ltd (Design Control Document) Rev.2 - Tier2 Chapter10-Steam and Power Conversion System

ML18079A460
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
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APR1400 DESIGN CONTROL DOCUMENT TIER 2 CHAPTER 10 STEAM AND POWER CONVERSION SYSTEM 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 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 10 - STEAM AND POWER CONVERSION SYSTEM TABLE OF CONTENTS NUMBER TITLE PAGE CHAPTER 10 - STEAM AND POWER CONVERSION SYSTEM ...................... 10.1-1 10.1 Summary Description ........................................................................................ 10.1-1 10.1.1 Protective Features ................................................................................ 10.1-3 10.1.2 Combined License Information ............................................................. 10.1-6 10.1.3 References ............................................................................................. 10.1-6 10.2 Turbine Generator............................................................................................. 10.2-1 10.2.1 Design Bases ......................................................................................... 10.2-1 10.2.1.1 Safety Design Bases ............................................................. 10.2-1 10.2.1.2 Non-Safety Power Generation Design Bases ....................... 10.2-1 10.2.2 Description ............................................................................................ 10.2-2 10.2.2.1 General Description .............................................................. 10.2-2 10.2.2.2 Component Description ........................................................ 10.2-3 10.2.2.3 Control and Protection .......................................................... 10.2-7 10.2.3 Turbine Rotor Integrity ....................................................................... 10.2-21 10.2.3.1 Material Selection ............................................................... 10.2-21 10.2.3.2 Fracture Toughness ............................................................ 10.2-23 10.2.3.3 Preservice Inspection .......................................................... 10.2-23 10.2.3.4 Turbine Rotor Design ......................................................... 10.2-24 10.2.3.5 Inservice Inspection ............................................................ 10.2-25 10.2.3.6 Turbine Missile Probability Analysis ................................. 10.2-26 10.2.4 Evaluation ............................................................................................ 10.2-28 10.2.5 Combined License Information ........................................................... 10.2-29 10.2.6 References ........................................................................................... 10.2-30 10.3 Main Steam System ........................................................................................... 10.3-1 10.3.1 Design Bases ......................................................................................... 10.3-1 10.3.2 System Description................................................................................ 10.3-4 10.3.2.1 General Description .............................................................. 10.3-4 i Rev. 2

APR1400 DCD TIER 2 10.3.2.2 Component Description ........................................................ 10.3-4 10.3.2.3 System Operation ................................................................. 10.3-8 10.3.2.4 Design Features for Minimization of Contamination ......... 10.3-11 10.3.3 Safety Evaluation ................................................................................ 10.3-14 10.3.4 Inspection and Testing Requirements ................................................. 10.3-15 10.3.4.1 Preoperational Testing ........................................................ 10.3-15 10.3.4.2 Inservice Testing................................................................. 10.3-15 10.3.5 Secondary Water Chemistry................................................................ 10.3-16 10.3.5.1 Chemistry Control Basis ..................................................... 10.3-17 10.3.5.2 Corrosion Control Effectiveness ........................................ 10.3-18 10.3.5.3 Primary-to-Secondary Leaks .............................................. 10.3-20 10.3.6 Steam and Feedwater System Materials .............................................. 10.3-21 10.3.6.1 Fracture Toughness ............................................................ 10.3-21 10.3.6.2 Materials Selection and Fabrication ................................... 10.3-21 10.3.6.3 Flow-Accelerated Corrosion .............................................. 10.3-22 10.3.7 Combined License Information ........................................................... 10.3-25 10.3.8 References ........................................................................................... 10.3-26 10.4 Other Features of the Steam and Power Conversion System ........................ 10.4-1 10.4.1 Main Condensers ................................................................................... 10.4-1 10.4.1.1 Design Bases ........................................................................ 10.4-1 10.4.1.2 System Description ............................................................... 10.4-1 10.4.1.3 Safety Evaluation.................................................................. 10.4-3 10.4.1.4 Inspection and Testing Requirements .................................. 10.4-4 10.4.1.5 Instrumentation Requirements.............................................. 10.4-5 10.4.2 Condenser Vacuum System................................................................... 10.4-5 10.4.2.1 Design Bases ........................................................................ 10.4-5 10.4.2.2 System Description ............................................................... 10.4-6 10.4.2.3 Safety Evaluation................................................................ 10.4-10 10.4.2.4 Inspection and Testing Requirements ................................ 10.4-10 10.4.2.5 Instrumentation Requirements............................................ 10.4-10 10.4.3 Turbine Steam Seal System ................................................................. 10.4-11 10.4.3.1 Design Basis ....................................................................... 10.4-11 ii Rev. 2

APR1400 DCD TIER 2 10.4.3.2 System Description ............................................................. 10.4-11 10.4.3.3 Safety Evaluation................................................................ 10.4-12 10.4.3.4 Inspection and Testing Requirements ................................ 10.4-12 10.4.3.5 Instrumentation Requirements............................................ 10.4-13 10.4.4 Turbine Bypass System ....................................................................... 10.4-13 10.4.4.1 Design Bases ...................................................................... 10.4-13 10.4.4.2 System Description ............................................................. 10.4-14 10.4.4.3 Safety Evaluation................................................................ 10.4-16 10.4.4.4 Inspection and Testing Requirements ................................ 10.4-17 10.4.4.5 Instrumentation Requirements............................................ 10.4-17 10.4.5 Circulating Water System ................................................................... 10.4-17 10.4.5.1 Design Bases ...................................................................... 10.4-17 10.4.5.2 System Description ............................................................. 10.4-18 10.4.5.3 Safety Evaluation................................................................ 10.4-25 10.4.5.4 Inspection and Testing Requirements ................................ 10.4-25 10.4.5.5 Instrumentation Requirements............................................ 10.4-25 10.4.6 Condensate Polishing System ............................................................. 10.4-26 10.4.6.1 Design Bases ...................................................................... 10.4-26 10.4.6.2 System Description ............................................................. 10.4-26 10.4.6.3 Safety Evaluation................................................................ 10.4-32 10.4.6.4 Inspection and Testing Requirements ................................ 10.4-32 10.4.6.5 Instrumentation Requirement ............................................. 10.4-32 10.4.7 Condensate and Feedwater System ..................................................... 10.4-33 10.4.7.1 Design Bases ...................................................................... 10.4-33 10.4.7.2 System Description ............................................................. 10.4-35 10.4.7.3 Safety Evaluation................................................................ 10.4-48 10.4.7.4 Inspection and Testing Requirements ................................ 10.4-48 10.4.7.5 Instrumentation Requirements............................................ 10.4-49 10.4.7.6 Water Hammer Prevention ................................................. 10.4-49 10.4.7.7 Flow-Accelerated Corrosion .............................................. 10.4-51 10.4.8 Steam Generator Blowdown System ................................................... 10.4-51 10.4.8.1 Design Bases ...................................................................... 10.4-52 iii Rev. 2

APR1400 DCD TIER 2 10.4.8.2 System Description ............................................................. 10.4-54 10.4.8.3 Safety Evaluation................................................................ 10.4-63 10.4.8.4 Inspection and Testing Requirements ................................ 10.4-64 10.4.8.5 Instrumentation Requirements............................................ 10.4-64 10.4.9 Auxiliary Feedwater System ............................................................... 10.4-65 10.4.9.1 Design Bases ...................................................................... 10.4-65 10.4.9.2 System Description ............................................................. 10.4-70 10.4.9.3 Safety Evaluation................................................................ 10.4-77 10.4.9.4 Inspection and Testing Requirements ................................ 10.4-81 10.4.9.5 Instrumentation Requirements............................................ 10.4-82 10.4.10 Auxiliary Steam System ...................................................................... 10.4-85 10.4.10.1 Design Basis ....................................................................... 10.4-85 10.4.10.2 System Description ............................................................. 10.4-85 10.4.10.3 Safety Evaluation................................................................ 10.4-91 10.4.10.4 Inspection and Testing Requirements ................................ 10.4-91 10.4.10.5 Instrumentation Requirements............................................ 10.4-91 10.4.11 Combined License Information ........................................................... 10.4-91 10.4.12 References ........................................................................................... 10.4-93 iv Rev. 2

APR1400 DCD TIER 2 LIST OF TABLES NUMBER TITLE PAGE Table 10.1-1 Steam and Power Conversion System Major Design Data ............... 10.1-7 Table 10.2.2-1 Source of Extraction Steam for Feedwater Heating ........................ 10.2-32 Table 10.2.2-2 Typical Turbine Valve Closure Times .............................................. 10.2-33 Table 10.2.2-3 Turbine Overspeed Protection Devices ........................................... 10.2-34 Table 10.2.3-1 Chemical Composition for Ni-Cr-Mo-V Alloy Steel Designation ...................................................................................... 10.2-35 Table 10.2.4-1 Turbine Speed Control System Component Failure Analysis ......... 10.2-36 Table 10.3.2-1 Main Steam System and Component Design Data .......................... 10.3-28 Table 10.3.2-2 Main Steam Piping Design Data...................................................... 10.3-30 Table 10.3.2-3 Main Steam Branch Piping Design Data (2.5 Inches and Larger) ............................................................................................. 10.3-31 Table 10.3.2-4 Feedwater Piping Design Data (2.5 Inches and Larger) .................. 10.3-32 Table 10.3.2-5 Main Steam and Feedwater Piping Fluid Data ................................ 10.3-34 Table 10.3.2-6 Main Steam Branch Piping (2.5 Inches and Larger),

Between the MSIVs and the Turbine Stop Valves .......................... 10.3-35 Table 10.3.3-1 Main Steam System Failure Modes and Effects Analysis ............... 10.3-36 Table 10.4.1-1 Main Condenser Design Parameters ................................................ 10.4-97 Table 10.4.2-1 Condenser Vacuum Pump Design Parameters ................................ 10.4-98 Table 10.4.5-1 Circulating Water System Design Parameters ................................. 10.4-99 Table 10.4.6-1 Condensate Polishing System Design Parameters ......................... 10.4-101 Table 10.4.7-1 Major Components Design Parameters ......................................... 10.4-102 Table 10.4.7-2 Condensate and Feedwater System Failure Modes and Effects Analysis ............................................................................. 10.4-105 Table 10.4.8-1 Steam Generator Blowdown System Major Component Design Parameters ......................................................................... 10.4-106 Table 10.4.8-2 Steam Generator Blowdown System Failure Modes and Effects Analysis ............................................................................. 10.4-110 Table 10.4.8-3 Codes and Standards for Equipment in the SGBS......................... 10.4-111 v Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-4 Design Basis Radioactive Source Terms for SGBD Components (1 % Fuel Defect) ..................................................... 10.4-112 Table 10.4.9-1 Auxiliary Feedwater System Component Parameters ................... 10.4-115 Table 10.4.9-2 Auxiliary Feedwater System Emergency Power Sources ............. 10.4-118 Table 10.4.9-3 Auxiliary Feedwater System Failure Modes and Effects Analysis ......................................................................................... 10.4-121 Table 10.4.9-4 Auxiliary Feedwater System Instrumentation and Control ........... 10.4-123 Table 10.4.9-5 Principal Auxiliary Feedwater System Pressure-Retaining Materials ........................................................................................ 10.4-124 Table 10.4.9-6 Steam Generator Makeup Flow Requirement ............................... 10.4-125 vi Rev. 2

APR1400 DCD TIER 2 LIST OF FIGURES NUMBER TITLE PAGE Figure 10.1-1 Heat Balance Diagram (Condenser Pressure: 0.0898 kg/cm2A

[2.6 inHgA]) - VWO ...................................................................... 10.1-8 Figure 10.1-2 Overall System Flow Diagram...................................................... 10.1-12 Figure 10.2.2-1 Typical Arrangement of T/G System ............................................ 10.2-37 Figure 10.2.2-2 High Level Overspeed Protection Architecture ............................ 10.2-38 Figure 10.3.2-1 Main Steam System Flow Diagram .............................................. 10.3-37 Figure 10.3.2-2 Turbine System Flow Diagram ..................................................... 10.3-39 Figure 10.4.2-1 Condenser Vacuum System Flow Diagram ................................ 10.4-126 Figure 10.4.3-1 Turbine Steam Seal System Flow Diagram ................................ 10.4-128 Figure 10.4.5-1 Circulating Water System Flow Diagram ................................... 10.4-129 Figure 10.4.6-1 Condensate Polishing System Flow Diagram ............................. 10.4-131 Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram .................... 10.4-133 Figure 10.4.8-1 Steam Generator Blowdown System Flow Diagram .................. 10.4-144 Figure 10.4.8-2 Concept of Central Blowdown ................................................... 10.4-146 Figure 10.4.9-1 Auxiliary Feedwater System Flow Diagram .............................. 10.4-147 Figure 10.4.10-1 Auxiliary Steam System Flow Diagram ..................................... 10.4-150 vii Rev. 2

APR1400 DCD TIER 2 ACRONYM AND ABBREVIATION LIST ABD abnormal blowdown AC alternating current AFAS auxiliary feedwater actuation signal AFW auxiliary feedwater AFWS auxiliary feedwater system AFWST auxiliary feedwater storage tank ALARA as low as reasonably achievable AOO anticipated operational occurrence AOV air-operated valve ATS automatic turbine startup ATWS anticipated transients without scram AVT all volatile treatment BDS blowdown subsystem BTP Branch Technical Position CBD continuous blowdown CBV cation-bed ion exchanger vessel COL combined license CPS condensate polishing system CV control valve Cv Charpy V-notch CW circulating water CWS circulating water system DBA design basis accident DBE design basis event DC direct current DPS diverse protection system EBD emergency blowdown EOTS Electrical Overspeed Trip System ESFAS engineered safety features actuation system viii Rev. 2

APR1400 DCD TIER 2 ETS emergency trip system FAC flow-accelerated corrosion FATT fracture appearance transition temperature FLB feedwater line break FWCS feedwater control system GDC general design criteria HCBD high-capacity blowdown HEI Heat Exchange Institute HP high pressure IEEE Institute of Electrical and Electronics Engineers ISV intermediate stop valve IV intercept valve LP low pressure LOOP loss of offsite power LCP local control panel MBV mixed-bed ion exchanger vessel MCR main control room MFIV main feedwater isolation valve MOTS Mechanical Overspeed Trip System MSADV main steam atmospheric dump valve MSADVIV MSADV Isolation Valve MSGTR multiple steam generator tube rupture MSIS main steam isolation signal MSIV main steam isolation valve MSIVBV main steam isolation valve bypass valve MSLB main steam line break MSR moisture separator reheater MSS main steam system MSSV main steam safety valve MSV main stop valve MSVH main steam valve house ix Rev. 2

APR1400 DCD TIER 2 NNS non-nuclear safety NRC United States Nuclear Regulatory Commission NRV non-return check valve NSSS nuclear steam supply system POSRV pilot-operated safety relief valve QA quality assurance RCS reactor coolant system RG Regulatory Guide RPCS reactor power cutback system RRS reactor regulating system RSR remote shutdown room SBCS steam bypass control system SBLOCA small-break loss-of-coolant accident SBO station blackout SG steam generator SGBS steam generator blowdown system SGMSR steam generator's maximum steaming rate SGTR steam generator tube rupture SSC structure, system, or component SSE safe shutdown earthquake TB turbine building TBS turbine bypass system TBV turbine bypass valve T/G turbine generator TGBCCW turbine generator building closed cooling water TGBOCWS turbine generator building open cooling water system TGCS turbine generator control system TSSS turbine steam seal system VWO valve wide open WLS wet lay-up subsystem WWTS wastewater treatment system x Rev. 2

APR1400 DCD TIER 2 CHAPTER 10 - STEAM AND POWER CONVERSION SYSTEM 10.1 Summary Description The function of the steam and power conversion system is to convert the heat energy generated by the nuclear reactor into electrical energy. The heat energy produces steam in two steam generators (SGs) capable of driving a turbine generator unit. The steam and power conversion system uses a condensing cycle with regenerative feedwater heating.

Turbine exhaust steam is condensed in a surface-type condenser. The condensate from the steam is returned to the SGs through the condensate and feedwater system.

The steam and power conversion system comprises the following major process systems:

a. Turbine generator (T/G)

b. Main steam system (MSS)

c. Condensate and feedwater system

d. Turbine bypass system (TBS)

e. Circulating water system (CWS)

f. Steam generator blowdown system (SGBS)

g. Auxiliary feedwater system (AFWS)

The following figures and tables describe the steam and power conversion system:

a. Table 10.1-1: Steam and Power Conversion System Major Design Data

b. Figure 10.1-1: Heat Balance Diagram

c. Figure 10.1-2: Overall System Flow Diagram

d. Figure 10.3.2-1: Main Steam System Flow Diagram

e. Figure 10.3.2-2: Turbine System Flow Diagram

f. Figure 10.4.5-1: Circulating Water System Flow Diagram 10.1-1 Rev. 2

APR1400 DCD TIER 2

g. Figure 10.4.7-1: Condensate and Feedwater System Flow Diagram

h. Figure 10.4.8-1: Steam Generator Blowdown System Flow Diagram

i. Figure 10.4.9-1: Auxiliary Feedwater System Flow Diagram The steam generated in the two SGs is supplied to the high-pressure turbine by the MSS.

The steam is expanded through the high-pressure turbine, passes through the two moisture separator reheaters (MSRs), and then flows to the three low-pressure turbines.

The exhaust steam from the low-pressure turbines is condensed in a conventional surface-type condenser. The condenser removes air and other noncondensable gases from the condensate and transfers heat to the CWS.

The condensate from the steam is returned to the SGs through the condensate and feedwater systems. The condensate from the condenser hotwell is transferred through the low-pressure (LP) feedwater heaters to the deaerator storage tank by the condensate pumps.

The feedwater booster pumps take suction from the deaerator storage tank and discharge to the feedwater pumps. Feedwater is discharged from the feedwater pumps, passes through two trains of high-pressure (HP) feedwater heaters, and is delivered to the SGs.

A TBS capable of relieving 55 percent of full-load main steam flow is provided to dissipate heat from the reactor coolant system (RCS) during turbine or reactor trip. This system consists of eight turbine bypass valves (TBVs) to limit an increase in pressure in the SGs following cessation of flow to the turbine. Closing the main stop valves blocks the normal steam flow path to the turbine, and decay heat is removed by directing bypass steam to the condenser. The TBS is described further in Subsection 10.4.4.

Two turbine-driven and two motor-driven auxiliary feedwater pumps are provided to provide reasonable assurance that adequate feedwater is supplied to the SGs in the event of a loss of the main and startup feedwater pumps. The auxiliary feedwater system (AFWS) is described in Subsection 10.4.9.

Overpressure protection of the secondary side of the SGs is provided by spring-loaded main steam safety valves (MSSVs).

Radioactive material is monitored to prevent discharging it to the environment.

10.1-2 Rev. 2

APR1400 DCD TIER 2 The turbines are tandem compound, 1,800 rpm, and supplied with steam from the nuclear steam supply system (NSSS). A three-phase synchronous electric generator is coupled directly to the turbine shaft. The generator consists of a hydrogen gas cooling system, a seal oil system to prevent hydrogen gas leakage from the generator casing, and a stator winding cooling water system for the stator bars. The generator is equipped with a collector housing for the static rectifier-type excitation system that is directly coupled to the generator shaft. Each T/G is designed for an output of around 1,425 MW, which depends on the plant condition for the NSSS thermal output of 4,000 MWt. The T/G is described in Section 10.2, and the principal T/G conditions and the rated NSSS conditions are presented in Table 10.1-1.

The following portions of the steam and power conversion system have safety-related functions:

a. Main steam piping and components from each SG nozzle outlet up to and including the main steam valve house (MSVH) penetration anchor wall (see Section 10.3)

b. Main feedwater piping and components from each SG nozzle inlet up to and including the MSVH penetration anchor wall (see Subsection 10.4.7)

c. Auxiliary feedwater system (AFWS) (see Subsection 10.4.9)

d. SG blowdown piping between each SG blowdown nozzle and its respective outermost containment isolation valve (see Subsection 10.4.8) 10.1.1 Protective Features Protection for Loss of External Electrical Load or Turbine Trip In the event of a loss of load or turbine trip, the TBS discharges steam from the SGs directly to the main condenser through the TBVs, bypassing the turbine. This process removes energy from the RCS and minimizes transient effects on the RCS. Load rejection capabilities are described in Section 10.3 and Subsections 10.4.4, 15.2.1, and 15.2.2.

Overpressure Protection Overpressure protection for the secondary side of the SGs is provided by spring-loaded MSSVs in accordance with the American Society of Mechanical Engineers (ASME) Boiler 10.1-3 Rev. 2

APR1400 DCD TIER 2 and Pressure Vessel (B&PV) Code,Section III (Reference 1). Five MSSVs are installed on each of the main steam lines upstream of the main steam isolation valve (MSIV) outside the containment. As the SG pressure rises and pressure setpoints are reached, the MSSVs open and discharge the high-pressure steam to the atmosphere. MSSVs are described in Subsection 10.3.2.2.3.

Overpressure protections for the following components are provided in accordance with ASME Section VIII, Division 1 (Reference 2):

a. MSRs

b. LP feedwater heaters

c. HP feedwater heaters

d. Deaerator/feedwater storage tank

e. MSR drain tanks Protection for Loss of Main Feedwater Flow When a loss of main feedwater event occurs, including a loss of offsite power (LOOP), the AFWS provides an independent means of supplying secondary quality makeup water to the SGs for removal of residual heat from the reactor core. The AFWS is described in Subsection 10.4.9.

Turbine Overspeed Protection The turbine generator control system (TGCS) provides automatic control of turbine speed and acceleration through the entire speed range. The speed control function serves as the first line of defense against turbine overspeed. At no more than 103 percent of the rated speed, the TGCS fully closes all the CVs, which should limit maximum speed to less that 110 percent. If the speed control function fails to protect the turbine overspeed, the overspeed protection system is activated. The overspeed protection system consists of two diverse and independent subsystems:

a. Mechanical overspeed trip system (MOTS) in the front standard

b. Electrical overspeed trip system (EOTS) 10.1-4 Rev. 2

APR1400 DCD TIER 2 The mechanical and electrical overspeed trip systems are fully independent of each other in that the failure of one system does not preclude operation of the other. They use diverse components and do not share common components, which removes susceptibility to common-cause failure.

The mechanical overspeed trip system is the emergency overspeed protection that acts to bring the turbine to a safe shutdown condition upon reaching a setpoint that is approximately 110 percent of the rated speed. The electrical overspeed trip system consists of two speed-calculating modules: primary and backup. Each module uses the three signals from the speed-conditioning units to the 2-out-of-3 tripping device. Each setpoint is approximately 111.5 percent of the rated speed. Turbine overspeed protection is described in Subsection 10.2.2.3.2.

Turbine Missile Protection Turbine missile protection is designed and controlled to minimize the potential for turbine missile generation (see Subsection 3.5.1.3).

The orientation of the T/G, as shown in Figure 3.5-1, is found to be favorable when considering its location relative to essential safety-related SSCs. The layout drawing shows the general arrangement of the T/G and associated equipment in relation to essential safety-related SSCs. Failure of the T/G equipment does not preclude safe shutdown of the reactor (see Subsection 10.2.4).

Radioactivity Protection The steam and power conversion system may become contaminated through SG tube leakage. Radioactive contaminants are detected by radiation monitors in the SG blowdown line (iodine activity), main steam line (noble gas activity), and the condenser vacuum exhaust (noble gas activity) (see Subsection 10.3.5). This design feature provides a redundant and diverse method of detecting SG tube leakage.

Radiological aspects of primary-to-secondary system leakage and limiting conditions for operation are described in Chapter 11.

10.1-5 Rev. 2

APR1400 DCD TIER 2 Flow-Accelerated Corrosion Protection Flow-accelerated corrosion (FAC) resistant materials are used in steam and power conversion systems for components exposed to single-phase and two-phase flow where significant FAC or erosion/corrosion can occur. Factors considered in the evaluation of FAC include system piping and component configuration and geometry, water chemistry, piping and component material, fluid temperature, and fluid velocity.

Pipe size and layout are also considered to minimize the potential for FAC in systems with single-phase and two-phase flow conditions. For other carbon steel piping with relatively mild FAC degradation, additional thickness is applied for the design life.

To maintain a noncorrosive environment, the secondary side water chemistry (see Subsection 10.3.5) uses an all-volatile chemistry.

An FAC monitoring program for the steam and power conversion systems that contain water or wet steam is described in Subsection 10.3.6.3.

10.1.2 Combined License Information No combined license (COL) information is required with regard to Section 10.1.

10.1.3 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. ASME Section VIII, Division 1, Rules for Construction of Pressure Vessels, The American Society of Mechanical Engineers, the 2010 Edition.

10.1-6 Rev. 2

APR1400 DCD TIER 2 Table 10.1-1 Steam and Power Conversion System Major Design Data Data Value Major Steam System Design Data Rated NSSS power 4,000 MWt MSS design pressure/temperature 84.37 kg/cm2A (1,200 psia) / 298.9 °C (570 °F)

MSS operating pressure/temperature 69.74 kg/cm2A (992 psia) / 284.2 °C (543.6 °F)

(at SG steam nozzle outlets)

Main steam flow 8.14 x 106 kg/hr (17.95 x 106 lb/hr)

(maximum guaranteed rate [MGR] condition)

Main feedwater temperature (MGR condition) 232.2 °C (450 °F)

Main feedwater flow 8.16 x 106 kg/hr (17.99 x 106 lb/hr)

(MGR condition, with 0.2 % SGBS flow)

Downcomer flow 8.16 x 105 kg/hr (17.99 x 105 lb/hr)

(MGR condition, with 0.2 % SGBS flow)

Economizer flow 7.34 x 106 kg/hr (16.19 x 106 lb/hr)

(MGR condition, with 0.2 % SGBS flow)

SGBS flow rate, normal/abnormal/high 0.2 % / 1 % / 13.9 % of main flow rate Turbine Generator Design Data Generator output 1,425 MWe at 0.090 kg/cm2A (2.6 in HgA)

Operating speed 1,800 rpm Turbine type Tandem-compound Frequency 60 Hz, three phase Power factor 0.90 Voltage 24 kV nominal 10.1-7 Rev. 2

APR1400 DCD TIER 2 773301. M 195910. M FP 195910. M 2.50 IN HG 16480. KW 14099786. M MOISTURE STEAM STEAM 12147152. M 201.9 P SEPARATOR REHEATER REHEATER 195910. M 18024619. M 539.9 T 86 1191.3 H 0. M 962.0 PSIA 89 0 .M 0 .M 1961. M 2

635329. M 7051. M 51 89 1 480.0 P 1756724. M 456.3 P 923.8 P GENERATOR OUTPUT 1485736. KW 6

61 FLOW LP 71 72 1800. RPM 58.9 P 14.8 P 8139. M 8139. M 7.26 P 3.10 P 480.0 P 313.7 P 209.4 P 209.4 P 545190. M 955549. M 460304. M 469955. M 983631. M 762437. M 1517085. M 3 5 9716154. M 1060. M 91 2.60 IN HG 11444408. M 5

10800. M 37596. M 110.1 T 3

86 MAKEUP 2 SSR 8500. M 91 51 54 1 0. M 52 983631. M 762437. M 1524136. M 955549. M 460304. M 545190. M 469955. M 72 71 61 52 54 18835515. M FEEDWATER 56.8 P 454.7 T 413.6 T 378.1 T 205.8 T 172.1 T 136.6 T 465.6 P 304.2 P 203.1 P 14.4 P 7.05 P 3.01 P PUMP(S) 289.2 T 291.3 T 111.1 T 110.5 T 459.7 T 418.6 T 383.1 T 210.8 T 177.1 T 141.6 T SPE CONDENSATE PUMP(S) 5.0 TD 5.0 TD 5.0 TD 5.0 TD 5.0 TD 5.0 TD 10.0 DC 10.0 DC 10.0 DC 0. TD 10.0 DC 10.0 DC 10.0 DC 1756932. M 3154697. M 6435558. M 289.2 T 1005493. M 1475448. M 8500. M 460304. M 423.6 T 388.1 T 301.3 T 182.1 T 146.6 T 121.1 T LEGEND - CALCULATIONS BASED ON 1967 ASME STEAM TABLES M - FLOW-LB/HR P - PRESSURE-PSIA H - ENTHALPY-BTU/LB T - TEMPERATURE-F DEGREES VWO, 0.2% MU, ENGLISH Figure 10.1-1 Heat Balance Diagram (Condenser Pressure: 0.0898 kg/cm2A [2.6 inHgA]) - VWO (1 of 4) 10.1-8 Rev. 2

APR1400 DCD TIER 2 775329. M 1191.3 H 196087. M FP 196087. M 2.50 IN HG 16499. KW 14127822. M MOISTURE STEAM STEAM 12172507. M SEPARATOR REHEATER REHEATER 202.2 196087. M 18022503. M 539.9 T PIV 86 1191.3 H 0. M 962.0 PSIA 89 0 .M 0 .M 1964. M 2

635261. M 7047. M 51 89 1 480.0 P 1759228. M 456.3 P 923.8 P GENERATOR OUTPUT 1517474. KW 6

61 FLOW LP 71 72 60.4 P 1800. RPM 15.4 P 8160. M 8160. M 7.31 P 3.56 P 480.0 P 313.7 P 209.7 P 209.7 P 489389. M 961354. M 478075. M 706523. M 983454. M 759938. M 1489681. M 3 5 9537166. M 1017. M 91 1.50 IN HG 11464135. M 5

3 10800. M 37596. M 91.7 T 86 MAKEUP 2 SSR 8500. M 91 51 54 1 0. M 52 983454. M 759938. M 1496728. M 961354. M 478075. M 489389. M 706523. M 72 71 61 52 54 18835427. M FEEDWATER 58.6 P 454.7 T 413.6 T 378.2 T 207.8 T 172.4 T 142.0 T 465.6 P 304.3 P 203.4 P 14.9 P 7.09 P 3.45 P PUMP(S) 291.2 T 293.2 T 459.7 T 418.6 T 383.2 T 212.8 T 177.4 T 147.0 T 92.7 T SPE 92.0 T CONDENSATE PUMP(S) 5.0 TD 5.0 TD 5.0 TD 5.0 TD 5.0 TD 5.0 TD 10.0 DC 10.0 DC 10.0 DC 0. TD 10.0 DC 10.0 DC 10.0 DC 1758783. M 3153982. M 6409938. M 291.2 T 1673986. M 8500. M 478075. M 967464. M 423.6 T 388.2 T 303.2 T 182.4 T 152.0 T 102.7 T LEGEND - CALCULATIONS BASED ON 1967 ASME STEAM TABLES M - FLOW-LB/HR P - PRESSURE-PSIA H - ENTHALPY-BTU/LB T - TEMPERATURE-F DEGREES VWO, 0.2% MU, ENGLISH Figure 10.1-1 Heat Balance Diagram (Condenser Pressure: 0.0518 kg/cm2a [1.5 inHgA]) - VWO (2 of 4) 10.1-9 Rev. 2

APR1400 DCD TIER 2 783703. M 188264. M FP 188264. M 2.50 IN HG 15737. KW 13499833. M MOISTURE STEAM STEAM 11620650. M 193.4 P SEPARATOR REHEATER REHEATER 188264. M 17166298. M 539.9 T 86 1191.3 H 0. M 962.0 PSIA 89 0 .M 0 .M 1878. M 2

589442. M 7134. M 51 89 1 458.2 P 1690918. M 435.5 P 923.8 P GENERATOR OUTPUT 1425321. KW 6

61 FLOW LP 71 72 1800. RPM 7804. M 7804. M 515592. M 904024. M 14.2 P 2.98 P 6.96 P 56.4 P 436085. M 429004. M 3 5 904958. M 713806. M 9335945. M 1431825. M 1813. M 458.2 P 299.6 P 200.5 P 200.5 P 91 2.60 IN HG 10960090. M 5

10800. M 35900. M 110.1 T 3

86 MAKEUP 2 SSR 8500. M 91 51 54 1 0. M 52 904958. M 713806. M 1438959. M 904024. M 436085. M 515592. M 429004. M 72 71 61 52 54 17985900. M FEEDWATER 54.4 P 450.0 T 409.4 T 374.5 T 203.6 T 170.2 T 135.0 T 444.4 P 290.6 P 194.5 P 13.7 P 6.75 P 2.89 P PUMP(S) 286.4 T 288.4 T 111.2 T 455.0 T 414.4 T 379.5 T 208.6 T 175.2 T 140.0 T SPE 110.5 T CONDENSATE PUMP(S) 5.0 TD 5.0 TD 5.0 TD 5.0 TD 5.0 TD 5.0 TD 10.0 DC 10.0 DC 10.0 DC 0. TD 10.0 DC 10.0 DC 10.0 DC 1688661. M 2991909. M 6121786. M 286.4 T 436085. M 951677. M 1380681. M 8500. M 419.4 T 384.5 T 298.4 T 180.2 T 145.0 T 121.2 T LEGEND - CALCULATIONS BASED ON 1967 ASME STEAM TABLES M - FLOW-LB/HR P - PRESSURE-PSIA H - ENTHALPY-BTU/LB T - TEMPERATURE-F DEGREES MGR, 0.2% MU, ENGLISH Figure 10.1-1 Heat Balance Diagram (Condenser Pressure: 0.0898 kg/cm2a [2.6 inHgA]) - MGR (3 of 4) 10.1-10 Rev. 2

APR1400 DCD TIER 2 785715. M 1191.3 H 188434. M FP 188434. M 2.50 IN HG 15755. KW 13526882. M MOISTURE STEAM STEAM 11645146. M SEPARATOR REHEATER REHEATER 193.7 188434. M 17164285. M 539.9 T PIV 86 1191.3 H 0. M 962.0 PSIA 89 0 .M 0 .M 1881. M 2

589261. M 7130. M 51 89 1 458.1 P 1693301. M 435.5 P 923.8 P GENERATOR OUTPUT 1459605. KW 6

61 FLOW LP 71 72 57.9 P 14.8 P 7824. M 7824. M 7.01 P 3.41 P 458.1 P 299.6 P 200.8 P 200.8 P 462764. M 909505. M 453155. M 655854. M 904737. M 711286. M 1405690. M 3 5 9163868. M 1770. M 3

1.50 IN HG 10979275. M 5

3 10800. M 35900. M 91.7 T 86 MAKEUP 2 SSR 8500. M 91 51 54 1 0. M 52 904737. M 711286. M 1412820. M 909505. M 453155. M 462764. M 655854. M 72 71 61 52 54 17985900. M FEEDWATER 56.1 P 450.0 T 409.4 T 374.6 T 205.7 T 170.5 T 140.3 T 444.4 P 290.6 P 194.8 P 14.3 P 6.80 P 3.31 P PUMP(S) 288.4 T 290.4 T 455.0 T 414.4 T 379.6 T 210.7 T 175.5 T 145.3 T 92.7 T SPE 92.0 T CONDENSATE PUMP(S) 5.0 TD 5.0 TD 5.0 TD 5.0 TD 5.0 TD 5.0 TD 10.0 DC 10.0 DC 10.0 DC 0. TD 10.0 DC 10.0 DC 10.0 DC 6097120. M 288.4 T 453155. M 915919. M 1571774. M 8500. M 1690452. M 2990999. M 300.4 T 180.5 T 150.3 T 102.7 T 419.4 T 384.6 T LEGEND - CALCULATIONS BASED ON 1967 ASME STEAM TABLES M - FLOW-LB/HR P - PRESSURE-PSIA H - ENTHALPY-BTU/LB T - TEMPERATURE-F DEGREES MGR, 0.2% MU, ENGLISH Figure 10.1-1 Heat Balance Diagram (Condenser Pressure: 0.0518 kg/cm2a (1.5 inHgA)) - MGR (4 of 4) 10.1-11 Rev. 2

APR1400 DCD TIER 2 RCB AB AB TGB 10.3 Main Steam System (MSS)

MSADV x 1

/ Piping MSSV x 5 To Feedwater

/ Piping Pump Turbine MSIV x 1

/ Piping E E E M H Main Stop H H Control Moisture Separator Valve Valve Reheater(MSR) x 2 E

MSADV x 1 H E E MSSV x 5 Main Stop H H Control

/ Piping

/ Piping Valve Valve MSIVBV x 1 To Feedwater

/ Piping E E E 10.2 Turbine Generator (TG) Pump Turbine M H Main Stop H H Control Valve Valve Intercept Valve x 2 Intercept Valve x 2 Intercept Valve x 2 MSIV x 1 E E

/ Piping Main Stop H H Control Intermediate Stop Valve x 2 Intermediate Stop Valve x 2 Intermediate Stop Valve x 2 E Valve Valve H

To Low Pressure Atmosphere MSIVBV x 1 High Pressure Low Pressure Low Pressure Turbine "C" Generator x 1 Exciter x 1

/ Piping Turbine x 1 Turbine "A" Turbine "B" A

M Equal. Duct Equal. Duct B

Aux. Feedwater Storage Tank 10.4.1 Main Condensers 100% x 2 M 100% Turbine Driven C AF Pump x 2 Turbine Bypass #3A #3B #3C Valve x 8 LP FW Heater 3 Stage To 10.4.9 Aux. Feedwater 10.4.4 Turbine #2A #2B #2C Atmosphere 50% x 3 System (AFWS) 100% Motor Driven Bypass System AF Pump x 2 Radiation VENTURI RX Steam Monitoring Generator (SG) x 2 #1A #1B #1C E

H E

H M 10.4.2 Condenser Vacuum 1st Stage A B C Condenser Vacuum System(CA) 2nd Stage MSR Drain MSR Drain Pump 33.33% x 4 MSR Drain Tank x 2 MFIV MFIV FW Control Isolation Tank x 2 Tank x 2 Valve Valve M Flow To SG Element Blowdown

1. 7 Reg.HX E E M H H MFIV MFIV FW Control Isolation Flow #6 Valve Valve Element M

RCB AB #5 To Atmosphere HP FW Heater Radiation 3 Stage 75% x 2 RX DEARATOR Monitoring SG Blowdown Flash Tank x 1 DEARATOR SPE STORAGE TANK 2 Condensate Condensate Condensate Blower x 2 From STAGE Pump 50% Pump 50% Pump 50%

Condensate water Turbine Driven Steam Packing Feedwater Pump Feedwater Booster Exhauster (SPE) 55% x 3 Pump 55% x 3 Condensate Polisher SG Blowdown 10.4.3 Turbine Steam Regenation Heat Exchanger x 1 Seal System CDI Scope To Deaerator Startup Feedwater (TSSS)

Pump 5% x 1 1. Cooling Tower SG Blowdown 2. The quantity and individual pump capacity Demine ralizer of the circulating water pump 100% x 2

10. 4. 7 C o n d e n s a t e a n d F e e d w a t e r S y s t e m 10.4.6 Condensate Polishing System (CP)

To Condenser AB TGB Circulating Water Pump 10.4.8 Steam Generator 16.66% x 6 Blowdown System Cooling Tower (SGBS) 10.4.5 Circulating Water System Figure 10.1-2 Overall System Flow Diagram 10.1-12 Rev. 2

APR1400 DCD TIER 2 10.2 Turbine Generator The T/G specification will address the following criteria, as identified in Subsection 10.2.5 COL Items and as verified by ITAAC. By establishing functional requirements, COL items, and ITAAC, instead of specifying a specific design in the DCD, assurance is provided that each APR1400 will be equipped with the design that best meets reliability and then current regulatory expectations for the T/G, the TGCS, and the overspeed protection system.

10.2.1 Design Bases 10.2.1.1 Safety Design Bases The T/G system does not perform nor support any safety-related function and therefore has no safety design basis. Classification of the T/G system in regard to the seismic and safety and quality group is provided in Table 3.2-1 of Section 3.2.

However, because it is possible for the T/G system to generate high-energy missiles that could damage essential safety-related structures, systems, and components (SSCs), it is designed and controlled to minimize the potential for turbine missile generation. The T/G system is designed to meet the requirements of General Design Criterion (GDC) 4 as related to the protection of SSCs from the effects of turbine missiles described in Subsection 3.5.1.3.

10.2.1.2 Non-Safety Power Generation Design Bases The T/G converts the energy of the steam produced in the SGs into rotational energy and then into electrical energy. The principal design features of the T/G are as follows:

a. The T/G is designed for base load operation.

b. The T/G load change characteristics are compatible with the plant control system, which coordinates the T/G and reactor operations.

c. The main turbine system is designed for electric power production consistent with the capability of the reactor and the reactor coolant system.

d. The T/G is designed to be monitored and controlled automatically by the TGCS at normal or abnormal conditions, as described in Subsection 10.2.2.3. The TGCS 10.2-1 Rev. 2

APR1400 DCD TIER 2 includes redundant, diverse, and independent mechanical and electrical overspeed trip devices that trip the turbine at approximately 110 percent and 111.5 percent of the rated speed of T/G, respectively. The maximum expected overspeed of the turbine does not exceed 115 percent of the rated speed. The design overspeed of the T/G is at least 5 percent above the maximum expected overspeed resulting from a loss of load.

e. The main stop valves (MSVs), control valves (CVs), intermediate stop valves (ISVs), intercept valves (IVs), non-return valves, overspeed protection system, and other protection devices are designed to allow regular online testing of each protection device with minimum effect on the online turbine operation.

f. The T/G system is designed so that the single failure of any component or subsystem does not disable the turbine overspeed trip function.

g. The T/G system provides the proper drainage of related piping and components to prevent water induction to the inside the turbine.

h. The MSRs, MSR drain tanks, pressure vessels, and piping in the T/G auxiliary systems are designed to the requirements of ASME Section VIII (Reference 1).

The other parts of the T/G are designed to the T/G manufacturers standards.

i. Generator rating, temperature rise, and class of insulation are in accordance with Institute of Electrical and Electronics Engineers (IEEE) Standard C50.13 (Reference 2).

j. The T/G is designed to trip automatically under abnormal conditions.

10.2.2 Description 10.2.2.1 General Description The T/G system consists of an 1,800 rpm turbine, two sets of MSRs, generator, exciter, controls, and associated subsystems.

The TGCS uses a digital monitoring and control system that controls the turbine speed, load, and flow for startup and normal operations. The control system operates the turbine MSVs, CVs, ISVs, and IVs. T/G supervisory instrumentation is provided for operational analysis and malfunction diagnosis.

10.2-2 Rev. 2

APR1400 DCD TIER 2 The extraction steam piping is constructed of low-alloy steel such as Cr-Mo steel or equivalent material for erosion and corrosion resistance. The source of the extraction steam for feedwater heating at each stage is presented in Table 10.2.2-1.

Upon loss of load, the steam contained in piping downstream of the extraction lines can flow back into the turbine across the remaining turbine stages and into the condenser.

Associated condensate can flash to steam under this condition and contribute to the backflow of steam or can be entrained with the steam flow and damage the turbines. Non-return check valves are employed to minimize the potential for these conditions to contribute to the turbine overspeed. These valves are periodically tested.

The T/G foundation is a reinforced concrete structure. The T/G foundation and equipment anchorage are designed to the same seismic design requirement as the turbine building.

Additional information on seismic design requirements is provided in Section 3.7.

10.2.2.2 Component Description The T/G will consist of a double-flow high-pressure (HP) turbine, three double-flow low-pressure (LP) turbines, and a direct-coupled generator in tandem. Details of the design will depend on the unit selected by the COL applicant. The COL applicant is to identify the turbine vendor and model (COL 10.2(1)).

The typical valve and piping arrangements are shown in Figure 10.2.2-1. Two MSRs with two stages of reheating are located on each side of the T/G centerline. The single direct-driven generator is water-cooled and rated 1,425 MWe. T/G accessories include the bearing lubrication oil system, TGCS, turbine hydraulic system, turning gear, hydrogen gas control system, seal oil system, stator cooling water system, etc.

10.2.2.2.1 Main Stop Valves and Control Valves The flow of main steam is directed from the SGs to the HP turbine through four MSVs and four CVs. Each main stop valve is in series with a control valve.

MSVs are designed to incorporate a steam strainer to limit foreign material from entering the control valves and turbine. The primary function is to quickly shut off steam flow to the HP turbine under emergency conditions. MSVs are hydraulically operated in an open-closed mode by the turbine overspeed protection system in response to turbine trip signals.

10.2-3 Rev. 2

APR1400 DCD TIER 2 CVs are designed to provide steam flow throttling and shut-off that is adequate for turbine speed control. The primary function of the CVs is to control steam flow to the turbine in response to the TGCS. CVs are closed under trip conditions.

MSVs and CVs are hydraulically operated by a high-pressure fire-resistant fluid supplied through a servo valve. Typical valve characteristics and closure times are provided in Table 10.2.2-2. Each valve will have an actuator consisting of a spring, housing assembly, and control package. The control package contains the hydraulic cylinder, operating piston, disk dump valve, solenoid-operated trip line test valve, shutoff valve, and servo-valve. The actuator shall be designed to allow the valves to close rapidly on turbine trip.

If the hydraulic system fails, the hydraulic pressure will drop, and the valve will be closed by the spring force.

10.2.2.2.2 High-Pressure Turbine The HP turbine receives steam through four steam lines. The steam is expanded axially across several stages of stationary and moving blades. These stages consist of a blade-attached wheel and diaphragm structure. Extraction steam from the HP turbine at three locations is supplied to the fifth, sixth, and seventh stages of feedwater heaters, as described in Table 10.2.2-1. After expanding through the HP turbine, the exhaust steam passes through the MSRs.

10.2.2.2.3 Moisture Separator Reheaters The moisture in the HP turbine exhaust steam is separated and reheated by two sets of external MSRs. The MSRs are located on each side of the T/G centerline. Extraction from the HP turbine and main steam from the equalization header are supplied to the first and second stages of the reheater tube bundle in each reheater.

The MSRs use multiple banks of chevron-skip vanes for moisture removal. The moisture is removed by the external moisture separator.

Condensed steam in the reheater, which is drained to the reheat drain tank, flows into the shellside of the fifth, sixth, and seventh feedwater heaters and cascades to the deaerator.

10.2-4 Rev. 2

APR1400 DCD TIER 2 10.2.2.2.4 Intermediate Stop Valves and Intercept Valves Hydraulically operated ISVs and IVs are provided in each hot reheat line upstream of the LP turbine inlet. Each intermediate stop valve is in series with an intercept valve.

Upon loss of load, the IVs first close and then throttle steam to the LP turbine to control speed. The ISVs and IVs close on a turbine trip. The ISVs and IVs are designed to close rapidly to control turbine overspeed. Typical valve characteristics and closure times are provided in Table 10.2.2-2.

10.2.2.2.5 Low-Pressure Turbine Each LP turbine receives steam from the MSRs through two hot reheat lines. The steam expands axially across several stages of stationary and moving blades.

The steam then passes through the LP turbines, each with extraction points for the LP stages of feedwater heating, and exhausts into the main condenser. Extraction steam from the LP turbines supplies the first stages of feedwater heating.

Condensate moisture from the moving blade at the latter stages is removed along the moisture groove. Drainage holes are drilled through the diaphragm rings to remove the moisture generated from the diaphragm rings located in high wet zones.

10.2.2.2.6 Extraction Non-Return Check Valve Non-return check valves are installed on extraction lines as shown in Figure 10.2.2-1.

Valves in the higher-pressure extraction lines are power-assisted, spring-closed, non-return check valves. The spring-closed actuators are designed to overcome friction and allow the valves to close rapidly on turbine trip. These non-return check valves are capable of closing within a time period to maintain stable turbine speeds in the event of a T/G system trip. Typical non-return check valve characteristics and closure times are provided in Table 10.2.2-2. The two low-pressure heaters and their associated extraction lines are located in the condenser neck. The no. 3 heaters are installed horizontally in the heater bay. Because of the low energy levels of the entrained fluid in the two lowest-pressure heaters, no. 2 heaters are provided with anti-flash baffle plates located inside the heaters.

10.2-5 Rev. 2

APR1400 DCD TIER 2 10.2.2.2.7 Generator The generator is a direct-driven, three-phase, 60 Hz, 1,800 rpm, four-pole synchronous generator with a water-cooled armature winding and hydrogen-cooled rotor. Generator rating, temperature rise, and class of insulation are in accordance with IEEE Standard C50.13.

The generator rotor is manufactured from forged components and includes layers of field windings embedded in milled slots. The windings are held radially by slot wedges at the rotor outside diameter. The wedge material maintains its mechanical properties at elevated temperatures. The magnetic field is generated by direct current (DC) power, which is fed to the windings through collector rings located outboard of the main generator bearings.

The generator rotor will be machined from a single, solid steel forging. Detailed examinations include:

a. Material property checks on test specimens taken from the forging

b. Magnetic particle and ultrasonic examination

c. Visual surface finish inspections of rotor slots for indication of a stress riser 10.2.2.2.8 Generator Cooling System The generator cooling system consists of a hydrogen gas cooling system, seal oil system, and stator winding water-cooling system.

A conventional oil-sealed hydrogen cooling system provides rotor cooling. The stator conductors are water cooled by a stator water cooling system.

The generator oil sealing system is designed to prevent hydrogen gas inside the generator from leaking, and pressure is maintained higher than the hydrogen gas pressure inside the generator through the generator seal oil system.

The generator stator winding water-cooling system is designed to control the cooling water pressure and flow through the stator winding cooling water system to prevent the temperature inside the generator from increasing.

10.2-6 Rev. 2

APR1400 DCD TIER 2 The hydrogen detraining system treats the oil that has drained from the casing through the seal ring. This system consists of a hydrogen detraining tank, which stores the seal oil from inside the generator; a liquid detector, which prevents the overflow of seal oil in the detraining tank; and a float trap, which recovers the atmosphere condition of hydrogen-side seal oil.

Hydrogen is supplied from high-pressure storage tanks and an electrolysis hydrogen and oxygen generator. In order to prevent explosions and fires, the hydrogen piping and main generator are checked for leaks and then purged with carbon dioxide to remove all air and oxygen before the introduction of hydrogen. The hydrogen purged from the generator is vented through the T/G building roof and dissipates to the outside air. Provisions are included at various points in the distribution system to allow for carbon dioxide purging and safe venting of the hydrogen in the generator and piping prior to maintenance.

10.2.2.2.9 Generator Exciter The excitation system regulates the generator terminal voltage. This system is a static bus-fed type and consists of a 3-phase full-wave rectifier, excitation transformer, and AC/DC bus duct. Excitation power can be obtained from an excitation transformer, which is connected directly to the generator terminals. The excitation system, generator field, and excitation transformer are connected by the AC/DC bus duct to each other.

The secondary side of the excitation transformer is connected to the 3-phase full-wave rectifier. The 3-phase full-wave rectifier uses a thyristor, which is a semiconductor device for power conversion from AC to DC.

10.2.2.3 Control and Protection 10.2.2.3.1 Normal Control The TGCS is a digital monitoring and control system that controls turbine speed, load, and flow for startup and normal operations. The TGCS operates the turbine MSVs, CVs, ISVs, and IVs. T/G supervisory instrumentation is provided for operational analysis and malfunction diagnosis.

The TGCS combines the capabilities of redundant digital processing and high-pressure hydraulics to regulate steam flow through the turbine. Valve-opening actuation is provided by a hydraulic system that is independent of the bearing lubrication system.

10.2-7 Rev. 2

APR1400 DCD TIER 2 Valve-closing actuation is provided by springs and steam forces in the event of a reduction in or relief of fluid pressure. The system is designed so that loss of fluid pressure, for any reason, leads to valve closing and a consequent turbine trip.

Electric power for the TGCS and protection system is supplied by two AC sources for redundancy with a 120V AC single-phase station source and a vital control bus from uninterruptible power source (UPS) or other reliable source.

The TGCS contains the following components:

a. Three redundant speed inputs

b. Three redundant control processors

c. Redundant communication paths between processors within the TGCS

d. Redundant communication paths for each turbine and generator from the TGCS main control cabinet to the operator workstation

e. Redundant communication paths within the TGCS connecting to the plant control system The TGCS is digital (e.g., microprocessor, field programmable gate array) and provides the following turbine control functions through circuitry and hydraulics:

a. Automatic control of turbine speed and acceleration through the entire speed range

b. Automatic control of load and loading rate from no load to full load, with continuous load adjustment and discrete loading rates

c. Semi-automatic control of speed and load when it becomes necessary to take portions of the automatic control out of service while continuing to supply power to the system

d. Limiting of load in response to preset limits on operating parameters

e. Detection of transients with the potential to damage a turbine, annunciation of detected conditions, and initiation of proper control response to such conditions 10.2-8 Rev. 2

APR1400 DCD TIER 2

f. Monitoring of the status of the control system, including the power supplies and redundant control circuits

g. Testing of valves and controls The above described features and those in the following sections are functional requirements to be used in selecting an appropriate turbine and TGCS. The COL applicant is to identify how the functional requirements as described in Subsection 10.2.2.3.2 for the overspeed protection system are met and provide schematic(s) of the TGCS and overspeed protection systems that show the entire system end-to-end and all discrete components and interfaces (e.g., sensors, power supplies, control devices, manual emergency trips, the device that eventually drains the hydraulic/air fluid from turbine control valves). The schematics and descriptive information provided once a turbine design is selected shall be sufficient to allow assessment of the TGCS and overspeed systems' ability to withstand a single failure without loss of function (i.e., redundancy),

resistance to common cause failure (i.e., diversity as provided by electrical and mechanical overspeed trips), and resistance of propagation of a failure to another trip channel (i.e.,

independence, separation) (COL 10.2(2)).

A simplified, generic schematic is provided by Figure 10.2.2-2.

10.2.2.3.1.1 Speed Control The turbine speed is measured by three independent speed sensors using technology different from those used for the electrical overspeed trip. For overspeed protection, each module provides a binary output signal, which is normally energized, to the 2-out-of-3 tripping device.

For speed control, the three speed sensors provide signals for the turbine rotation rate.

The three signals are input to three separate speed detection modules, each located on three separate I/O branches. Each of these modules has an onboard processor that converts the sensor input to a turbine rpm value. Independence of the three speed sensor signal branches is assured in that failure of the transmission of one branch of the signal does not affect the transmission of the signal in the other two branches. Each I/O branch is separately fused. Also, failure of a speed detection module (receiving one branch of the signal) does not affect the function of the remaining two speed detection modules from receiving their signals.

10.2-9 Rev. 2

APR1400 DCD TIER 2 The speed control function of the turbine control and protection systems redundant controller provides speed control and acceleration functions for normal turbine operation.

The speed error signal is derived by comparing the desired setpoint speed with the actual speed of the turbine. This error drives an algorithm that positions the control valves at the desired position. Acceleration rates can also be entered by the operator or calculated by the control system in the auto startup mode. A failure of one speed input generates an alarm. Failure of two or more speed inputs also generates an alarm and trips the turbine.

The speed governor closes all CVs and IVs fully at approximately 103 percent of the turbine normal operating speed. An acceleration limiter built into the digital based controller is activated during a high load rejection. The valves are fully closed at 103 percent.

10.2.2.3.1.2 Load Control Load control is used during normal operation to maintain power output steady. Control of all turbine control valves is done with redundant control processors. The load control function of the TGCS generates signals that are used to regulate the unit load. The signal outputs are based on maintaining the proper combination of speed error and load reference signals.

Automatic controls are provided to avoid unnecessary turbine trip and to permit subsequent operation at house load (i.e., load required to run station auxiliaries) in the event of a loss of load from 100 percent power. Also, automatic action is provided to balance the TG loads following a small, brief mismatch between generator load and generator power, without loss of synchronization during load mismatch transients, up to full power.

Control logic provides reasonable assurance that the necessary conditions have been satisfied prior to changes in mode of operation, to communicate status information between the load control unit and other elements of the TGCS, and to provide switching signals to devices in the TGCS.

10.2.2.3.1.3 Flow Control When the output flow reference signal is at the limit value, the load set runback is initiated to drop the load setpoint. To prevent an excessive decrease of the main steam pressure, a main steam pressure limiter circuit is provided to close the controlling valve set when the main steam pressure falls below a preset level. The regulation of this circuit is fixed at 10 percent. When the main steam pressure falls below an adjustable setpoint, the flow 10.2-10 Rev. 2

APR1400 DCD TIER 2 reference signal to the controlling valve set is limited to the value permitted by the level of the main steam pressure. The pressure setpoint is adjustable from zero to rated pressure by using the keyboard or cursor-positioning device on the control console in the control room. Control room displays show the pressure setpoint that has selected, as well as the actual main steam pressure. An acceleration limiter operates when the field breakers open and the turbine acceleration is too high.

First-stage feedback is incorporated into the control system to provide more linear turbine response to the desired load signal and to maintain near constant turbine output while testing control valves.

The turbine and its CVs are designed to pass the rated flow at the existing throttle pressure at the MSVs and CVs at the rated output of the nuclear steam supply system (NSSS). The load control function and maximum load limiter function are protected against overload.

The feedback of live steam pressure is provided for a constant control gain.

All stop valves are hydraulically operated from the common hydraulic safety system equipped with limit switches for stroke testing.

10.2.2.3.1.4 Valve Control The CVs position loop consists of electrical circuitry, an electro-hydraulic servo-valve, hydraulic actuator, and linear position transducer. By use of a valve position feedback control, the control valve flow control unit positions the CVs according to the flow demand signal from the load control unit or directly from the control panel. Valve position control is performed by using a feedback path that transmits the actual valve position back to a point where it is compared algebraically with the reference input. The error signal positions the hydraulic actuator using the servo-valve to make it zero value. CV testing is designed to allow regular testing of each valve with the effects to the online turbine operation minimized. This testing is performed by the position controller using the integrated servo-valve.

IVs are equipped with a position controller and a servo-valve.

Three control processors can control servo valves with up to three coils. These control processors are connected to each coil. In a failure of a controller, its output port or the physical connection to the output coil results in the other two servo drives compensating for the failed channel and keeping the valve properly positioned.

10.2-11 Rev. 2

APR1400 DCD TIER 2 The flow of main steam entering the HP turbine is controlled by four MSVs and CVs.

Each MSV is either fully open or fully closed by an electro-hydraulic actuator. The MSVs shut off the steam flow to the turbine when required, such as for actuation of the electrical overspeed trip. The CVs are positioned by electro-hydraulic servo actuators in response to signals from their individual flow control unit. The flow control unit positions the CVs for wide-range speed control through the normal turbine operating range and for load control after T/G synchronization.

The intermediate stop (ISVs) and intercept valves (IVs), located in the hot reheat lines at the inlet of the LP turbines, control steam flow to the LP turbines. During normal operation of the turbine, they are fully open. The IV flow control unit positions the valve during startup and normal operation and closes the valve rapidly on loss of turbine load.

The IVs and ISVs close completely on turbine overspeed and turbine trip.

Typical valve characteristics and closure times are provided in Table 10.2.2-2.

10.2.2.3.1.5 Power Load Unbalance If the T/G is running at load and the load on the generator is suddenly lost, the following events take place in rapid succession:

a. The acceleration limiter operates on high acceleration.

b. The CVs and IVs are closed at the maximum rate.

c. The entrained steam between the valves and the turbine, in the turbine casing, and in crossover and extraction lines expands.

d. The expected overspeed is less than 10 percent at full load.

e. The IVs reopen when the actual speed is below the set value.

If the above sequence is not successful, the TGCS overspeed protection device is activated to protect the T/G. The main steam is bypassed to the condenser to reduce steam flow to the turbine (see Subsection 10.4.4).

10.2-12 Rev. 2

APR1400 DCD TIER 2 10.2.2.3.1.6 Automatic Turbine Startup and Shutdown The automatic turbine startup (ATS) receives commands from the operator using the operator interface or from a plant computer through a data link, compares it to the limits, and issues commands to the primary controllers. ATS routines are executed during all modes of operation. ATS routine results are used directly or also displayed during all modes of operation.

The primary mode of communication between the ATS and the operator is through the operator interface displays.

The ATS has the following phases:

a. Pre-roll monitoring and operation

b. Acceleration to the rated speed

c. Loading and unloading

d. Post-trip securing 10.2.2.3.2 Overspeed Protection The normal speed control system serves as the first line of defense against turbine overspeed. This system includes CVs, IVs, and fast-acting valve-closing functions within the TGCS. The TGCS begins to close the control and intercept valves at about 101 percent of the rated speed and completely closes the valves at 103 percent. If this system fails to prevent the overspeed, the overspeed protection system is activated to prevent overspeed. The overspeed protection system consists of two major subsystems: (1) a mechanical overspeed trip system (MOTS) in the front standard and (2) an electrical overspeed trip system (EOTS), which each cause the turbine steam valves to shut through the action of the emergency trip system (ETS).

The MOTS, upon reaching a setpoint that is approximately 110 percent of the rated speed, acts to bring the turbine to a safe shutdown condition. It consists of an unbalanced weight that is activated by a centrifugal force against a spring when the turbine overspeeds, thus causing an eccentric movement that mechanically opens the emergency trip valve. If the MOTS fails, the EOTS will activate the ETS trip valves, causing all steam valves to trip closed upon reaching the setpoint.

10.2-13 Rev. 2

APR1400 DCD TIER 2 The EOTS consists of two speed calculating modules: a primary and backup. Each module uses the three signals from passive magnetic speed sensors that are diverse and independent from the TGCS sensors and the speed conditioning units to the 2-out-of-3 tripping device. The primary module and secondary module calculate the trip setpoint in a diverse manner, with one using software logic, and the other using module firmware, which is independent of the primary module. These modules trigger hydraulic solenoid valves, and all stop and control valves are then closed. Each setpoint is 111.5 percent of the rated speed. The turbine is not expected to exceed 115 percent of the rated speed.

Following is a detailed functional performance description of the TGCS, MOTS, and EOTS.

a. Redundant, in-series turbine steam valves are used on each line admitting steam to the high and low pressure turbines. These are the MSVs and CVs for the high pressure turbine, and the ISV and IVs for the low pressure turbines. Each of these valves fail closed (held open by hydraulic control oil pressure maintained by a closed dump valve).

b. Closure of the turbine steam valves is accomplished by draining hydraulic control oil holding the dump valves closed, allowing the springs to shut each steam valve.

c. Draining hydraulic control oil from the MSVs and ISVs is accomplished by activating any of the three overspeed trips. Specifically:

1) Normal control system - receipt of a valid trip energizes the solenoid operated fast-acting valves, which drain off hydraulic control oil from each dump valve.

2) MOTS - movement of mechanical linkages repositions the mechanical trip valve, draining hydraulic control oil. A trip can occur for any of the following reasons:

a) Mechanical (i.e., rotating inertia increasing due to rising rotational speed) turbine trip that moves the trip linkages b) Emergency manual trip activation at the turbine front standard by de-energizing a solenoid that moves the trip linkages c) Emergency manual trip activation from the control room by de-energizing a solenoid that moves the trip linkages 10.2-14 Rev. 2

APR1400 DCD TIER 2

3) EOTS - trip signals are processed by both a primary and backup unit to determine trip validity based on 2-out-of-3 voting, either of which then opens contacts to de-energize both solenoids of the master trip valve. This allows the master trip valve to reposition due to spring force, draining hydraulic control oil.

d. Draining hydraulic control oil from the CVs and IVs is accomplished when draining of hydraulic control oil pressure described in c. above also allows a spring to reposition a valve, which drains hydraulic control oil from the separate CV/IV header.

e. An extraction relay dump valve under normal operating conditions aligns the incoming instrument air supply to the operators of air-assisted, spring-closed, non-return valves in the higher-pressure extraction lines to hold them open. The non-return check valves close rapidly on turbine trip when the extraction relay dump valve vents air. Typical characteristics and closure times are provided in Table 10.2.2-2, but the number of valves, their closing times, and detailed design will be in accordance with the turbine manufacturer's requirements and the requirements of ANSI/ASME TDP-1-1998. Although held open by air, the valve closes as a non-actuated swing check valve. The design allows periodic trip confirmation.

f. The balance of the hydraulic control oil system must fulfill the following requirements:

1) Drains - Control oil from the valve actuators is collected in two stainless steel drain headers. There is one header for the MSVs (ISVs for low pressure turbines) and one for the CVs (IVs). These two headers drain to the hydraulic power unit reservoir through a common drain line. The drain headers are sized to handle the maximum hydraulic control oil flow requirements, maintaining the required valve stroke times, and are sloped to drain to the reservoir.

2) Failure of the hydraulic piping between the trip block and the valve actuator, or between the hydraulic fluid tank and the valve actuator will cause a loss of fluid pressure, which closes the turbine steam valves.

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3) The hydraulic fluid in the trip and overspeed protection control headers is independent of the bearing lubrication system to minimize the potential for contamination of the fluid.

The turbine overspeed trips close all stop and control valves within a certain period after a trip signal that precludes an unsafe turbine overspeed condition, as described in Table 10.2.2-3.

To further decrease the possibility of an overspeed condition, two redundant reverse-power relays prevent overspeed after a turbine trip and prevent overheating of the last stages of LP turbine blades. Additionally, a T/G protection device interfaces with the main steam bypass system, which bypasses main steam to the condenser to reduce steam flow to the turbine (see Subsection 10.4.4).

The turbine overspeed protection devices are listed in Table 10.2.2-3. Each device has an on-load test provision.

In case of malfunction of the normal speed control system coincident with a loss of generator load, the turbine accelerates and the mechanical and electrical overspeed trip systems activate at 110 percent and 111.5 percent of the rated speed, respectively, and trip the MSVs, ISVs, and non-return valves as the second and third lines of defense, respectively. The main CV and IV actuators also close. Subsequently, the turbine coasts down.

The main function of the ETS is to check the validity of the trip demand signals and to provide high assurance that trip action results in immediate response to a valid trip demand.

The turbine includes instrumentation for a trip on excess vibration and a remote trip input signal from the plant control system on a reactor trip.

The trip and monitoring system initiates appropriate action on abnormal operating conditions and indicates the existence of these conditions to the operator.

The ETS closes the MSVs, CVs, ISVs, and IVs to shut down the turbine on the following signals:

a. Manual emergency trip in control room

b. Moisture separator high level 10.2-16 Rev. 2

APR1400 DCD TIER 2

c. High condenser pressure

d. Low turbine lube oil pressure

e. LP turbine exhaust hood high temperature

f. Thrust bearing wear

g. Manual emergency trip at front standard

h. Loss of stator coolant

i. Low hydraulic fluid pressure

j. Selected generator trips

k. Loss of TGCS electrical power

l. Excessive turbine shaft vibration

m. Loss of two speed signals - either two normal speed control or two emergency

n. Abnormal shell and rotor differential expansion or rotor expansion When the ETS is activated, it overrides all operating signals and trips the MSVs, CVs, ISVs, and IVs.

The manual emergency trip shall be designed such that no single failure (e.g., push button) will prevent a manual trip and that failure of the ETS to initiate an automatic trip does not prevent a successful manual trip. The physical implementation (e.g., hard wiring) shall be included in the schematic required by COL 10.2(2).

The fundamental design principles are met as follows:

Diversity

a. A purely mechanical overspeed trip is available in conjunction with the normal control and electrical overspeed trips. The mechanical trip valve does not depend on availability of electric power (power is required to keep the mechanical trip solenoid valve energized to prevent the manual trip valve from draining hydraulic control oil).

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b. The TGCS and EOTS use diverse speed inputs, determine trip validity using different technology, have different set points, and actuate to drain hydraulic control oil, to eliminate common cause failures from rendering the trip functions inoperable. The MOTS senses speed via physical repositioning of an eccentric weight, rather than counting rotations per unit time.

Separation

a. The ETS valves are located in the turbine front standard out of the way of turbine missiles and high pressure steam lines, whereas the TGCS solenoid-operated fast-acting valves are part of the main steam valve actuators.

b. The TGCS overspeed trip controllers and the EOTS primary and backup processors are located in different instrument cabinets.

c. Hydraulic control oil drain headers for MSVs and CVs and for ISVs and IVs are separate and separated on opposite sides of the turbines.

Redundancy

a. Each turbine steam inlet line has two valves (e.g., MSV and CV for high pressure turbine), closure of any one in each pair isolates that line.

b. Failure of any one component in overspeed protection systems will not prevent a turbine trip.

Independence

a. The normal control overspeed system, EOTS, and MOTS each determine turbine speed using independent means: diverse TGCS speed sensors, passive magnetic speed sensors, and rotational acceleration (centrifugal force).

b. A failure of one of the overspeed protection systems will not propagate to the others because they are electrically isolated and physically separated.

c. Closure or lack of closure of one of the series turbine steam valves (e.g., MSV and CV) will not prevent the other valve from closing within its timing requirements to prevent overspeed.

10.2-18 Rev. 2

APR1400 DCD TIER 2 Single failure criterion Single failures are addressed through redundancy and independence, but additionally: No single failure will cause a turbine to overspeed. This feature is desirable since the best way to protect for an overspeed is to designate TGCS features that assure no single failure can initiate the transient.

Fail safe

a. Upon loss of power, valves transition to positions where hydraulic control oil is drained, tripping shut all turbine steam valves.

b. If a speed sensor fails, it is removed from the voting logic, leaving two out of two trip logic. If two speed sensors fail, a turbine trip is initiated.

c. Relays that provide the interface between the TGCS and the EOTS controllers and the valves of the hydraulic control and protection systems fail in a fail safe position on a loss of power.

Testability

a. Test valves and relays are provided to allow any turbine steam valve to be tested during operation.

b. Overspeed sensors, controllers, and trips are fully testable during normal operation.

c. To avoid the possibility that a test alignment error could block a trip and due its simplicity, the mechanical overspeed protection trip is not provided a means to test during operation. Instead, the turbine manual switches and associated linkages are tested during refueling outages prior to turbine start-ups or if maintenance work could have affected functionality.

The normal overspeed and EOTS controllers and relays are installed in separate cabinets; electric power for each is supplied by two AC sources for redundancy with a 120V AC single-phase station source and a vital control bus from a UPS or other reliable source.

10.2-19 Rev. 2

APR1400 DCD TIER 2 10.2.2.3.3 Inspection and Testing The overspeed trip circuits and devices are tested remotely at or above the rated speed by means of controls in the main control room and can also be tested with the turbine not in operation. Operation of the overspeed protection devices under controlled speed conditions is checked at startup and after each refueling or major maintenance outage. In some cases, operation of the overspeed protection devices can be tested just prior to shutdown. This eliminates the need to test overspeed protection devices during the subsequent startup if no maintenance is performed that affects the overspeed trip circuits and devices.

Inservice testing and functional checks are performed periodically as required by the vendor and by the turbine missile probability analysis. MSVs, CVs, ISVs, and IVs are exercised by closing each valve and observing the remote valve position indicator for fully closed position status. This test also verifies operation of the fast close function of each MSV and CV during the last few percent of valve stem travel. Fast closure of the ISV and IV is tested in a same way. Non-return check valves are tested in accordance with vendor recommendations. Inspection and test requirements for the overspeed trip device are as required by the turbine missile probability analysis.

The checks include testing of components such as:

a. MSVs, CVs, ISVs, and IVs

b. Turbine trips and pressure switches for lube oil supervision

c. Electrical overspeed trips

d. Vacuum trips

e. Extraction power-assisted check valves

f. The control fluid pressure switch

g. All control devices and positioning of control valves

h. The mechanical overspeed trip device

i. Each lube oil pump 10.2-20 Rev. 2

APR1400 DCD TIER 2 10.2.3 Turbine Rotor Integrity Turbine rotor integrity is provided by the integrated combination of material selection, rotor design, fracture toughness requirements, tests, and preservice and inservice inspection.

This combination results in a low probability of a condition that would cause a rotor failure.

The COL applicant shall identify the turbine vendor and model. Also, the COL applicant is to provide a description of how the turbine missile probability analysis conforms with Subsection 10.2.3.6 to ensure that requirements for protection against turbine missiles (e.g.,

applicable material properties, method of calculating the fracture toughness properties per SRP, Section 10.2.3, Acceptance Criteria, preservice inspections, in-service tests and inspections) will be met. If the turbine vendor has performed a turbine missile analysis that has been reviewed and approved by the NRC for a rotor design relevant to the COL applicant's selected design, then the COL applicant should reference the analysis. If an approved analysis is not available, then the COL applicant shall prepare and reference an analysis that provides confidence that the final analysis performed with as-built properties, when available, will be sufficient to demonstrate assurance of turbine rotor integrity (COL 10.2(3)).

The as-built turbine material properties, turbine rotor and blade designs, pre-service inspection and testing results and in-service testing and inspection requirements shall be verified by ITAAC to meet the requirements defined in the turbine missile probability analysis.

10.2.3.1 Material Selection Turbine rotor forgings are made from vacuum treated or remelted Ni-Cr-Mo-V alloy steel components using processes that minimize flaw occurrence, provide reasonable assurance of uniform strength, and provide adequate fracture toughness. Undesirable elements, such as sulfur and phosphorus, are controlled to the lowest practicable concentrations consistent with good feedstock selection and melting practice, and consistent with obtaining adequate initial and long-life fracture toughness for the environment in which the parts operate.

The turbine rotor material conforms with the chemical property limits of ASTM A470 (Reference 3). The chemical composition of manufacturers material for the rotor steel has lower or equal limitations than indicated in the ASTM standard for phosphorous, sulphur, and antimony as described in Table 10.2.3-1. The rotor forgings are heat treated and tested prior to the final machining process.

10.2-21 Rev. 2

APR1400 DCD TIER 2 10.2.3.1.1 Integral/Monoblock Rotor These turbine designs utilize rotors produced from large integral forgings. Acceptable material properties will be consistent with component size and fabrication method.

Material testing has shown that fracture appearance transition temperature (FATT) increases (and Charpy V-notch energy decreases) from the outer surface to the deep-seated region of a forging as a result of variation (slowing from outside to center) in the cooling rate during the quenching process. The cooling rate variation causes the FATT (and Charpy V-notch energy) to vary rapidly with depth near the surface of the forging and then more gradually at deeper forging locations. Since actual levels of the 50 percent FATT and Charpy V-notch energy vary depending upon the size of the part, and the location within the part, etc.,

these variations are taken into account in accepting specific forgings for use.

The COL applicant shall specify the turbine rotor material properties for the chosen turbine vendor and applicable for the specific rotor designs. The COL applicant shall specify the turbine rotor material properties (in terms of the 50% FATT and Charpy V-notch energy tests performed in accordance with ASTM A-370 (Reference 4)) for the chosen turbine vendor and applicable for the specific rotor designs. Any deviation from material properties in SRP 10.2.3, revision in effect on date of regulatory applicability for COL application, shall be identified and justified (COL 10.2(4)).

10.2.3.1.2 Welded Rotor The COL applicant shall specify the turbine rotor material properties for the chosen turbine vendor and applicable for the specific rotor designs. The COL applicant shall specify the turbine rotor material properties (in terms of the 50% FATT and Charpy V-notch energy tests performed in accordance with ASTM A-370) for the chosen turbine vendor and applicable for the specific rotor designs. Any deviation from material properties in SRP 10.2.3, revision in effect on date of regulatory applicability for COL application, shall be identified and justified (COL 10.2(4)).

10.2.3.1.3 Shrunk-on Disk The 50 percent FATT, as obtained from Charpy tests performed in accordance with ASTM A-370, is no higher than -18ºC (0ºF) for low-pressure turbine wheel (disc) forgings, and the Charpy V-notch energy at the minimum operating temperature is at least 8.3 kg-m (60 ft-lbf) in the tangential direction. Any deviation from material properties in SRP 10.2.3, revision 10.2-22 Rev. 2

APR1400 DCD TIER 2 in effect on date of regulatory applicability for COL application, shall be identified and justified (COL 10.2(4)).

10.2.3.2 Fracture Toughness The proper toughness of the turbine rotor is obtained through the use of selected materials as described in Subsection 10.2.3.1. High reliability and availability, efficiency, and safety are satisfied by keeping the balance between the strength and toughness of the turbine rotor.

The fracture toughness KIC for actual rotor product is determined using a value of deep-seated FATT based on the measured FATT values from the center bore or trepan specimens from the rotor forging, and a correlation factor obtained from the past manufactured rotor material test data, and generated statistically lower bound of the data.

As part of the turbine missile probability analysis, the COL applicant is to identify which of the methods for determining fracture toughness properties of those allowed in SRP Section 10.2.3 acceptance criteria is used.

The fracture toughness KIC is evaluated to prevent brittle fracture of the turbine rotor. The operating temperature of the turbine rotor is higher than the FATT. The centrifugal forces and thermal gradients are considered in the calculation of turbine rotor bore stress. The ratio of the fracture toughness of the rotor material at an operating temperature to the maximum tangential stress at 120 percent of the rated speed, is at least 10mm (2in.).

When required, sufficient warmup time or other procedures are specified in the turbine operating instructions to ensure that the above ratio of fracture toughness to stress intensity is maintained during all phases of anticipated turbine operation.

10.2.3.3 Preservice Inspection The preservice inspection program has the following features:

a. Rotor forgings are rough machined with minimum stock allowance prior to heat treatment

b. Each finished rotor is subjected to 100 percent volumetric (ultrasonic), surface, and visual examinations using procedures and acceptance criteria equivalent to those specified for Class 1 components in the ASME Code, Sections III 10.2-23 Rev. 2

APR1400 DCD TIER 2 (Reference 5) and V (Reference 6). Before welding and/or brazing, all surfaces prepared for welding and/or brazing will be surface examined. After welding and/or brazing, all surfaces exposed to steam will be surface examined, giving particular attention to stress risers and welds. Welds will be ultrasonically examined in the radial and radial-tangential sound beam directions.

c. The fracture analysis is conservative. The result of the fracture analysis is acceptable when the fracture toughness is greater than the stress intensity factor of the maximum final growth crack or the critical crack size is greater than the maximum final growth size after the guaranteed lifespan. These criteria are more restrictive than the criteria for Class 1 components in ASME Section III and components in ASME Section V. The criteria include the requirement that subsurface ultrasonic indications be removed or evaluated to provide reasonable assurance that any cracks will not increase enough to compromise the integrity of the unit during its design life.

After final machining, all surfaces exposed to steam (i.e., all accessible surfaces except for shaft ends) are magnetic particle tested. Special attention is given to the areas of stress raisers. Finish-machined bores, keyways, and drilled holes are subjected to magnetic particle or liquid penetrant examination. No flaw indications in keyway or hole regions are allowed. Either ultrasonic examination of turbine rotor welds or an analysis that demonstrates that defects in the root of the rotor welds will not grow to critical size for the life of the rotor is performed.

Each fully bucketed turbine rotor assembly is spin tested for 3 minutes at 120 percent of the rated speed. This speed is 5 percent greater than the maximum speed anticipated following a turbine trip from full load.

10.2.3.4 Turbine Rotor Design The turbine rotor assembly is designed to withstand normal conditions and anticipated transients, including those resulting in turbine overspeed trips, without loss of structural integrity. The design of the turbine assembly meets the following criteria:

a. The combined stresses of the turbine rotor at design overspeed resulting from centrifugal forces and thermal gradients do not exceed 0.75 of the minimum specified yield strength of the material.

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b. Turbine shaft bearings are designed to withstand a turbine trip after a loss of a complete last stage blade together with its root. For this reason, the bearings are able to withstand any combination of normal operating loads and anticipated transients.

c. The multitude of natural critical frequencies of the turbine shaft assemblies existing between zero speed and 20 percent overspeed are controlled in the design to prevent distress to the unit during operation.

d. The turbine rotor assembly is designed and tested to withstand the stresses corresponding to an overspeed level of 120 percent of the rated speed. This speed is 5 percent above the maximum expected speed resulting from loss of load.

The final overspeed basis and setpoints are included with the turbine missile probability analysis.

e. The turbine rotor design facilitates inservice inspection of high-stress regions.

f. The turbine missile probability analysis described in Subsection 10.2.3.6 contains additional descriptions of the design features of the turbine, rotor, shaft, couplings, and blades, including the number of stages, blade design, how the blades are attached to the rotor, how the turbine rotor is forged, and pertinent fabrication methods. Informational drawings are included as required to illustrate important design features.

g. The turbine missile probability analysis described in Subsection 10.2.3.6 includes an analysis of turbine component loading. The analysis includes rotor and blade loading combinations. The analysis shows that the rotor and blades have adequate margin to withstand loadings imposed during postulated overspeed events up to 120 percent of rated speed without detrimental effects.

10.2.3.5 Inservice Inspection The turbine and turbine valve inservice test and inspection program includes scope, frequency, methods, acceptance, disposition of reportable indications, corrective actions, and technical basis for inspection frequency. In-service test, inspection, and operating procedures shall be verified by ITAAC to be in accordance with industry practice and to ensure the validity assumptions/input of turbine missile probability analysis report.

10.2-25 Rev. 2

APR1400 DCD TIER 2 The inspections are performed during refueling outages on an interval consistent with the inservice inspection schedules in ASME Section XI (Reference 7) and the inspection intervals from the turbine manufacturers turbine missile analysis provided by the COL applicant as described in Subsection 3.5.1.3. The COL applicant shall provide the site-specific turbine rotor inservice inspection program and inspection interval, including the turbine valve test and inspection program and test and inspection frequency consistent with the manufacturers turbine missile analysis (COL 10.2(5)).

The inspection includes a complete inspection of all normally inaccessible parts, such as couplings, coupling bolts, LP turbine rotors, LP turbine buckets, and HP turbine rotor.

The inspection consists of visual, surface, and volumetric examinations.

The inservice inspection of MSVs, CVs, ISVs, and IVs includes the following description.

At intervals in accordance with vendor recommendations and as supported by the turbine missile probability analysis, during refueling or maintenance shutdowns coinciding with the inservice inspection schedule required by ASME Section XI for reactor components, at least one MSV, one CV, one ISV, and one IV is dismantled, and visual and surface examinations are conducted of valve seats, disks, and stems. If unacceptable flaws or excessive corrosion are found in a valve, all other valves of that type are dismantled and inspected. Valve bushings are inspected and cleaned, and bore diameters are checked for proper clearance. Non-return check valves are inspected by an inspection program in accordance with vendor recommendations as supported by the turbine missile probability analysis.

10.2.3.6 Turbine Missile Probability Analysis An analysis containing an evaluation of the probability of turbine missile generation is referenced by the COL applicant. The report provides a calculation of the probability of turbine missile generation using established methods and industry guidance applicable to the fabrication technology employed. The analysis is a comprehensive report containing a description of turbine fabrication methods, material quality and properties, and required maintenance and inspections that addresses:

a. The calculated probability of turbine missile generation from material and overspeed related failures based on as-built rotor and blade designs and as-built material properties (as determined in certified testing and nondestructive examination [NDE])

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b. Maximum anticipated speed resulting from a loss of load, assuming normal control system function without trip

c. Overspeed basis and overspeed protection trip setpoints

d. Discussion of the design and structural integrity of turbine rotors

e. An analysis of potential degradation mechanisms (e.g., stress corrosion cracking, pitting, low-cycle fatigue, corrosion fatigue, erosion and erosion-corrosion), and any specific maintenance or operating requirements necessary to mitigate the them

f. Material properties (e.g., yield strength, stress-rupture properties, fracture toughness, minimum operating temperature of the high-pressure turbine rotor) and the method of determining those properties

g. Required preservice test and inspection procedures and acceptance criteria to support calculated turbine missile probability

h. Actual maximum tangential and radial stresses and their locations in the low-pressure turbine rotor

i. Rotor and blade design analyses, including loading combinations, assumptions and warmup time, that demonstrate sufficient safety margin to withstand loadings from postulated overspeed events up to 120 percent of rated speed

j. Description of the required inservice inspection and testing program for valves essential to overspeed protection and any inservice tests, inspections, and maintenance activities for the turbine and valve assemblies that are required to support the calculated missile probability, including inspection and test frequencies with technical bases, type of inspection, techniques, areas to be inspected, acceptance criteria, disposition of reportable indications, and corrective actions The above analysis/report is prepared using criteria in accordance with U.S. Nuclear Regulatory Commission (NRC) requirements (Reference 8, 9). The turbine missile probability analysis report(s) are updated based on as-built properties and verified by ITAAC to exist and conclude that the probability of turbine failure resulting in the ejection 10.2-27 Rev. 2

APR1400 DCD TIER 2 of turbine rotor (or internal structure) fragments through the turbine casing is less than 1 x 10-5 per year.

10.2.4 Evaluation The T/G and all related steam handling equipment will be conventional with a typical proven design that has been used extensively in other nuclear power plants. The T/G automatically follows the electrical load requirements from the station auxiliary load to the turbine full load.

The T/G is located entirely in the T/G building. Thus, no safety-related system or portion of safety-related system is close enough to the T/G to be affected by the failure of a high or moderate energy line associated with the T/G or the LP turbine and condenser connection as described in Subsection 10.2.1.

The T/G and associated high and moderate energy piping, valves, and instruments are located entirely in the T/G building. There are no safety-related systems or components located within the T/G building. Thus, no safety-related system or portion of safety related system is close enough to the T/G to be affected by the failure of a high or moderate energy line associated with the T/G or the LP turbine and condenser connection.

The probability of a destructive overspeed condition and missile generation, assuming the recommended inspection and test frequencies, is less than 1 x 10-5 per year in accordance with SRP Section 3.5.1.3, turbine missiles. Additionally, the orientation of the T/G is favorable as shown in Figure 3.5-1. The layout drawings show the general arrangement of the T/G and associated equipment in relation to essential safety-related SSCs. Failure of the T/G equipment does not preclude safe shutdown of the reactor. The T/G components and instrumentation associated with protecting the T/G from an overspeed condition are accessible under operating conditions.

The results of a failure analysis of the conceptual turbine speed control system are given in Table 10.2.4-1. The system is designed so that the single failure of any component or subsystem does not disable the turbine overspeed trip function.

Since the steam generated in the SGs is not normally radioactive, no radiation shielding is provided for the T/G and associated components. During normal conditions, radiological considerations do not affect access to system components. In the event of a primary-to-secondary system leak due to tube leak in a SG, the steam possibly becomes contaminated.

10.2-28 Rev. 2

APR1400 DCD TIER 2 Appropriate radiological controls can be applied to steam systems in the event that such leakage occurs. Discussions of the radiological aspects of primary-to-secondary leakage are presented in Chapter 11.

10.2.5 Combined License Information COL 10.2(1) The COL applicant is to identify the turbine vendor and model.

COL 10.2(2) The COL applicant is to identify how the functional requirements as described in Subsection 10.2.2.3.2 for the overspeed protection system are met and provide a schematic(s) of the TGCS and overspeed protection systems that show the entire system end-to-end and all discrete components and interfaces (e.g., sensors, power supplies, control devices, manual emergency trips, the device that eventually drains the hydraulic/air fluid from turbine control valves). The schematics and descriptive information provided once a turbine design is selected shall be sufficient to allow assessment of the TGCS and overspeed systems' ability to withstand a single failure without loss of function (i.e., redundancy), resistance to common cause failure (i.e., diversity as provided by electrical and mechanical overspeed trips), and resistance of propagation of a failure to another trip channel (i.e., independence, separation)

COL 10.2(3) The COL applicant is to provide a description of how the turbine missile probability analysis conforms with Subsection 10.2.3.6 to ensure that requirements for protection against turbine missiles (e.g., applicable material properties, method of calculating the fracture toughness properties per SRP Section 10.2.3 Acceptance Criteria, preservice inspections, in-service tests and inspections) will be met. If the turbine vendor has performed a turbine missile analysis that has been reviewed and approved by the NRC for a rotor design relevant to the COL applicant's selected design, then the COL should reference the analysis. If an approved analysis is not available, then the COL applicant shall prepare and reference an analysis that provides confidence that the final analysis performed with as-built properties, when available, will be sufficient to demonstrate assurance of turbine rotor integrity.

10.2-29 Rev. 2

APR1400 DCD TIER 2 COL 10.2(4) The COL applicant shall specify the turbine rotor material properties for chosen turbine vendor and applicable for the specific rotor designs. The COL applicant shall specify the turbine rotor material properties (in terms of the 50% FATT and Charpy V-notch energy) for the chosen turbine vendor and applicable for the specific rotor designs. Any deviation from material properties in SRP 10.2.3, revision in effect on date of regulatory applicability for COL application, shall be identified and justified.

COL 10.2(5) The COL applicant shall provide the site-specific turbine rotor inservice inspection program and inspection interval, including the turbine valve test and inspection program and test and inspection frequency consistent with the manufacturer's turbine missile analysis.

10.2.6 References

1. ASME Section VIII, Division 1, Rules for Construction of Pressure Vessels, the American Society of Mechanical Engineers, the 2013 Edition.

2. IEEE Standard C50.13-2014, IEEE Standard for Cylindrical - Rotor, 50 Hz and 60 Hz Synchronous Generators Rated 10 MVA and Above, Institute of Electrical and Electronics Engineers, 2014.

3. ASTM A470, Standard Specification for Vacuum-Treated Carbon and Alloy Steel Forgings for Turbine Rotors and Shafts, American Society for Testing and Materials, 2010.

4. ASTM A370, Standard Test Methods and Definitions for Mechanical Testing of Steel Products, American Society for Testing and Materials, 2014.

5. ASME Boiler and Pressure Vessel Code,Section III, Rules for Construction of Nuclear Facility Components, The American Society of Mechanical Engineers, the 2013 Edition.

6. ASME Boiler and Pressure Vessel Code,Section V, Nondestructive Examination, the American Society of Mechanical Engineers, the 2013 Edition.

10.2-30 Rev. 2

APR1400 DCD TIER 2

7. ASME Boiler and Pressure Vessel Code,Section XI, Rule for Inservice Inspection of Nuclear Power Plant Components, The American Society of Mechanical Engineers, the 2013 Edition.

8. NUREG-1048, Supplement No. 6, Safety Evaluation Report Relating to the Operation of Hope Creek Generating Station, U.S. Nuclear Regulatory Commission, July 1986.

9. NUREG-0933, Main Report with Supplements 1-34, Resolution of Generic Safety Issues: Item A-37: Turbine Missiles (2), U.S. Nuclear Regulatory Commission, 2011.

10.2-31 Rev. 2

APR1400 DCD TIER 2 Table 10.2.2-1 Source of Extraction Steam for Feedwater Heating Extraction No. Feedwater Heater No. Extraction Source 1st Point 7 HP turbine 1st extraction 2nd Point 6 HP turbine 2nd extraction 3rd Point 5 HP turbine exhaust 4th Point Deaerator LP turbine 1st extraction 5th Point 3 LP turbine 2nd extraction 6th Point 2 LP turbine 3rd extraction 7th Point 1 LP turbine 4th extraction 10.2-32 Rev. 2

APR1400 DCD TIER 2 Table 10.2.2-2 Typical Turbine Valve Closure Times Closure Time Valve Characteristic (seconds)

Main stop valves The primary function is to quickly shut off steam flow to the 0.3 turbine under emergency conditions.

Hydraulic-actuated power actuator consists of a spring housing assembly and control package.

Control valves The primary speed control acts as a first line against 0.3 overspeed by closing on a proportional basis in response to a load rejection. Normal speed control should prevent the turbine from reaching the primary overspeed trip setpoint.

The valves are opened by individual hydraulic cylinders.

Intermediate stop The arrangement is welded directly to the cross-around pipe 0.3 valves to locate the combined valve as close as possible to the turbine, thereby limiting the amount of uncontrolled cross-around steam that is available for overspeeding the turbine under emergency conditions.

The valves are operated by individual hydraulic cylinders.

Intercept valves The purpose of the intercept valve is to shut off steam flow 0.3 from the cross around, which, because of its large storage capacity, could potentially drive the unit to a dangerous overspeed upon loss of generator load.

The valves are operated by individual hydraulic cylinders.

Non-return check The valves are employed to minimize potential to contribute below 1.0 valves to the turbine overspeed in the event of T/G trip.

The valves are operated by air that is connected through air relay dump valve.

10.2-33 Rev. 2

APR1400 DCD TIER 2 Table 10.2.2-3 Turbine Overspeed Protection Devices Percent of Rated Speed Device Function (Approximate)

Speed Control System CVs Control 100 Speed Control System Valves Close 103 Mechanical Overspeed System Trip 110 Electrical Overspeed System (2-out-of-3) Trip 111.5 10.2-34 Rev. 2

APR1400 DCD TIER 2 Table 10.2.3-1 Chemical Composition for Ni-Cr-Mo-V Alloy Steel Designation Element Value (wt%)

C 0.22 - 0.30 Si 0.10 max.

Mn 0.20 - 0.45 P 0.012 max.

S 0.012 max.

Cr 1.5 - 2.0 Ni 3.25 - 4.00 Mo 0.25 - 0.50 V 0.07 - 0.15 Sn 0.010 max.

10.2-35 Rev. 2

APR1400 DCD TIER 2 Table 10.2.4-1 Turbine Speed Control System Component Failure Analysis Component Malfunction Overspeed Prevented By Main control valves Fail to close Closure of main stop valve Main stop valves Fail to close Closure of main control valve Intercept valves Fail to close Closure of intermediate stop valves Intermediate stop valves Fail to close Closure of intercept valve Control processor 1 Fails Control processors 2 and 3 Control processor 2 Fails Control processors 1 and 3 Control processor 3 Fails Control processors 1 and 2 Mechanical overspeed trip Fails Electronic overspeed trip Electronic overspeed trip Fails Mechanical overspeed trip 10.2-36 Rev. 2

APR1400 DCD TIER 2 Legend MSV CV MSV Main Stop Valve CV Control Valve MSR Moisture Separator Reheater Main ISV Intermediate Stop Valve Steam IV Intercept Valve HP High Pressure Turbine LP Low Pressure Turbine NRV Non-return Check Valve MSR ISV ISV ISV IV IV IV HP LP A LP B LP C GEN IV IV IV ISV ISV ISV MSR NRV NRV NRV NRV NRV Heater Heater Heater Deaera Heater Heater Heater No. 7 No. 6 No. 5 tor No. 3 No. 2 No. 1 Figure 10.2.2-1 Typical Arrangement of T/G System 10.2-37 Rev. 2

APR1400 DCD TIER 2 TGCS Normal Control Signal Channels Controller 1 Trip Signal Channels Electro Controller 2 Hydraulic Control Lines to each valve System Controller 3 ETS Lines to each valve MOTS mechanical Overspeed Protection Steam Line Primary EOTS Emergency TGCS: Normal control system is first line of Trip System defense against overspeed by tripping Backup EOTS solenoid-operated fast-acting valves, which (ETS) in front drains hydraulic control oil from turbine standard steam valve dump valves.

Manual MOTS Emergency Trips in Main EOTS: Electrical Overspeed Trip System de-Control Room energizes master trip valve solenoids, which and at front drains hydraulic control oil from turbine standard steam valve dump valves via the ETS.

MSV ISV Magnetic MOTS: Mechanical Overspeed Trip System Speed consists of unbalanced ring that is activated CV IV by a centrifugal force against a spring when Sensors the turbine overspeeds, thus causing an eccentric movement that strikes the trip finger on the emergency trip valve, which HP LP GEN drains hydraulic control oil from turbine steam valve dump valves via the ETS.

Diverse Speed Figure 10.2.2-2 High Level Overspeed Protection Architecture 10.2-38 Rev. 2

APR1400 DCD TIER 2 10.3 Main Steam System The main steam system (MSS) is the system to transport steam generated in the SGs to the high-pressure turbine. The MSS also provides steam to the feedwater pump turbines, auxiliary feedwater pump turbines, the second-stage reheater of the MSR, turbine steam seal system, auxiliary steam system, and process sampling system.

The system dissipates heat from the reactor coolant system (RCS) following a turbine trip, by dumping the steam to the condenser, or when the condenser is unavailable, by dumping the steam to the atmosphere via the main steam atmospheric dump valve (MSADV) or main steam safety valve (MSSV).

The MSS extends from the SG nozzles up to the turbine stop valves including the main steam isolation valves (MSIVs), MSSVs, MSADVs, turbine bypass valves (TBVs), and branch piping.

10.3.1 Design Bases The MSS is designed to:

a. Deliver steam from the SGs to the turbine

b. Dissipate heat during the initial phase of plant cooldown

c. Dissipate heat from the RCS following a turbine and reactor trip

d. Dissipate heat when the main condenser is not available

e. Provide steam for the following:

Feedwater pump turbines, auxiliary feedwater pump turbines, the second-stage reheater of the MSR, turbine steam seal system, auxiliary steam system, and process sampling system

f. Isolate the SGs from the non-safety-related remainder of the MSS when necessary (including containment isolation and post-LOCA)

g. Provide adequate overpressure protection for the SGs and the MSS

h. Conform with applicable design codes 10.3-1 Rev. 2

APR1400 DCD TIER 2

i. Permit visual inservice inspection The safety-related portion of the MSS is the portion between the SG nozzle outlet to and including the main steam valve house (MSVH) penetration anchor wall.

The safety-related portions of the MSS are designed to perform their required functions during normal conditions, adverse environmental occurrences, and accident conditions, including a loss of offsite power (LOOP) with a single malfunction or failure of an active component.

The MSS is designed in conformance with the following requirements:

a. General Design Criterion (GDC) 2 - Safety-related portions of the MSS are designed to withstand the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, floods, tsunamis, and seiches without loss of capability to perform its safety functions. Refer to Sections 3.3, 3.4, and 3.7.

b. GDC 4 - Safety-related portion of the MSS are resistant to the effects of the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents, including LOCAs. Safety-related portions of the MSS are designed to withstand the effects of external missiles and internally generated missiles, pipe whip, and jet impingement forces associated with pipe breaks.

Refer to Sections 3.5, 3.6, and 3.11.

c. GDC 5 - Safety-related portions of the MSS are not shared among nuclear power units. No safety-related equipment of the MSS is shared between units.

d. GDC 34 - The MSS is designed to provide sufficient cooldown capacity with suitable power supply and redundancy for the safety function in conjunction with auxiliary feedwater system (AFWS), assuming a single failure.

e. NRC Regulatory Guide (RG) 1.155 (Reference 1) and 10 CFR 50.63 (Reference 2)

- Safety-related portions of the MSS are designed to provide decay heat removal capability necessary for core cooling and safe shutdown during a station blackout (SBO) event. A discussion of the SBO event and conformance with the guidance in NRC RG 1.155 and 10 CFR 50.63 is provided in Section 8.4. To cope with an SBO event, the APR1400 is provided with an alternate ac (AAC) power source.

10.3-2 Rev. 2

APR1400 DCD TIER 2

f. NRC RG 1.115 (Reference 3) - Safety-related portions of the MSS are designed to protect against missiles resulting from turbine failure. Refer to Section 3.5.

g. NRC RG 1.117 (Reference 4) - Safety-related portions of the MSS are designed to protect against tornadoes. Refer to Section 3.3.

h. NRC RG 1.29 (Reference 5) - Seismic categories of the MSS are designated as seismic Category I, II, or III in conformance with NRC RG 1.29.

The main steam piping, its isolation valves, and all associated supports from the SGs to the MSVH penetration anchor are seismic Category I and are designed in accordance with the requirements of ASME Section III, Class 2 and 3. The remaining steam piping is in accordance with ANSI/ASME-B31.1 (Reference 6).

The MSS is provided with MSADVs to remove reactor decay heat and reactor coolant pump (RCP) heat during hot standby and emergency cooldown in conjunction with the AFWS. An MSADV is installed on each of the four main steam lines to allow a controlled cooldown of the SG when the MSIVs are closed or when the main condenser is not available as a heat sink. In the combined event of a steam line break and the loss of normal ac power or an SG tube rupture (SGTR) and loss of normal ac power, the MSADVs on the intact SG operate manually.

The MSS delivers steam to the feedwater pump turbines during low-load operation until hot reheat steam for the feedwater pump turbines is available. Steam for the turbine-driven auxiliary feedwater pumps is taken from two of the four main steam lines upstream of the MSIVs outside the reactor containment building.

The MSS is designed to provide access to welds with removable insulation in the portions that require inservice inspection in accordance with ASME Section XI (Reference 7).

ASME Section III, Class 2, and 3 components are subjected to inservice testing to assess and verify operational readiness as set forth in 10 CFR 50.55a(f) (Reference 8) and ASME OM Code. Descriptions of periodic inservice inspection and inservice testing of ASME Section III, Class 2 and 3 components are provided in Subsection 3.9.6 and Section 6.6.

The MSSV and MSADV discharge piping is arranged and supported to minimize discharge loads so that the limiting loads are not exceeded for normal and transient conditions. The MSS is designed to accommodate steam hammer dynamic loads and relief valve discharge 10.3-3 Rev. 2

APR1400 DCD TIER 2 loads resulting from rapid closure of system valves and safety and relief valve operation without compromising safety functions.

10.3.2 System Description 10.3.2.1 General Description The MSS delivers steam generated in the SGs to the HP turbine where the thermal energy of the steam is converted to mechanical energy to drive the main T/G. The MSS also provides steam to the feedwater pump turbines, auxiliary feedwater pump turbines, second-stage reheater of the MSR, turbine steam seal system, auxiliary steam system, and process sampling system.

The major components of the MSS are the main steam piping, MSIVs, main steam isolation valve bypass valves (MSIVBVs), MSSVs, MSADVs, turbine bypass valves (TBVs; see Subsection 10.4.4), and auxiliary feedwater pump turbine steam supply valves and warmup valves.

A flow diagram of the MSS is presented in Figure 10.3.2-1. The principal data for the major components are provided in Table 10.3.2-1.

10.3.2.2 Component Description 10.3.2.2.1 Piping The MSS delivers steam from the two SGs to the HP turbine during normal power operation. The MSS has four main steam lines from the two SGs to the main steam common header. The four main steam lines are designed so that the pressure drop between SG nozzle and turbine stop valve does not exceed 2.1 kg/cm2 (30 psi) at 105 percent of saturated steam flow at normal full-power SG pressure. The main steam lines are arranged so that pressure drops between each SG and the main steam header are approximately equal. The difference between steam line pressure drops is within 0.2 kg/cm2 (3 psi) at the full-power condition. The piping diameter is determined to limit velocities, taking account of erosion and corrosion effects. Main steam piping layout is designed so that 90-degree elbows and miters are minimized.

The main steam piping and its supports and restraints are designed to withstand loads under the service levels specified in Subsection 3.9.3.

10.3-4 Rev. 2

APR1400 DCD TIER 2 Sampling connections are provided downstream of the MSIVs to monitor the steam chemistry. Low-point drains are provided on the main steam piping for startup operation and for prevention of turbine water induction. Condensate from the low point is drained to the main condenser.

Adequate clearances are provided for inservice inspection of the ASME Section III, Class 2 portions of the MSS piping in accordance with ASME Section XI.

Piping design data are provided in Tables 10.3.2-2 and 10.3.2-3.

Upstream of the main steam isolation valves, there are connections for the main steam atmosphere dump valves, main steam safety valves, low point drains, nitrogen supply, auxiliary feedwater pump turbine steam supply. Branch piping downstream of the main steam isolation valves includes connections for the turbine bypass, 2nd stage reheaters, high pressure turbine, feedwater pump turbine, auxiliary steam, turbine steam seal and low point drains. Table 10.3.2-6 describes branch piping, 2.5 inches and larger, that is downstream of the main steam isolation valves up to turbine stop valves.

10.3.2.2.2 Main Steam Isolation Valve and Main Steam Isolation Valve Bypass Valve Each main steam line has an MSIV to maintain tight shutoff against forward and reverse steam flow under its design condition. Each MSIV is provided with a bypass line for warmup of the steam lines downstream of the isolation valves and pressure equalization prior to admitting steam to the turbine.

The fail-closed MSIVs and MSIVBVs are interlocked to automatically close after receipt of a main steam isolation signal (MSIS) within limits. The parameters that initiate an MSIS are given in Section 7.3.

Each MSIV and MSIVBV has a hydraulic actuator that provides redundancy of the valve operation using physical separation and electrical independence to each other. An MSIS is provided to each redundant set of hydraulic actuators.

An electrical or mechanical malfunction of one circuit does not prevent the MSIV and MSIVBV from closing. The MSIVBV is a fail-closed valve and de-energized in normal so that no single electrical failure will result in the spurious opening of the valves.

10.3-5 Rev. 2

APR1400 DCD TIER 2 The following operator interfaces to the MSIV are provided locally, in the main control room (MCR), and the remote shutdown room (RSR).

a. Capability to manually open and close the valve

b. Capability to test the valve operation

c. Valve position indication (open/close indicating lights)

The data for the MSIV and MSIVBV are provided in Table 10.3.2-1.

10.3.2.2.3 Main Steam Safety Valves The primary purpose of the MSSVs is to provide overpressure protection for the secondary side of the SGs.

Five spring-loaded MSSVs are provided for each individual main steam line. A total of 20 MSSVs are provided for the four main steam lines from the two SGs and have relieving capacity sufficient to prevent a rise in pressure of more than 10 percent above the MSS design pressure.

The total rated capacity of the MSSVs is 105 percent of the saturated steam flow at normal full-power SG pressure; this capacity is equally divided among the valves.

Safety valve set pressure is calculated in accordance with Article NC-7000 of ASME Section III. The MSSVs have a proven design and consistently open fully at the set pressure within acceptable limits during operability tests.

The MSSVs and their supports are designed to withstand loads arising from various operating and design basis events, specified in Subsection 3.9.3. The piping and valve arrangement and design analysis are performed in accordance with ASME Section III, Division 1, Appendix O.

There are no isolation valves in the main lines between the SGs and MSSVs.

The data for the MSSV are provided in Table 10.3.2-1.

10.3-6 Rev. 2

APR1400 DCD TIER 2 10.3.2.2.4 Main Steam Atmospheric Dump Valves One MSADV is provided on each main steam line upstream of the MSSVs to allow cooldown of the RCS through a controlled discharge of steam to the atmosphere when the MSIVs are closed or when the main condenser is not available as a heat sink. Each valve is capable of holding the plant at hot standby, dissipating core decay and RCP heat, and allowing controlled cooldown from hot standby to shutdown cooling system initiation conditions in conjunction with AFWS.

Each valve is sized to allow a controlled plant cooldown in the event of a line break or tube rupture that renders one SG unavailable for heat removal, concurrent with a single active failure of one of the remaining two MSADVs. During hot standby, each MSADV is capable of controlling required flow at SG pressure of 70.31 kg/cm2 A (1,000 psia).

MSADVs are designed so that the valves close automatically on loss of motive power or loss of control signal. Each MSADV can be operated with hand wheel or manual control provision to enable manual operation of the hydraulic actuator mounted on the valve upon total loss of power.

The steam through the MSADV is discharged directly to the atmosphere, with a separate vertical vent stack and silencer provided for each valve. A block valve is provided for each MSADV to allow isolation of steam leakage due to a stuck-open or inadvertently opened MSADV. The block valve is manually operated from the MCR or RSR.

Operator interface to the MSADV control system is provided in the MCR and RSR. The following are provided:

a. Capability to manually close and position the valve

b. Valve position indication (both analog position and open/close indication lights)

Two MSADVs with hydraulic actuators that are physically separate and electrically independent from each other are provided to each SG. No single failure prevents operation of at least one MSADV on each SG.

The MSADVs and their supports are designed to withstand loads arising from various operating and design basis events, specified in Subsection 3.9.3. The piping and valve 10.3-7 Rev. 2

APR1400 DCD TIER 2 arrangement and design analysis are performed in accordance with ASME Section III, Division 1, Appendix O.

The data for the MSADVs are provided in Table 10.3.2-1.

10.3.2.2.5 Auxiliary Feedwater Pump Turbine Steam Supply Valves and Warmup Valves An auxiliary feedwater pump turbine steam supply valve is furnished on one of the two main steam lines for each SG. These valves are automatically opened by auxiliary feedwater actuation signal (AFAS).

A normally open auxiliary feedwater pump turbine steam warmup valve allows warmup of the steam supply line to auxiliary feedwater pump turbine before the auxiliary feedwater pump turbine steam supply valve is opened. The warmup valve also allows pressure and temperature to equalize across the auxiliary feedwater pump turbine steam supply valve during auxiliary feedwater pump turbine startup.

10.3.2.3 System Operation 10.3.2.3.1 System Startup Prior to the startup of the MSS, the circulating water and the condensate and feedwater systems are in operation. Normal water level is established in the SGs. The SGs provide steam for the MSS warmup using heat generated by the RCP, pressurizer heaters, and reactor.

All main steam line drain valves are opened to drain condensate. The main turbine stop valves are closed, and the stop valve seat drains are opened. The MSIVs remain closed while the MSIVBVs are opened and the globe valve downstream of the MSIVBV throttles the steam flow for the MSS warmup and pressure equalization across the MSIVs. When the pressure and temperature are equalized across the MSIVs, the MSIVs can be opened and the MSIVBVs closed. Thereby, the turbine is warmed and loaded.

The MSS pressure and flow are automatically controlled by modulating the TBVs and dumping steam to the condenser.

During startup and low-load operation, main steam from the cross-connection header is supplied to the deaerator for pegging via the auxiliary steam header.

10.3-8 Rev. 2

APR1400 DCD TIER 2 10.3.2.3.2 Normal Operation During normal plant operation, main steam is delivered to the high-pressure turbine through the MSS and is automatically controlled by the turbine generator control system (TGCS).

All MSIVs are opened. All MSIVBVs, MSSVs, MSADVs, and TBVs are closed. The MSS also supplies steam to the auxiliary steam system during all modes of operation.

Main steam is also supplied to the turbine steam seal system and the second-stage reheater tube side.

During plant low-load operation when hot reheat steam pressure is not high enough to drive the feedwater pump turbine at its required speed, main steam is introduced as a supplementary source to maintain the required feedwater pump turbine speeds.

During rapid load changes, if there are transient plant conditions where the NSSS exceeds the turbine steam requirement, the TBVs remove excess energy from the NSSS by dumping steam to the condenser in conjunction with the steam bypass control system (SBCS).

10.3.2.3.3 Plant Shutdown During the initial cooling period for plant shutdown, the main condenser removes decay heat from the RCS using the TBS. The bypassed steam is distributed over the condenser tubes by spray headers. The condenser design includes special provisions of the energy dispersion devices to prevent steam impingement on the tubes. In the event that the TBS is not available for cooldown, MSADVs may be used. At the end of the cooldown period, the drain and vent valves are opened to drain any condensate formed in the piping, and the MSIVs are closed.

10.3.2.3.4 Abnormal Operation Following a load rejection of any magnitude from full load to house load, including a turbine trip from 100 percent power, the TBS controls main steam pressure automatically, by the SBCS. The TBVs are automatically closed or blocked from opening when the condenser is unavailable.

If a load rejection occurs concurrently with condenser unavailability, the spring-loaded MSSVs sequentially open with increasing pressure and discharge the required amount of steam to the atmosphere to prevent system pressure from exceeding the MSS maximum design pressure.

10.3-9 Rev. 2

APR1400 DCD TIER 2 For a main steam line break inside the containment, the faulted SG discharges directly into the containment. The unaffected SG discharges steam into the containment through the interconnecting header and broken line. All MSIVs are signaled to close automatically upon receipt of an MSIS. A flow restrictor is provided at each of the four outlet nozzles of the SGs to limit steam flow in the event of a main steam line break.

After closure of MSIVs, the intact SG will repressurize to the safety valve setpoint and MSSVs open. The plant is finally cooled down by discharging steam through the silencer to the atmosphere using the MSADVs.

For an evaluation of a main steam line break (MSLB) and steam generator tube rupture (SGTR), refer to Section 15.0.

10.3.2.3.5 Water (Steam) Hammer Prevention The MSS is designed to minimize the potential for steam hammer. The MSS is designed to accommodate steam hammer dynamic loads and relief valve discharge loads resulting from the rapid closure of system valves and safety/relief valve operation without compromising safety functions. Refer to Section 3.12 for a description of piping design and piping supports design. Loads from relief valve openings and sudden closure of valves are included in the piping analyses.

The MSS design includes protection against water entrainment, which includes provisions for drain pots, line sloping, and valve operation. The main steam nozzle vertical connection lines of the SGs are the highest point in the main steam piping and all main steam lines slope away from the SGs.

Low-point drains are provided on the main steam pipes for startup and for prevention of turbine water induction and water hammer. Main steam drain valves are provided with position indications. Main steam drain valves can be manually controlled in the MCR and RSR. Main steam drain valves are automatically opened and closed by drip pot level switches. Level alarms are provided in the MCR and RSR to warn the operator of main steam line drain pot high-high level.

The discharge piping from the TBVs to the condenser is arranged without low points or includes drains to prevent water from collecting in the piping. The discharge piping from each valve is not headered together prior to its connection to the condenser. These 10.3-10 Rev. 2

APR1400 DCD TIER 2 precautions will eliminate potential water hammer damage to condenser internals and other TBVs upon valve opening.

The COL applicant is to provide operating and maintenance procedures in accordance with NUREG-0927 and a milestone schedule for implementation of the procedure (COL 10.3(1)). The procedures are to address :

a. Prevention of rapid valve motion

b. Introduction of voids into water-filled lines and components

c. Proper filling and venting of water-filled lines and components

d. Introduction of steam or heated water that can flash into water-filled lines and components

e. Introduction of water into steam-filled lines or components

f. Proper warmup of steam-filled lines

g. Proper drainage of steam-filled lines

h. Effects of valve alignments on line conditions 10.3.2.3.6 Instrumentation and Control The control system minimizes the number of instrumentation control functions and control loops required to perform the essential control functions.

Radiation monitors and alarms capable of detecting N-16 are incorporated in the main steam lines upstream of the MSIV and MSIVBVs. Two monitors per SG are provided.

N-16 radiation monitors are described in Subsection 12.3.4.1.5.

Instrumentation and controls associated with the MSS are described in Chapter 7.

10.3.2.4 Design Features for Minimization of Contamination The MSS is designed with specific features to meet the requirements of 10 CFR 20.1406 (Reference 20) and NRC RG 4.21 (Reference 9). The basic principles of NRC RG 4.21, and the methods of control suggested in the regulations, are specifically delineated in four 10.3-11 Rev. 2

APR1400 DCD TIER 2 design objectives and two operational objectives discussed in Subsection 12.4.2. The following description summarizes the primary features to address the design and operational objectives for the MSS.

The MSS includes components that contain radiologically contaminated fluid resulting from steam generator tube leakage. In accordance with NRC RG 4.21, the MSS has been evaluated for leak identification from the SSCs that contain radioactive or potentially radioactive materials, the areas and pathways where leakage may occur, and the methods of leakage control incorporated in the design of the system. The leakage identification evaluation indicated that the MSS is designed to facilitate early leak detection and the prompt assessment and response to manage collected fluids. Unintended contamination to the facility and the environment is minimized or prevented by the SSC design, supplemented by operational procedures and programs for inspection and maintenance activities.

Prevention/Minimization of Unintended Contamination

a. The main steam lines are equipped with radiation monitors to detect radiological contamination and to provide alarms for operator notification. Following a steam generator tube rupture, the MSIVs for the affected steam generator are closed in order to isolate the affected steam generator. This design minimizes radiological cross-contamination and unintended contamination of the facility.

b. The main steam piping is sloped in the direction of steam flow to avoid water entrenchment and the collection of condensate drainage.

c. To minimize the possibility of water impingement into the main turbine, drain pots are provided at low points in the main steam piping where water may collect.

Condensate from these drain pots is continuously removed with direct piping to the main condenser during normal plant power operation. This design approach prevents the spread of contamination within the facility.

Adequate and Early Leak Detection

a. Radiological monitoring of the MSS is provided continuously through N-16 gamma detection with a scintillation detector and microprocessor on each main steam line from the steam generator.

10.3-12 Rev. 2

APR1400 DCD TIER 2

b. Radiation sampling connection is provided on the condenser vacuum pump exhaust line and the steam generator blowdown line to monitor contamination levels associated with the condensate and steam generator blowdown systems.

c. The radiation monitors are designed to provide indication of steam generator leakage and alert the operator of a steam generator tube leak condition during power operation, including the identification of the affected steam generator.

Reduction of Cross-Contamination, Decontamination, and Waste Generation

a. The safety-related portion of the main steam piping is designed to comply with the ASME Section III. The non-safety-related portion of the main steam piping is designed to ASME B31.1 for safe operation and the minimization of waste generation.

b. Main steam piping is designed to minimize the effects of erosion/corrosion, is adequately sized to limit velocities, and is routed with long-radius elbows to minimize potential erosion and waste generation.

c. The SSCs are designed with life-cycle planning through the use of nuclear industry-proven materials compatible with the chemical, physical, and radiological environment, minimizing waste generation.

d. Process sampling connections are provided downstream of the MSIVs for monitoring of steam chemistry.

Decommissioning Planning

a. The main steam piping is designed for the full service life and is fabricated as individual segments for easy assembly and removal.

b. The main steam piping is designed with clean out capabilities. Design features such as welding techniques used and surface finishes are intended to minimize the need for decontamination, and hence reduce waste generation.

c. The MSS is designed without any embedded or buried piping, preventing contamination to the environment.

10.3-13 Rev. 2

APR1400 DCD TIER 2 Operations and Documentation

a. The MSS piping and components are located in the reactor containment building, auxiliary building, and turbine generator building. Adequate space is provided around the equipment to enable prompt assessment and responses.

b. The COL applicant is to establish operational procedures and maintenance programs as related to leak detection and contamination control (COL 10.3(2)).

Procedures and maintenance programs are to be completed before fuel is loaded for commissioning.

Site Radiological Environmental Monitoring The MSS is part of the overall plant but does not have direct release points or contamination migration pathways to the environment during normal operation.

Therefore, the MSS is not specifically required to be included in the radiological environmental monitoring program.

10.3.3 Safety Evaluation Safety-related portions of the MSS are contained in seismic Category I structures (reactor containment building and MSVH in auxiliary building). The portions are designed to withstand the effects of natural phenomena such as wind, earthquakes, tornadoes, hurricanes and floods, and are protected from potential dynamic effects such as missiles, pipe whips, and jet impingement as described in Chapter 3. Sections 3.3 through 3.8 describe the bases of the structural design. The MSS piping and components upstream of and including the MSIVs are classified as seismic Category I. The safety-related portion of the MSS is designed to remain functional after a safe shutdown earthquake (SSE).

The safety-related components of the MSS are qualified to function in accident environmental conditions. The environmental qualification program is addressed in Section 3.11.

Each MSADV has the capability to allow a controlled plant cooldown in the event of a line break or tube rupture that renders one SG unavailable for heat removal, concurrent with a single active failure of one of the remaining two MSADVs.

10.3-14 Rev. 2

APR1400 DCD TIER 2 The MSSVs are installed on the MSS lines to provide overpressure protection for the MSS and the secondary side of the SGs.

Safety-related portions of the MSS are designed to perform their safety functions during an SBO event using power from an AAC power source.

Each MSIV has its own redundant set of hydraulic actuators, assuming a single failure cannot cause failure to close when required to close.

Radioactive contamination of the MSS can occur by a primary to secondary side leak in the SGs. The radiological aspects of primary to secondary system leakage are addressed in Subsection 11.1.1.3.

Accident analyses of the MSLB and SGTR are addressed in Subsection 15.1.5 and 15.6.3, respectively.

Table 10.3.3-1 provides the results of a single failure analysis for the MSS. The analysis results demonstrate that no single failure, coincident with a LOOP event, compromises the ability to fulfill the system safety functions.

10.3.4 Inspection and Testing Requirements 10.3.4.1 Preoperational Testing The MSS components are inspected and tested as part of the initial test program. The initial plant startup test program for the MSS is described in Subsections 14.2.12.1.29, 14.2.12.1.63, 14.2.12.1.64, 14.2.12.1.65, and 14.2.12.4.15.

10.3.4.2 Inservice Testing ASME Section III, Class 2 piping is inspected and tested in accordance with ASME Sections III and XI. ANSI/ASME B31.1 piping is inspected and tested in accordance with the ANSI/ASME B31.1 Code.

A description of periodic inservice inspection and inservice testing of ASME Section III, Class 2 and 3 components is provided in Subsection 3.9.6 and Section 6.6. Provisions are made to allow for inservice inspection of components at times that are consistent with those specified in ASME Section XI.

10.3-15 Rev. 2

APR1400 DCD TIER 2 During the initial startup and periods of plant shutdown, the tripping mechanisms for the MSIVs are tested for proper operation in accordance with the Technical Specifications in Chapter 16.

A test is conducted to verify MSIV response to a simulated MSIS, as follows:

a. The objective of the test is to verify the function of the MSIV and to confirm the closing time.

b. The test method consists of applying a simulated MSIS to the controls of the MSIV under test, and recording the temperature and pressure parameters upstream and downstream of the valve seat and the timing of the closure process from receipt of signal to the instance of valve closure as indicated by the valve stem travel indicator.

c. Acceptance criteria are that the MSIV closes in accordance with Subsection 10.3.2.2.2.

Periodic testing to demonstrate the operability of the MSS components is performed as specified in the Technical Specifications in Chapter 16.

10.3.5 Secondary Water Chemistry The principal function of the secondary water system is to provide high-purity, high-quality steam to the turbine. The term purity refers to the absence of chemical and physical contaminants. The term quality refers to the absence of entrained moisture.

It is required that chemistry throughout the secondary system be controlled by all volatile treatment (AVT). This zero-solids concept has been selected as the best mode of operation to maintain long-term SG integrity.

In order for the secondary system to fulfill its function of providing high-purity, high-quality steam to the turbine-generator system, secondary water chemistry is guided by the following objectives:

a. Minimization or elimination of secondary-side corrosion

b. Minimization of impurities in the steam 10.3-16 Rev. 2

APR1400 DCD TIER 2 These chemistry objectives are crucial elements of a program of prudent operation and preventive maintenance that seeks to maximize plant availability while maintaining long-term plant and component integrity. The secondary water chemistry program is based on the Electric Power Research Institute (EPRI) Pressurized Water Reactor (PWR) Secondary Water Chemistry Guidelines.

10.3.5.1 Chemistry Control Basis SG secondary side water chemistry control is accomplished by the following:

a. Close control of the feedwater to limit the amount of impurities that can be introduced into the SG

b. Continuous blowdown of the SG to reduce the concentrating effects of the SG

c. Chemical addition to establish and maintain an environment that minimizes system corrosion

d. Preoperational cleaning of the feedwater system

e. Minimizing feedwater oxygen content prior to entry into the SG Secondary water chemistry is based on the zero-solids treatment method. This method employs the AVT method to maintain system pH and to scavenge dissolved oxygen that may be present in the feedwater. A neutralizing amine is added to establish and maintain alkaline conditions in the feed train. Neutralizing amines that can be used for pH control are ammonia or ethanolamine.

Hydrazine is added to scavenge dissolved oxygen that is present in the feedwater.

Hydrazine also tends to promote the formation of a protective oxide layer on metal surfaces by keeping these layers in a reduced chemical state.

Both the pH agent and hydrazine are injected continuously downstream of the condensate pumps or condensate demineralizers. These chemicals are added for chemistry control and can also be added to the upper SG feed line.

Layup exists whenever the SGs are at a temperature of less than 99 °C (210 °F). The primary objective during any layup of the SG is to minimize corrosion by excluding and providing protection against oxygen, and maintaining a proper pH. In order to achieve 10.3-17 Rev. 2

APR1400 DCD TIER 2 this objective, the operator should prepare for layup as the plant is cooling down. The most effective means of excluding oxygen is to maintain an overpressure of steam or nitrogen in the SG. In order to provide reasonable assurance that oxygen is excluded, 0.35 kg/cm2G (5 psig) is specified as the minimum SG pressure during normal layup. In addition, a positive nitrogen overpressure should be maintained during filling and draining operations to minimize oxygen ingress.

Sampling can be accomplished after pumping the contents from one SG to the other and back three times, assuming recirculation is available. The pumping operation should lower the water level in one SG from the can deck level to the low water level and raise the level in the other SG a corresponding amount. Adding chemicals, or reducing contaminant levels prior to or during wet layup, should be performed during the pumping operation. Otherwise, it should be necessary to drain the SGs partially to add chemicals.

Should the latter be necessary, the amount of water drained should be minimized. If recirculation is not available, sufficient water should be drained to provide reasonable assurance that a representative sample is taken. Mixing should also be accomplished by sparging with nitrogen via the blowdown pipes.

The COL applicant will provide secondary side water chemistry threshold values and recommended operator actions for chemistry excursions in compliance with the latest version of the EPRI PWR Secondary Water Chemistry Guidelines in effect at the time of COLA submittal. The COL applicant will establish the operational water chemistry program six months before fuel load (COL 10.3(3)).

10.3.5.2 Corrosion Control Effectiveness Alkaline conditions in the feed train and the SG reduce general corrosion at elevated temperatures and tend to decrease the release of soluble corrosion products from metal surfaces. These conditions promote the formation of a protective metal oxide film and reduce the corrosion products released into the SG.

Hydrazine also promotes the formation of a metal oxide film by reducing ferric oxide to magnetite. Ferric oxide can be loosened from the metal surfaces and transported by the feedwater. Magnetite provides an adherent protective layer on carbon steel surfaces.

The removal of dissolved oxygen from secondary water is also essential in reducing corrosion. Oxygen dissolved in water causes general corrosion that can result in pitting of ferrous metals, particularly carbon steel. Dissolved oxygen is removed from the steam 10.3-18 Rev. 2

APR1400 DCD TIER 2 cycle condensate in the main condenser deaerating section and by the full-flow feedwater deaerator, which is located between the low-pressure and high-pressure feedwater trains.

Additional oxygen protection is obtained by chemical injection of hydrazine into the condensate stream. Maintaining a residual level of hydrazine in the feedwater provides reasonable assurance that any dissolved oxygen that is not removed by the condensate system is scavenged before it can enter the SG.

The presence of free hydroxide (OH-) can cause rapid corrosion if it is allowed to concentrate in a local area. Free hydroxide is avoided by maintaining proper pH control and by minimizing impurity ingress in the SG.

Zero-solids treatment is a control technique in which both soluble and insoluble solids are excluded from the SG. This is accomplished by maintaining strict surveillance over the possible sources of feed train contamination (e.g., main condenser cooling water leakage, air inleakage, subsequent corrosion product generation in the low pressure drain system).

Solids are also excluded by injecting only volatile chemicals to establish conditions that reduce corrosion and therefore reduce the transport of corrosion products into the SG.

Solids in the SG can also be reduced through the use of full-flow condensate demineralization.

In addition to minimizing the sources of contaminants entering the SG, continuous blowdown is used to minimize the concentration of the contaminants.

The condensate polishing, feedwater, and blowdown systems are addressed in Subsections 10.4.6, 10.4.7, and 10.4.8, respectively.

With low solid levels, which result from following the above procedures, the accumulation of corrosion deposits on SG heat transfer surfaces and internals is limited. Corrosion product formation can alter the thermal-hydraulic performance in local regions to an extent that deposits create a mechanism that allows impurities to concentrate to high levels and could cause corrosion. By limiting the ingress of solids into the SG, the effect of this type of corrosion is reduced.

Chemical additives do not concentrate in the SG and do not represent chemical impurities that can cause corrosion because they are volatile.

10.3-19 Rev. 2

APR1400 DCD TIER 2 10.3.5.3 Primary-to-Secondary Leaks Primary-to-secondary leaks result in two major problems. The first is general contamination of the secondary cycle because of the distribution and possible accumulation of both long- and short-lived radionuclides. The effects and monitoring methods for these radionuclides are described in the following sections. The second concern is the effect of boric acid from the reactor coolant on secondary system pH. The result of primary-to-secondary leaks is similar to a boric acid treatment of the secondary system.

10.3.5.3.1 Radioactivity Effects Radioactivity in the secondary system is troublesome because of normal steam and water leaks throughout the plant and direct venting to the atmosphere. The limits in Subsection 3.4.15 of the Technical Specifications provide reasonable assurance that the health and safety of the general public at the site boundary are not affected if the limit is reached. In addition, primary-to-secondary leaks can result in contamination of components and increased radiation exposure of plant personnel. Because of these considerations, the radioactivity in the SGs is monitored and could result in a limiting condition for operation.

Iodine 131 (131I) has been selected because it is the most limiting nuclide. Additional discussion is presented in Chapter 11.

10.3.5.3.2 Monitoring Several methods are used to monitor primary-to-secondary leakage. Analysis of the secondary water is required by Subsection 3.7.17 of the Technical Specifications. The surveillance requirement specifies that gross activity be analyzed once every 31 days.

Periodic radiochemical analyses do not provide sufficient warning if a substantial primary-to-secondary leak suddenly occurs. For this reason, plants rely on radiation monitors for initial indication. The monitors are located in the SG blowdown line (iodine activity),

main steam line (noble gas activity), and the condenser vacuum exhaust (noble gas activity).

During periods of low leak rates, or when noble gas activity is low, tritium activity in the secondary plant can be monitored. The measurement of noble gas activity from condenser vacuum exhaust appears to be the most sensitive method of detecting and quantifying primary-to-secondary leaks.

10.3-20 Rev. 2

APR1400 DCD TIER 2 The secondary system radiation monitor alarm results in prompt action to analyze the SG water to determine the leak rate. The primary-to-secondary leak rate can be determined by performing a mass balance based on isotopic analyses of the SG and RCS water.

10.3.6 Steam and Feedwater System Materials 10.3.6.1 Fracture Toughness The material specifications for pressure retaining components in the safety-related portion of the main steam and feedwater system meet the fracture toughness requirements of the ASME Section III, Articles NC-2300 (Class 2) for Quality Group B and ND-2300 (Class 3) for Quality Group C components.

10.3.6.2 Materials Selection and Fabrication MSS and feedwater system piping materials used for ASME Section III, Class 2 and 3 components defined in NRC RG 1.26 are provided in Tables 10.3.2-2, 10.3.2-3, and 10.3.2-

4. The APR1400 meets the regulatory requirements of 10 CFR 50.55a, GDC 1 of Appendix A to 10 CFR 50, and Appendix B to 10 CFR 50.

The material selection and fabrication methods used for Class 2 and 3 components conform with the following:

a. The materials that are used conform to ASME Section III including Appendix I and Part A, Part B, and Part C of ASME Section II (Reference 10) and NRC RG 1.84 (Reference 11).

b. No austenitic stainless steel piping material is used in the main steam and feedwater systems.

c. The secondary system piping is designed to allow cleaning to remove foreign material and rust prior to operation and to prevent introduction of this material into the SG. Cleaning and acceptance criteria are based on the requirements of ASME NQA-1 (Reference 12) and recommendations of NRC RG 1.28 (Reference 13).

d. The control preheats temperatures for welding of low-alloy materials conform with the NRC RG 1.50 (Reference 14) for the MSS and feedwater system.

Preheat temperature for carbon steel piping of the ASME Section III, Division 1, 10.3-21 Rev. 2

APR1400 DCD TIER 2 Class 2, and 3 portions of the MSS and feedwater system conform with the ASME Section III, Appendix D, Article D-1000.

e. The welding of austenitic stainless steel conforms with the NRC RG 1.31 (Reference 21) and NRC RG 1.44 (Reference 22).

f. Welder performance qualification for areas of limited accessibility conforms with the recommendations of NRC RG 1.71 (Reference 15) (i.e., assurance of the integrity of welds in locations of restricted direct physical and visual accessibility).

g. The nondestructive examination procedures and acceptance criteria for the examination of Class 2 and Class 3 materials of tubular products conform with the requirements of ASME Section III, NC/ND-2550 through NC/ND-2570.

h. A description of periodic inservice inspection and inservice testing of ASME Section III, Class 2 and 3 components is provided in Section 6.6 and Subsection 3.9.6. Preservice and inservice testing and inspection are addressed further in Chapter 14.

i. No copper alloys are used for components that are in contact with feedwater, steam, or condensate.

Oxygen-induced corrosion is minimized by providing the following component materials:

a. Steam reheater tubes are ferritic stainless steel

b. Feedwater heater tubes are type 304L stainless steel 10.3.6.3 Flow-Accelerated Corrosion FAC-resistant materials are used for the FAC-susceptible piping in steam and power conversion systems. The water chemistry conditions of the secondary system are controlled to minimize corrosion. The additional pipe thickness are applied for the carbon steel steam and water piping in consideration of the 40 years of design life. The piping layout is also considered to minimize the incidence of FAC or erosion/corrosion in piping.

Most of the piping on steam and feedwater systems is made of carbon steel. Materials for the piping portions that are susceptible to FAC are installed using an FAC-resistant alloy such as Cr-Mo steel.

10.3-22 Rev. 2

APR1400 DCD TIER 2 The following piping portions with potential for FAC are generally based on NSAC-202L-R3 (Reference 16) and NUREG-1344 (Reference 17) attached to GL 89-08 (References 18).

a. For other safety/non-safety carbon steel piping with relatively mild FAC degradation identified in NUREG-1344 attached to GL 89-08, NSAC-202L-R3, and through experience, the average thinning rates of 2.54 x 10-6 mm/hr (0.1 x 10-6 in/hr) in steam system and 4.35 x 10-6 mm/hr (0.17 x 10-6 in/hr) in the water system are given based on the actual measurement records from Korea standard nuclear plants.

The additional thickness of 0.889 mm (0.035 in.) for the portion of steam system piping, and 1.524 mm (0.06 in.) for the portion of water system piping in design are applied in consideration of the 40 years of design life.

b. As shown in Table 10.3.2-4, the main feedwater piping from the main feedwater isolation valve (MFIV) in the MSVH to SGs is made of high-content chrome-moly materials. This portion of the feedwater system is potentially susceptible to FAC, and the design specifications require FAC-resistant piping materials as described above. Other feedwater system piping is generally made of carbon steel with 1.524 mm (0.06 in.) additional margin in design.

c. Condensate piping from the deaerator inlet control valves to the deaerator is made of chrome-moly materials. Other condensate piping is made of carbon steel with a 1.524 mm (0.06 in.) additional margin in the design.

d. As shown in Table 10.3.2-2 and Table 10.3.2-3, the entire portion of MSS piping is made of carbon steel with a 0.889 mm (0.035 in.) additional margin in design.

e. The entire portion of extraction steam piping is made of chrome-moly materials

f. Most feedwater heater drain piping is made of carbon steel with 1.524 mm (0.06 in.) additional margin in design. FAC-susceptible portions such as downstream components of control valves are made of high-content chrome-moly materials.

g. Additional thickness beyond the corrosion allowance is included on steam and feedwater system piping based on the additional thickness (A) of ASME code Section III for safety related piping and ASME B31.1 for non-safety related piping.

10.3-23 Rev. 2

APR1400 DCD TIER 2 The COL applicant is to provide the description about the material specifications for components between 1) the high pressure turbine and the moisture separator reheater and 2) the moisture separator reheater and the low pressure turbine when the T/G design is selected. The COL applicant is also to specify that the pipe thickness is adequate for the plant design life in terms of FAC in place of the components between 1) the high pressure turbine and the moisture separator reheater and 2) the moisture separator reheater and the low pressure turbine when the T/G design is selected (COL 10.3(4))

For safety/non-safety carbon steel piping with relatively mild potential for FAC degradation, the required design wall thickness is based on piping design pressure, design temperature, and allowable stress in accordance with ASME Section III NC/ND-3640 or ASME B31.1 Paragraph 104. The specified wall thickness (prior to fabrication) is a standardized wall thickness stipulated in ASME B36.10M (Reference 19). It is determined to exceed the required design wall thickness with consideration of minus tolerances of the thicknesses by the appropriate amount to account for the expected wall thickness loss during fabrication.

The piping layout includes a consideration of several features for the various piping systems to minimize the incidence of FAC and erosion/corrosion in piping as follows:

a. Elimination of high-turbulence points wherever possible (e.g., increasing the pipe length downstream of flow orifice, control valve)

b. Application of a suitable flow orifice to minimize cavitation possibilities (e.g.,

using the multi-plate orifice and multi-hole orifice)

c. Application of long-radius elbows

d. Application of smooth transition at shop or field welds

e. Selection of pipe diameter to have velocities within industry-recommended values For the safety/non-safety carbon steel piping with relatively mild FAC degradation, the FAC monitoring program is prepared and implemented. The FAC monitoring program includes preservice thickness measurements of as-built piping considered susceptible to FAC and erosion/corrosion. By performing this preservice measurement, the piping thickness margin that is used as a wall thinning margin is known. By combining the measurement with regular inspections, the frequency of the pipe replacement can be predicted. Reasonable assurance of the integrity and safety of plants is provided by conducting inspection and maintenance during the service life of the plant and replacing 10.3-24 Rev. 2

APR1400 DCD TIER 2 piping if necessary. The type of fluid, flow rates, fluid temperatures, and pressure of ASME Class 2 and 3 piping for steam and feedwater system are given in Table 10.3.2-5.

The COL applicant is to provide a description of the FAC monitoring program. The description is to address consistency with GL 89-08 and NSAC-202L-R3 and provide a milestone schedule for implementation of the program (COL 10.3(5)). The program shall incorporate the conditions of 10 CFR 50.55a(b)(5) on ASME Code Case N-597-2.

The COL applicant is to provide material specifications that will be utilized for ASME Section III components (COL 10.3(6)).

10.3.7 Combined License Information COL 10.3(1) The COL applicant is to provide operating and maintenance procedures in accordance with NUREG-0927 and a milestone schedule for implementation of the procedure.

COL 10.3(2) The COL applicant is to establish operational procedures and maintenance programs as related to leak detection and contamination control.

COL 10.3(3) The COL applicant is to provide secondary side water chemistry threshold values and recommended operator actions for chemistry excursions in compliance with the latest version of the EPRI PWR Secondary Water Chemistry Guidelines in effect at the time of COLA submittal. The COL applicant is to establish the operational water chemistry program six months before fuel load.

COL 10.3(4) The COL applicant is to provide the description about the material specifications for components between 1) the high pressure turbine and the moisture separator reheater and 2) the moisture separator reheater and the low pressure turbine when the T/G design is selected. The COL applicant is also to specify that the pipe thickness is adequate for the plant design life in terms of FAC in place of the components between 1) the high pressure turbine and the moisture separator reheater and 2) the moisture separator reheater and the low pressure turbine when the T/G design is selected.

COL 10.3(5) The COL applicant is to provide a description of the FAC monitoring program. The description is to address consistency with GL 89-08 and 10.3-25 Rev. 2

APR1400 DCD TIER 2 NSAC-202L-R3 and provide a milestone schedule for implementation of the program. The program shall incorporate the conditions of 10 CFR 50.55a(b)(5) on ASME Code Case N-597-2.

COL 10.3(6) The COL applicant is to provide material specifications that will be utilized for ASME Section III components.

10.3.8 References

1. Regulatory Guide 1.155, Station Blackout, U.S. Nuclear Regulatory Commission, August 1988.

2. 10 CFR 50.63, Loss of All Alternating Current Power, U.S. Nuclear Regulatory Commission.

3. Regulatory Guide 1.115, Protection Against Turbine Missiles, Rev. 2, U.S. Nuclear Regulatory Commission, January 2012.

4. Regulatory Guide 1.117, Tornado Design Classification, Rev. 1, U.S. Nuclear Regulatory Commission, April 1978.

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

6. ANSI/ASME B31.1, Power Piping, The American Society of Mechanical Engineers, 2010.

7. 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.

8. 10 CFR 50.55a(f), Inservice testing requirements, U.S. Nuclear Regulatory Commission.

9. Regulatory Guide 4.21, Minimization of Contamination and Radioactive Waste Generation: Life-cycle Planning, U.S. Nuclear Regulatory Commission, June 2008.

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

10.3-26 Rev. 2

APR1400 DCD TIER 2

11. Regulatory Guide 1.84, Design and Fabrication Code Case Acceptability ASME Section III Division 1, Rev. 35, U.S. Nuclear Regulatory Commission, October 2010.

12. ASME NQA-1, Quality Assurance Requirements for Nuclear Facility Applications, The American Society of Mechanical Engineers, the 2008 Edition with the 2009 Addenda.

13. Regulatory Guide 1.28, Quality Assurance Program Requirements (Design and Construction), U.S. Nuclear Regulatory Commission, June 2007.

14. Regulatory Guide 1.50, Control of Preheat Temperature for Welding of Low-Alloy Steel, Rev. 0, U.S. Nuclear Regulatory Commission, May 1973.

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

16. EPRI Report 1011838, Recommendations for an Effective Flow- Accelerated Corrosion Program (NSAC-202L-R3), Electric Power Research Institute, May 2, 2006.

17. NUREG-1344, Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants, 1989.

18. Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, U.S. Nuclear Regulatory Commission, May 2, 1989.

19. ASME B36.10M, Welded and Seamless Wrought Steel Pipe, The American Society of Mechanical Engineers, 2004.

20. 10 CFR 20.1406, Radiological Criteria for Unrestricted Use, U.S. Nuclear Regulatory Commission.

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

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

10.3-27 Rev. 2

APR1400 DCD TIER 2 Table 10.3.2-1 (1 of 2)

Main Steam System and Component Design Data Main Steam System Design Data Description Value 2

MSS design pressure/temperature 84.37 kg/cm A (1,200 psia) /

298.9 °C (570 °F)

MSS operating pressure/temperature 69.74 kg/cm2A (992 psia) /

(at SG steam nozzle outlets) 284.2 °C (543.6 °F)

Total main steam flow (MGR condition) 8.14 x 106 kg/hr (17.95 x 106 lb/hr)

Component Design Data Main Steam Piping Number of main steam lines 4 Steam flow, kg/hr (lb/hr) 8.14 x 106 (17.95 x 106)

Pipe size, ID, m (in.) 0.72662 (28.607)

Design pressure, kg/cm2A (psia) 84.37 (1,200)

Pipe material Carbon steel Design Code ASME Section III, Class 2 Seismic Category I Main Steam Isolation Valves (MSIVs)

Valve type EH (electro-hydraulic)

Valve size, mm (in.) 813 (32)

Number of MSIVs per main steam line 1 Total number of MSIVs 4 Design Code ASME Section III, Class 2 Seismic Category I Main Steam Isolation Valve Bypass Valves (MSIVBVs)

Valve type EH (electro-hydraulic)

Valve size, mm (in.) 100 (4)

Number of MSIVBV per main steam line 1 Total number of MSIVBVs 4 Design Code ASME Section III, Class 2 Seismic Category I 10.3-28 Rev. 2

APR1400 DCD TIER 2 Table 10.3.2-1 (2 of 2)

Main Steam Atmospheric Dump Valves (MSADVs)

Valve type EH (electro-hydraulic), modulating Valve size, mm (in.) 400(16)

Number of MSADV per main steam line 1 Total number MSADVs 4 Design relieving capacity per valve, 100 % 498,952 (1,100,000) open, kg/hr (lb/hr)

(at 70.31 kg/cm2A (1,000 psia))

Controllable capacity per valve, kg/hr (lb/hr) 28,576 (63,000)

(at 77.34 kg/cm2A (1,100 psia))

Design Code ASME Section III, Class 2 Seismic Category I Main Steam Safety Valves (MSSVs)

Valve type Spring loaded type Valve size, in and out, mm (in.) 150 x 250 (6 x 10)

Number of MSSVs per main steam line 5 Total number of MSSVs 20 Set pressure, kg/cm²G (psig)

No. 1 82.54 (1,174)

No. 2 84.72 (1,205)

No. 3 ~ No. 5 86.48 (1,230)

Required minimum total relieving capacity 8.62 x 106 (19 x 106) of the 20 MSSVs at 110 % of SG design pressure, kg/hr (lb/hr)

Required minimum relieving capacity per 4.31 x 105 (0.95 x 106) one valve at 110 % of SG design pressure, kg/hr (lb/hr)

Required maximum limit relieving capacity 9.07 x 105 (2.0 x 106) per one valve at 70.31 kg/cm2A (1,000 psia),

kg/hr (lb/hr)

Design pressure, kg/cm²G (psig) 86.48 (1230)

Design temperature, °C (°F) 298.9 (570)

Design Code ASME Section III, Class 2 Seismic Category I 10.3-29 Rev. 2

APR1400 DCD TIER 2 Table 10.3.2-2 Main Steam Piping Design Data Outside Segment Material Specification NPS DN Diameter (in) Remark ASME Class SG to containment SA-106 Gr.C (seamless) N/A N/A 30.907 Special Pipe Section III, penetration Class 2 Containment penetration SA-106 Gr.C (seamless) N/A N/A 30.907 Special Pipe Section III, to MSVH 32.311 Class 2 Fittings SA-234 WPC N/A N/A 30.907 Special Pipe Section III, 32.311 Class 2 MSVH to MS pipe A-106 Gr.C (seamless) N/A N/A 31.607 Special Pipe B31.1 enclosure Fittings A-234 WPC 24 600 Larger than - B31.1 24.000 MS pipe enclosure A-106 Gr.C (seamless) N/A N/A 31.607 Special Pipe B31.1 to main steam header Main steam header A-672 Gr.B70 (welded) N/A N/A 59.75 Special Pipe B31.1 Main steam header to MSV A-106 Gr.C (seamless) N/A N/A 28.85 Special Pipe B31.1 Fittings A-234 WPC 24 600 Larger than - B31.1 24.000 10.3-30 Rev. 2

APR1400 DCD TIER 2 Table 10.3.2-3 Main Steam Branch Piping Design Data (2.5 Inches and Larger)

Outside Segment Material Specification NPS DN Diameter (in) Remark ASME Class Main steam piping to SA-106 Gr. C 20 500 20.000 - Section ,

MSADV (seamless) Class 2 MSADV discharge piping to A-106 Gr. C 16 400 16.000 - B31.1 silencer (seamless)

Main steam piping to MSSV SA-105 6 150 6.625 - Section ,

Class 2 MSSV discharge piping to A-106 Gr. C 10 250 10.750 - B31.1 vent stack (seamless) 26 650 26.000 Main steam piping to pipe SA-333 Gr. 6 8 200 8.625 - Section ,

chase (seamless) Class 2 Pipe chase to AF pump SA-106 Gr. B 8 200 8.625 - Section ,

turbine steam isolation valve (seamless) Class 3 2.5 and 65 and 2.875 and - Section ,

Fittings ASTM (S)A-234 WPB larger larger larger Class 3 10.3-31 Rev. 2

APR1400 DCD TIER 2 Table 10.3.2-4 (1 of 2)

Feedwater Piping Design Data (2.5 Inches and Larger)

Outside Segment Material Specification NPS DN Diameter (in) Remark ASME Class Feedwater pump to feedwater A-106 Gr.B 24 600 24.000 - B31.1 pump discharge header (seamless)

Feedwater pump discharge A-672 Gr.B60 30 750 30.000 - B31.1 header (welded)

Feedwater pump discharge A-672 Gr.B60 (welded) 26 650 26.000 - B31.1 header to Feedwater heaters 5/6/7 32 800 32.000 Feedwater heaters 7 to Feedwater A-672 Gr.B60 (welded) 26 650 26.000 - B31.1 heaters 7 outlet header Feedwater heaters 7 outlet header A-672 Gr.B60 (welded) 32 800 32.000 - B31.1 Fittings A-234 WPB 24 600 24.000 - B31.1 A-234 WPC 26 650 26.000 30 750 30.000 32 800 32.000 Feedwater heaters 7 outlet header A-106 Gr.B 10 250 10.750 - B31.1 to MSVH (seamless,welded) 24 600 24.000 Fittings A-234 WPB 10 250 10.750 B31.1 24 600 24.000 10.3-32 Rev. 2

APR1400 DCD TIER 2 Table 10.3.2-4 (2 of 2)

Outside Segment Material Specification NPS DN Diameter (in) Remark ASME Class MSVH to MFIV SA-333 Gr.6 10 250 10.750 - Section ,

(seamless) 24 600 24.000 Class 2 MFIV to SG SA-335 Gr. P22 6 150 6.625 - Section ,

(seamless) 10 250 10.750 Class 2 14 350 14.000 24 600 24.000 Fittings SA-234 WP22 6 150 6.625 - Section ,

10 250 10.750 Class 2 14 350 14.000 24 600 24.000 10.3-33 Rev. 2

APR1400 DCD TIER 2 Table 10.3.2-5 Main Steam and Feedwater Piping Fluid Data Flow Rate Temperature Pressure Segment Fluid kg/hr (lb/hr) ºC (ºF) kg/cm²A(psia)

Main steam piping Steam 8.14 x 106 284.2 69.75 ASME Class 2 (17.95 x 106) (543.6) (992)

Feedwater piping Water 8.16 x 106 232.2 74.17 ASME Class 2 (17.99 x 106) (450.0) (1,055) 10.3-34 Rev. 2

APR1400 DCD TIER 2 Table 10.3.2-6 Main Steam Branch Piping (2.5 Inches and Larger), Between the MSIVs and the Turbine Stop Valves Max. Steam Description Flow Shutoff Valve Valve Closure Time Actuator Comments Turbine bypass 1,292,000 lb/hr 16 in (406.4 mm) globe within 5 sec when the Air operated ; Fail close Valves are normally closed during power lines to condenser ; (162.79 kg/s), (turbine bypass valve) permissive signal from the operation 8 lines total each lines SBCS Reheating steam 2nd 413,500 lb/hr 12 in (304. 8mm) Gate (( Max. 49 sec ))1) Motor operated ; Jogging/Fail-As-Is Flow to reheater ceases following valve stage to MSRs ; (52.1 kg/s), (isolation valve) closure due to turbine trip or main steam 2 lines total each lines isolation signal.

Main steam supply 476,000 lb/hr 10 in (254 mm) globe (( Max. 60 sec ))1) Motor operated ; There is no flow to this line during power to auxiliary steam (59.975 kg/s) (isolation valve) Fail-As-Is operation. Valve is automatically closed system. ; by MSIV close fail signal.

1 line High pressure 4,504,000 lb/hr 32 in (812.8 mm) gate 0.3 sec Electro-Hydraulic operated, Fail close Main steam flow to high pressure turbine turbine steam (567.49 kg/s), (HP turbine stop valve) ceases following stop valve closure on a supply lines ; each lines turbine trip 4 lines total Main steam supply 38,987 lb/hr 4 in (101.6 mm) gate (( - ))1) Motor operated ; Fail-As-Is Valve is normally closed during power for turbine steam (4.91 kg/s) (isolation valve) operation.

seal ;

1 line Main steam supply 146,287 lb/hr 6 in gate (( - ))1) Electro-Hydraulic operated, Fail close There is no flow to this line during power to feedwater pump (18.43 kg/s), (H.P. steam inlet stop valve) operation. Valves are closed after receipt turbine , 3 lines each lines of main steam isolation signal.

1) Value determined by valve supplier 10.3-35 Rev. 2

APR1400 DCD TIER 2 Table 10.3.3-1 Main Steam System Failure Modes and Effects Analysis Component Component Active Safety Failure Mode Failure Effect on System Safety No. Name No. Function (Actuation Signal) Method of Failure Detection Function Capability

1. Main steam MS- Protection of secondary Spurious opening or Valve position indication in the No safety-related impact on plant.

safety valves V1301~1320 circuit overpressurization failure to reset after MCR and RSR Refer to Chapters 15 and 16.

(MSSVs) opening The impact from MSSV inadvertent opening and MSSV failure to close is analyzed in the Chap.15.

2. Main steam MS- Isolation of reactor Fails to close Valve position indication in the No safety-related impact on plant.

isolation valve V011~014 containment building. (MSIS) MCR and RSR Refer to Chapters 6, 15, and 16.

(MSIV) The MSIV failure to close is analyzed in Chapters 6 and 15.

3 Main steam MS- Isolation of reactor Fails to close Valve position indication in the No safety-related impact on plant.

isolation valve V015~018 containment building. (MSIS) MCR and RSR Refer to the Chapter 15.

bypass valve MSIVBVs are closed during plant normal (MSIVBV) operation and fail closed upon loss of power. Second isolation valve is provided near the MSIVBV in each MSIV bypass line.

4. Main steam MS- To cool down the RCS Fails to open or to close Valve position indication in the No safety-related impact on plant.

atmospheric V101~104 through a controlled on demand MCR and RSR Refer to the Chapter 15 and 16.

dump valve discharge of steam to the (MSADV) atmosphere 5 MSADV MS- When MSADV fails to Fails to close Valve position indication in the No safety-related impact on plant.

isolation valve V105~108 close, the MSADVIV MCR and RSR Refer to Chapters 15 and 16.

(MSADVIV) isolates the MSADV MSADV isolation valves are locked open during plant normal operation. When MSADV fails to close, the MSADVIV isolates the MSADV.

6 MS line drain MS- Isolation of reactor Fails to close Valve position indication in the No safety-related impact on plant.

isolation valve V090~093 containment building. (MSIS) MCR and RSR 10.3-36 Rev. 2

APR1400 DCD TIER 2 SILENCER INSIDE RCB OUTSIDE RCB (MSVH IN AUX. BLDG)

BI D DD ROOF MSVH MS PIPE TGB BI D ENCLOSURE NT NITROGEN SUPPLY 102 26" 26" 26" 26" 26" BI D BI D BI D BI D BI D BI D 16" MAIN STEAM 1302 1304 1306 1308 1310 ISOLATION VALVE V1257 E

H FC MAIN STEAM ATMOSPHERIC ESF-MSIS ESF-MSIS DUMP VALVE CLOSE CLOSE 20" 106 TEW DMA-MSIS MSVH : MAIN STEAM VALVE HOUSE SET @ 1174 SET @ 1205 SET @ 1230 SET @ 1230 SET @ 1230 PT 001 CLOSE PSIG PSIG PSIG PSIG PSIG M LO I 012 TGB  : TURBINE GENERATOR BUILDING E

H IRU 30.907" PC 32.311" 30.907" 31.607" SHEET 2 "A" MS  : MAIN STEAM 0611 FC MAIN STEAM SAFETY VALVES ESF-MSIS CLOSE 4" AFW : AUXILIARY FEEDWATER 020 091 DRAIN TO DRAIN TO MSIVBV : MAIN STEAM ISOLATION VALVE BYPASS VALVE 12" M 12" DRAIN HEADER A DRAIN HEADER B 2"

E H 2" SHEET 2 "E" SHEET 2 "F" SILENCER FC MSIVBV FC 016 ROOF BI D BI D NT NITROGEN SUPPLY ESF-MSIS ESF-MSIS 101 26" 26" 26" 26" 26" BI D BI D BI D BI D BI D CLOSE CLOSE BI D 16" MAIN STEAM 1301 1303 1305 1307 1309 ISOLATION VALVE V1030 E

H FC MAIN STEAM ATMOSPHERIC ESF-MSIS ESF-MSIS DUMP VALVE CLOSE CLOSE 20" 105 TEW DMA-MSIS SET @ 1174 SET @ 1205 SET @ 1230 SET @ 1230 SET @ 1230 PT PSIG PSIG PSIG PSIG PSIG 002 CLOSE M LO 011 I E IRU H

32.311" 30.907" PC 30.907" 31.607" SHEET 2 "B" 0612 FC MAIN STEAM SAFETY VALVES ESF-MSIS FT FT 1011X 1012X CLOSE 4" 019 IRU IRU ESF-AFAS-1 BI CI 090 12" OPEN DRAIN TO DRAIN TO MSVH PIPE 12" M 2" FT FT DPS-AFAS-1 CHASE DRAIN HEADER C DRAIN HEADER D 1011Y 1012Y 110 AT AUXILARY FW 2" E OPEN SHEET 2 "G" H SHEET 2 "H" IRU IRU PUMP TURBINE A FC MSIVBV 8" LO PT FO AFW PUMP TBN STM FC PT V1151 1013A 1013D SUPPLY V/V 015 IRU 112 IRU AFW PUMP TBN BI D 1" WARMUP V/V LT PT PT 1013C 1013B FO ESF-MSIS ESF-MSIS v1153 IRU IRU CLOSE CLOSE STEAM GENERATOR 1

SILENCER BI D ROOF NT NITROGEN SUPPLY 26" 26" 26" 26" 26" 104 BI D BI D BI D BI D BI D MAIN STEAM BI D 16" ISOLATION VALVE 1312 1314 1316 1318 1320 V1051 E

H FC MAIN STEAM ESF-MSIS ESF-MSIS ATMOSPHERIC CLOSE CLOSE 20" DUMP VALVE PT 108 TEW DMA-MSIS SET @ 1174 SET @ 1205 SET @ 1230 SET @ 1230 SET @ 1230 003 CLOSE M LO PSIG PSIG PSIG PSIG PSIG IRU I 014 E H

30.907" PC 32.311" 30.907" 31.607" SHEET 2 "C" 0622 MAIN STEAM SAFETY VALVES FC ESF-MSIS CLOSE 022 ESF-AFAS-2 4" OPEN BI CI DRAIN TO 093 DRAIN TO 12" DPS-AFAS-2 PIPE 12" M DRAIN HEADER F MSVH CHASE DRAIN HEADER E 2" OPEN 2" E

SHEET 2 "J" 109 AT AUXILARY FW SHEET 2 "I" H

FC MSIVBV PUMP TURBINE B 8" LO FC V1152 FO AFW PUMP TBN STM 018 111 SUPPLY V/V BI D AFW PUMP TBN 1" WARMUP V/V LT FO v1154 ESF-MSIS ESF-MSIS SILENCER CLOSE CLOSE ROOF BI D 26" 26" 26" 26" 26" NT NITROGEN SUPPLY 103 BI D BI D BI D BI D BI D MAIN STEAM BI D 16" 1311 1313 1315 1317 ISOLATION VALVE 1319 V1073 E

H FC MAIN STEAM ATMOSPHERIC ESF-MSIS ESF-MSIS DUMP VALVE CLOSE CLOSE 20" 107 SET @ 1174 SET @ 1205 SET @ 1230 SET @ 1230 SET @ 1230 TEW DMA-MSIS PT PSIG PSIG PSIG PSIG PSIG 004 CLOSE M LO I 013 IRU E

H 30.907" PC 32.311' 30.907" 31.607" SHEET 2 "D" 0621 FC MAIN STEAM SAFETY VALVES ESF-MSIS CLOSE 021 092 4" DRAIN TO 12" DRAIN TO 12" M DRAIN HEADER G E 2" DRAIN HEADER H 2" H SHEET 2 "K" SHEET 2 "L" FC MSIVBV FT FT 1021X 1022X FC IRU IRU 017 FT FT BI D 1021Y 1022Y IRU IRU ESF-MSIS ESF-MSIS CLOSE CLOSE PT PT 1023A 1023D IRU IRU PT PT 1023C 1023B IRU IRU STEAM GENERATOR 2

Figure 10.3.2-1 Main Steam System Flow Diagram (1 of 2) 10.3-37 Rev. 2

APR1400 DCD TIER 2 SHEET 1 "G" MS DRAIN SHEET 1 "K" SHEET 1 "F" SHEET 1 "E" MS DRAIN SHEET 1 "J" MS DRAIN MS DRAIN MS DRAIN MS DRAIN MS DRAIN MS DRAIN FT DRAIN FT DRAIN FT DRAIN SHEET 1 "I" SHEET 1 "L" SHEET 1 "H" D C B A PS SECONDARY SAMPLING 2" 2" 2" 1/2 2" 2" 2" 2" 2" 2" 2" 2" 2" 2" 2" 2" FT FEEDWATER FT FEEDWATER FT FEEDWATER 10" 6" 31.607" PUMP TURBINE A PUMP TURBINE B PUMP TURBINE C SHEET 1 "A" 10" CD CONDENSER A 10" MAIN STEAM DRAIN HEADER 12" 2"

A 6" 6" 6" M TA SECOND STG REHEATER A 12" 10" 6" CD DRAIN TO CONDENSER A 2"

PS SECONDARY SAMPLING 1/2 32.131" 31.607" SHEET 1 "B" 12" CD DRAIN TO CONDENSER A LO TA TURNINE STEAM SEAL 2" 4"

12" V1102 2"

B WS CD CONDENSER B AS AUX. STEAM LO WS LO HEADER 16" 24" 10" V1118 FC FT : FEEDWATER PUMP TURBINE TA HP TURBINE MAIN STOP VALVE A 28.850" WS WS CD CONDENSER B 16" LO 24" LO TA HP TURBINE MAIN FC V1146 STOP VALVE B 28.850" TEW I

24" WS WS CD CONDENSER C 16" LO 24" LO TO T/G CONTROL PT SYSTEM FC V1128 PI TA HP TURBINE MAIN STOP VALVE C 28.850" TO T/G TE WS WS CD CONDENSER C CONTROL 16" LO 24" LO SYSTEM 131 TA HP TURBINE MAIN M TA SECOND STG STOP VALVE D REHEATER B FC V1142 28.850" TURBINE BYPASS VALVES PS SECONDARY SAMPLING 1/2 32.131" 31.607" CD DRAIN TO CONDENSER A SHEET 1 "C" 12" 2"

12" 2"

C WS CD CONDENSER A 16" LO WS 24" LO FC WS CD CONDENSER A 16" LO WS 24" LO FC PS SECONDARY SAMPLING 1/2 LO WS WS CD CONDENSER A 16" LO 24" 24" FC 31.607" SHEET 1 "D" 12" 2"

D WS CD CONDENSER B 16" LO WS 24" LO FC V1132 TURBINE BYPASS VALVES Figure 10.3.2-1 Main Steam System Flow Diagram (2 of 2) 10.3-38 Rev. 2

APR1400 DCD TIER 2 HS ABOVE 65%

PI TURBINE LOAD M

019 VENT TO ATMOSPHERE 14 "

MAIN STEAM PI 14" 1201 40" 1202 36" 1203 36" 020 24" 28" 24" 26" 24" 26" 42" 12" 12" 14" 20" 18" 18" 42" 10" 10" 42" ZL ZL PI 2ND STAGE REHEATER M MOISTURE SEPERATOR 021 REHEATER (MSR) A 904 908 14" E E HT01 PI PI PI H H 28" 32" 14" 1ST STAGE REHEATER MS PIPE 10" STOP CONTROL VALVE VALVE 10" 48" 48" 48" 48" PI 22" PI HPFWH 5A TI TI TI 22" HPFWH 5A ZL ZL PI 16" FWPT 42" 42" 42" E

H 901 905 E H 42" 28" 32" V915 INTERCEPT VALVE V911 INTERCEPT VALVE V913 INTERCEPT VALVE E E MS PIPE H E H H

ZL C.I.V. 1 ZL C.I.V. 3 ZL C.I.V. 5 STOP CONTROL PI PI PI PI E

H V921 INTERMEDIATE E V923 INTERMEDIATE H E

V925 INTERMEDIATE VALVE STOP VALVE H

VALVE STOP VALVE STOP VALVE PI PI PI PI HIGH PRESSURE TURBINE LOW PRESSURE TURBINE A LOW PRESSURE TURBINE B LOW PRESSURE TURBINE C TA01 TA02 TA03 TA04 PI PI ZL ZL INTERMEDIATE ZL INTERMEDIATE ZL INTERMEDIATE 11/2" E H V922 STOP VALVE E H V924 STOP VALVE H E

V926 STOP VALVE C.I.V. 2 C.I.V. 4 C.I.V. 6 ZL E H V912 INTERCEPT E V914 INTERCEPT H E

V916 INTERCEPT PI H

VALVE VALVE VALVE PI 11/2" 11/2" 11/2" 11/2" 11/2" E 902 E 906 HS ABOVE 65% 11/2"X21/2" H H TURBINE LOAD 28" 32" PI 21/2"X3" MS PIPE M STOP CONTROL 022 3" VENT TO ATMOSPHERE TI TI TI VALVE VALVE 16" FWPT 14" MS PIPE PI PI 36" 2" 1204 40" 1205 36" 1206 PI PI PI 14" V1017 24" 28" 24" 26" 24" 26" 42" 023 12" 12" 14" 42" ZL ZL 42" 20" 18" 18" 073 10" 3" 2" 3" 10" COPD V1003 V1115 E 903 E 907 H H 28" 32" 2ND STAGE REHEATER MS PIPE PI STOP CONTROL VALVE VALVE M MOISTURE SEPERATOR 024 REHEATER (MSR) B HT02 PI 14" 10" 1ST STAGE REHEATER PI PI 10" 48" 48" 48" 48" PI 42" 42" 42" 42" COPD : CONDENSATE PUMP DISCHARGE 22" FWPT : FEEDWATER PUMP TURBINE 22" HPFWH : HP FEEDWATER PUMP HEATER MS : MAIN STEAM HPFWH 5B HPFWH 5B Figure 10.3.2-2 Turbine System Flow Diagram 10.3-39 Rev. 2

APR1400 DCD TIER 2 10.4 Other Features of the Steam and Power Conversion System 10.4.1 Main Condensers 10.4.1.1 Design Bases The main condenser is designed to condense the low-pressure turbine exhaust steam so that the condensate can be efficiently pumped through the steam cycle. The main condenser also serves as a collection point for the following:

a. Feedwater heater drains and vents

b. Miscellaneous equipment drains and vents

c. Feedwater pump turbine exhaust steam The main condenser is also designed to condense up to 55 percent of the total full-power steam flow bypassed directly to the condenser by the turbine bypass system (TBS). The steam is bypassed to the condenser in case of a sudden load rejection of the T/G or a turbine trip, and at plant startup and shutdown as addressed in Subsection 10.4.4. The condenser is designed in accordance with the Heat Exchange Institute (HEI) Standards for Steam Surface Condensers (Reference 1). The condenser is a single-pressure, three-shell, and single-pass surface condenser. Each condenser shell consists of two parallel tube bundles to permit maintenance and cleaning during operation.

10.4.1.2 System Description The main condenser is part of the condensate system. The condensate system is addressed in Subsection 10.4.7.

Classification of equipment and components is given in Section 3.2.

The following functional requirements of the main condenser are met to provide reasonable assurance of a reliable system:

a. The main condenser hotwells serve as storage reservoirs for the condensate and feedwater systems with sufficient volume to supply maximum condensate flow for 5 minutes.

10.4-1 Rev. 2

APR1400 DCD TIER 2

b. The condenser vacuum system in the main condenser is designed to remove leaked air and non-condensable gases from condensing steam. The condenser vacuum system is described in Subsection 10.4.2.

c. The circulating water system (CWS) is routed to each of three condenser shells in a parallel configuration. Heat is removed from the main condenser by the CWS.

d. The condenser tube material is titanium and tube sheets are titanium-clad carbon steel as specified in Table 10.4.1-1, or equivalent material. The titanium material provides good corrosion- and erosion-resisting properties.

e. Condenser design precludes or minimizes steam impingement forces on the condenser tubes for normal operation and turbine bypass valve quick-opening events. Tube support plates are designed to minimize tube vibrations.

f. The tube leak detection system is provided to permit sampling of the condensate in the condenser hotwell as described in Subsection 9.3.2. The tube leak detection system identifies which tube bundle has sustained leakage using sampling from condenser tube tray if circulating water inleakage occurs. The affected condenser hotwell is manually isolated by closing the motor-operated hotwell discharge valve when condenser tube leakage exceeds the design value for the condensate polishing system (CPS). Plant power is reduced as necessary. The waterbox is then drained into the condenser pit sumps (north/south) through piping that is part of the equipment vents and drains system and the affected tubes are either repaired or plugged. The waterbox drains are monitored and controlled for process radiation through the condenser pit sumps and a condensate polishing area sump.

g. The condenser is designed to deaerate the condensate during startup and normal operation. The design also deaerates any drains that enter the condenser.

h. In the event that the condenser tube leakage is beyond the design limit of the CPS, the condenser and CWS are designed to permit isolation of a portion of the tubes (segmented condenser) to permit repair of leaks while operating at reduced power (i.e., draining of waterboxes and repairing or plugging the affected tubes)

i. The condenser is capable of being filled with water for a hydrostatic test.

Provisions are made to allow draining and cleaning of the hotwell.

10.4-2 Rev. 2

APR1400 DCD TIER 2

j. An expansion connection between the condenser neck and the turbine exhaust is provided.

k. Heater shells and piping installed in the condenser neck are located outside the turbine exhaust steam high-velocity regions. Internal piping is as short and straight as possible, and all steam-extraction piping slopes downward toward the heater shells.

l. The condenser shells are protected from the high internal pressure by using the relief diaphragm on the top of the low-pressure (LP) hood. If the pressure inside the LP hood exceeds atmospheric pressure, the relief diaphragm pops, and the steam inside the LP turbine is released to the air. The condenser shells have pressure transmitters to detect loss of the condenser vacuum. When the pressure from the pressure transmitters exceeds the setpoint, a turbine trip signal is generated.

m. The CPS is in full-flow operation or partial-flow operation when condensate purification is required under all load conditions. The design limit and operation period of the CPS against the condenser tube leakage without affecting the condensate/feedwater quality for safe reactor operation are addressed in Subsection 10.4.6.

10.4.1.3 Safety Evaluation The condenser does not perform any safety-related function and does not require safety evaluation.

The condenser is normally used to remove residual heat from the reactor coolant system (RCS) during the initial cooling period after plant shutdown when the main steam is bypassed to the condenser through the turbine bypass system. The condenser is also used to condense the main steam bypassed to the condenser in the event of sudden load rejection by the T/G or a turbine trip.

In the event of load rejection, the condenser condenses 55 percent of full-load main steam flow from the turbine bypass system without tripping the reactor. If the main condenser is not available during normal plant shutdown, sudden load rejection, or turbine trip, the spring-loaded main steam safety valves (MSSVs) can discharge full main steam flow to the atmosphere to protect the main steam system (MSS) from overpressure. Safe reactor 10.4-3 Rev. 2

APR1400 DCD TIER 2 shutdown can then be achieved by use of the main steam atmospheric dump valves (MSADVs). Unavailability of the main condenser considered here includes failure of the circulating water pumps to supply cooling water or loss of condenser vacuum for any reason.

During normal operation and shutdown, the main condenser does not have radioactive contaminants. Radioactive contaminants are only through primary-to-secondary system leakage due to steam generator (SG) tube leaks. The radiological aspects of primary-to-secondary leakage, including operating concentrations of radioactive contaminants, are addressed in Subsection 11.1.1.3. If high radiation is detected in the condenser vacuum system discharge, the off-gases are automatically diverted to containment drain sump area for removing the contaminants based on GDC 60. Detailed methods to preclude the accidental release of radioactive materials to the environment in excess of established limits are addressed in Subsection 10.4.2. There is no hydrogen buildup in non-condensable gas constituents in the main condenser, which are addressed in Subsection 10.4.2. The non-condensable gases are removed by the mechanical vacuum pumps, which are addressed in Subsection 10.4.2.

Flooding due to failure of a condenser hotwell does not prevent safe shutdown of the reactor. The flood height due to the failure of the main condenser in the T/G building is determined as 4.0 ft from El. 100 ft 0 in of the T/G building. Floodwater is drained to the outside of the T/G building through the emergency flood relief opening (flood relief panel),

which is installed at El. 100 ft-0 in of the building. Flooding from the T/G building does not enter the safety-related building because the opening or access door between the turbine building and auxiliary building is located at a higher level than the flood height of the T/G building. Also plant grading and drainage, as described COL 3.4(1), and watertight doors that are installed at the exterior entrances of the safety-related building as described in Subsection 3.4.1.4 will mitigate the T/G building flooding. Because the T/G building contains non-safety-related equipment and other buildings are not affected by T/G building flooding, the impact of internal flooding from the T/G building is limited to non-safety-related equipment in the T/G building.

10.4.1.4 Inspection and Testing Requirements The condenser is tested in accordance with the HEI Standards for Steam Surface Condensers. The condenser is designed to be capable of being filled with water for hydrostatic tests. The condenser shells, hotwells, and waterboxes are provided with 10.4-4 Rev. 2

APR1400 DCD TIER 2 access openings to permit inspection and repairs; periodic visual inspections of and preventive maintenance on condenser components are conducted according to normal industrial practice.

10.4.1.5 Instrumentation Requirements All of the instrumentation for the condenser is for normal power operation, and is not required for safe shutdown of the reactor. Sufficient instrumentation is provided throughout the plant power generation systems to facilitate an accurate heat energy balance of the plant.

Hotwell level and pressure indications are provided locally, and associated alarms are provided in the main control room (MCR) for each condenser shell. The condenser hotwell level is maintained by receiving condensate from condensate storage tank and directing condensate overflow to the condensate overflow storage sump. Condensate temperature (measured in the condensate system), condenser pressure, circulating water temperature and pressure, and differential pressure from waterbox-to-waterbox are monitored and used to verify main condenser operation.

Turbine trip is activated by pressure transmitters located in the condenser shells upon a loss of condenser vacuum when the condenser pressure reaches or exceeds the setpoint

((0.26 kg/cm2 A (7.5 in HgA))).

Refer to Subsection 7.7.1.1 for a description of the process component control system, which provides the applicable non-safety remote monitoring and controls from the MCR.

10.4.2 Condenser Vacuum System 10.4.2.1 Design Bases The condenser vacuum system is designed to:

a. Remove air and non-condensable gases from the condenser

b. Maintain adequate condenser vacuum for proper turbine operation during startup and normal operation The condenser vacuum system is designed to prevent an uncontrolled release of radioactive material to the environment. The condenser vacuum system vents the non-condensable 10.4-5 Rev. 2

APR1400 DCD TIER 2 gases to the environment in accordance with GDC 60 and 64. System components conform with the requirements of NRC RG 1.26 and 1.28 (References 2 and 3, respectively) and Heat Exchanger Institute (HEI) Standards for Steam Surface Condensers (Reference 1).

All system components meet design code requirements that are consistent with the component quality group and seismic design classification, as described in Section 3.2.

System components in the turbine building are non-seismic and designed in accordance with NRC RG 1.26, Quality Group D. System components in the auxiliary building and-reactor containment building are seismic Category II and Quality Group D, except for the containment isolation portion, which is designed as seismic Category I and Quality Group B.

Piping and valves (Quality Group B and D) are designed in accordance with ASME Section III, Class 2, and ASME B31.1 (References 4 and 5, respectively).

10.4.2.2 System Description 10.4.2.2.1 General Description The condenser vacuum system is shown in Figure 10.4.2-1.

The condenser vacuum system consists of four 33.33 percent capacity skid-mounted vacuum pumps and interconnecting piping, which are used to pull a vacuum on the condenser.

The vacuum pump capacity meets or exceeds the capacity recommended in HEI standard.

The vacuum pumps remove the non-condensable gases from the condenser shells by hogging operation during startup, and by holding evacuation during normal plant operation.

Design parameters of the condenser vacuum pump are shown in Table 10.4.2-1.

10.4.2.2.2 System Operation After the turbine steam seals are established, all vacuum pumps initially remove the air from the main condenser to draw down the pressure of the condenser and LP turbine casings. During normal operation, three vacuum pumps are continuously used. A 10.4-6 Rev. 2

APR1400 DCD TIER 2 standby vacuum pump is automatically activated in the event of excessive air inleakage that results in the rise of condenser backpressure.

A high condenser pressure alarm annunciates in the MCR if the condenser pressure reaches the high-pressure setpoint of ((0.17 kg/cm2A (5 in HgA))). The turbine trips if the condenser vacuum system cannot maintain condenser operating pressure. The effects of a loss of condenser vacuum are described in Subsection 15.2.3.

The condenser vacuum system is also designed to remove non-condensable gases when the turbine bypass system is in operation, such as during hot shutdown. In the event that the condenser vacuum system malfunctions and the condenser becomes unavailable, the RCS heat rejection is accommodated by the MSADVs.

The non-condensable gases are not radioactively contaminated in normal operation. The radioactive materials are processed in this system only if there is a primary-to-secondary SG tube leak due to a steam generator tube rupture (SGTR). If radioactivity in the exhaust flow exceeds acceptable level, the condenser vacuum pump vent effluent monitor actuates an alarm in the MCR and automatically diverts the exhaust flow from vacuum pumps to the containment drain sump area in reactor containment building, and then adequate operating procedures are implemented to preclude significant release to the environment. The effluent monitor design, configuration, and its associated parameters are addressed in Subsections 11.5.2.1 and 11.5.2.2, respectively. The location of radiation detector is shown in Figure 11.5-1. The accumulated gas in the reactor containment building is exhausted to the atmosphere by the low-volume purge air cleaning unit of the reactor containment building purge system addressed in Subsection 9.4.6.2.2.

The exhausted non-condensable gases from the condenser vacuum pumps are controlled and monitored alarm setpoints in accordance with GDC 60 and 64. Conformance with GDC 60 and 64 is addressed in Subsections 3.1.51 and 3.1.55, respectively. The gaseous effluent radiological evaluation is provided in Section 11.3.

Thermal decomposition of hydrazine can be considered as a source of hydrogen within condenser shells. However, a potential for hydrogen buildup within condenser shells does not exist because three vacuum pumps operate continuously during normal operation, and a standby vacuum starts when one vacuum pump fails. Condenser shells are considered to maintain the water vapor content above 58 percent by volume in non-condensable gases in conformance with SRP Subsection 10.4.2 (Reference 6). The trace amounts of oxygen 10.4-7 Rev. 2

APR1400 DCD TIER 2 dissolved in the condensate and condenser hotwell inventory are considered negligible compared to the amounts of air evacuated by the vacuum pumps. Therefore, a potential for explosive mixtures within the condenser shells does not exist.

10.4.2.2.3 Design Features for Minimization of Contamination The condenser vacuum system is designed with specific features to meet the requirements of 10 CFR 20.1406 (Reference 7) and Regulatory Guide 4.21 (Reference 8). The basic principles of NRC 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. The following description summarizes the primary features to address the design and operational objectives for the condenser vacuum system.

The condenser vacuum system has been evaluated for leakage identification from the SSCs that contain radioactive or potentially radioactive materials, the areas and pathways where leakage may occur, and the methods of leakage control incorporated in the design of the system. The leakage identification evaluation indicated that the condenser vacuum system is designed to facilitate early leak detection and the prompt assessment and response to manage collected fluids. Unintended contamination of the facility and the environment is minimized or prevented by the SSC design and facility design, supplemented by operational procedures and programs for inspection and maintenance activities.

Prevention/Minimization of Unintended Contamination

a. The condenser vacuum system components are located in an open area at the foundation level inside the turbine generator building. The components are designed to be skid mounted or provided with drip pan and curb. The floors are sloped, coated and provided with drains that are routed to the local drain hubs.

This design approach prevents the spread of contamination to the facility and the environment.

b. The condenser vacuum system is designed with sufficient capacity and redundancy to support normal operation, including anticipated operational occurrences. The components and piping are fabricated from carbon steel with welded construction for life-cycle planning, minimizing leakage, and unintended contamination of the facility and the environment.

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APR1400 DCD TIER 2 Adequate and Early Leak Detection The condenser vacuum system is designed with automated operation with manual initiation for the different modes of operation. Adequate instrumentation, including level and pressure elements and a radiation monitor, is provided to monitor the operations. Upon receipt of a high radiation signal, the vacuum discharge is diverted to the reactor containment building drain sump, and the vent from that sump is processed through the containment ventilation purge system. This design approach minimizes the spread of contamination and provides early detection.

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 condenser vacuum system components are provided with seal water (demineralized water) for decontamination. Chilled water and other utilities are provided to facilitate operations. The utility connections are designed with a minimum of two barriers to prevent the contamination of clean systems.

Decommissioning Planning

a. The SSCs are designed for the full service life and are fabricated as individual assemblies for easy removal.

b. The SSCs are designed to facilitate decontamination. Design features, such as the welding techniques and surface finishes, are intended to minimize the need for decontamination and hence reduce waste generation.

c. The condenser vacuum system is designed without any embedded or buried piping, thus preventing unintended contamination to the environment and facilitating eventual decommissioning.

Operations and Documentation

a. The condenser vacuum system is located in an open area inside the turbine generator building. Adequate space is provided around the equipment to enable prompt assessment and responses when required.

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b. The COL applicant is to establish operational procedures and maintenance programs as related to leak detection and contamination control (COL 10.4 (1)).

Procedures and maintenance programs are to be completed before fuel is loaded for commissioning.

c. The COL applicant is to maintain the complete documentation of system design, construction, design modifications, field changes, and operations (COL 10.4 (2)).

Documentation requirements are included as a COL information item.

Site Radiological Environmental Monitoring The condenser vacuum system is part of the overall plant and is included in the site radiological environmental monitoring program, for monitoring of the release of non-condensable gases and the potential for environmental contamination. The program includes air sampling and analysis and monitoring of meteorological conditions, hydro-geological parameters, and potential migration pathways of the radioactive contaminants.

The site environmental monitoring program is included as a COL information item.

10.4.2.3 Safety Evaluation The condenser vacuum system is designed as non-safety class with the exception of the containment isolation portion designed as safety Class 2. The condenser vacuum system is not required for safe shutdown of the plant.

10.4.2.4 Inspection and Testing Requirements A performance test for each vacuum pump is performed in accordance with HEI Performance Standard for Liquid Ring Vacuum Pumps (Reference 9). The condenser vacuum system is fully tested and inspected before initial plant operation and is subject to periodic inspections after startup.

10.4.2.5 Instrumentation Requirements The condenser vacuum system includes sufficient instrumentation to provide reasonable assurance of proper operation. All of the instrumentation for this system is for the normal power operation and none is required for safe shutdown of the reactor.

Radiation in the exhaust gases discharged to the atmosphere is continuously monitored by the effluent monitor and indicated in the MCR. The effluent monitor actuates an alarm in 10.4-10 Rev. 2

APR1400 DCD TIER 2 the MCR upon receipt of a high-radiation signal. Details on the process and effluent radiation monitoring and sampling systems are provided in Section 11.5.

10.4.3 Turbine Steam Seal System 10.4.3.1 Design Basis The turbine steam seal system (TSSS) is designed to seal the annular openings where the turbine shaft penetrates the turbine casings to prevent steam outleakage and air inleakage along the turbine shaft. The TSSS also returns the air-steam mixture to the turbine gland steam-packing exhauster, condenses the steam, returns the drains to the main condenser, and exhausts the non-condensable gases to the atmosphere through blowers. The TSSS is designed to prevent uncontrolled release of radioactive material to the environment in accordance with GDC 60 and 64.

All system components are non-seismic and designed in accordance with NRC RG 1.26 (Reference 2), Quality Group D, as described in Section 3.2.

10.4.3.2 System Description The TSSS consists of a steam-seal supply and exhaust header, a gland steam-seal feed valve, turbine steam seal control panel, a gland steam-packing exhauster with two motor-driven blowers, and the associated piping and valves. The TSSS serves both the main turbine and the feedwater pump turbines. For the system to function satisfactorily from startup to full load, a fixed positive pressure in the steam seal supply header and a fixed vacuum in the outer ends of all turbine glands are maintained at all loads. Steam is provided by the main, auxiliary, and extraction steam systems. The TSSS also receives steam-seal leak-off from turbine control valves and main turbine stop valves. The TSSS is shown in Figure 10.4.3-1.

The steam discharge ends of all glands are routed to the gland steam packing exhauster, which is maintained at a slight vacuum by the redundant motor-driven blowers. The gland steam packing exhauster is a shell-and-tube heat exchanger. Condensate from the condensate system is used to condense the steam from the mixture of air and steam drawn from the shaft packing. Drains from the gland steam packing exhauster are returned to the condenser, and the non-condensable gases are vented to the atmosphere through the condenser vacuum system discharge line. The non-condensable gases discharged from the blowers are monitored for radioactivity as addressed in Section 11.5. The non-10.4-11 Rev. 2

APR1400 DCD TIER 2 condensable gases are not radioactively contaminated in normal operation. The non-condensable gases are discharged from the steam packing exhauster blower to the atmosphere. The non-condensable gases are monitored by a radiation monitor installed on the steam packing exhauster blower discharge line.

If radioactivity in the exhaust flow exceeds a predetermined setpoint, an alarm activates in the MCR for operator actions. The operating procedures are implemented in accordance with "Radioactive effluents controls program" described in Technical Specification 5.5.4.

Design and configuration for the effluent monitor, and the associated parameters, are provided in Subsections 11.5.2.1 and 11.5.2.2, respectively. The location of radiation detector is shown in Figure 11.5-1.

During cold startup of the T/G, sealing steam is provided by the auxiliary steam system.

When the SG is brought up to full pressure, the auxiliary steam source is closed, and the main steam provides sealing. As the turbine is brought up to about 50 percent load, steam leakage from the high-pressure packing and the extraction steam system enters the steam-seal header. When this leakage is sufficient to maintain steam-seal header pressure, the main steam source valve is closed, and sealing steam to all turbine seals is supplied from the high-pressure packing and the extraction steam system. When the leakage from the high-pressure packing is more than required by vacuum packing, the excess steam is discharged through the unloading valve to the main condenser.

10.4.3.3 Safety Evaluation The TSSS has no safety function. The TSSS valves are arranged for fail-safe operation to protect the turbine.

10.4.3.4 Inspection and Testing Requirements Tests and inspection of TSSS equipment are performed in accordance with applicable codes and standards. Hydrostatic tests for piping and valves are performed in accordance with ASME B31.1 (Reference 5) and ASME B16.34 (Reference 10), respectively.

Nondestructive inspections are performed in accordance with ASME Section V (Reference 11). The TSSS is functionally tested during unit startup. Normal operating system performance monitoring detects any deterioration in the performance of system components.

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APR1400 DCD TIER 2 10.4.3.5 Instrumentation Requirements The indicating and alarm devices for steam-seal header pressure in local locations and the MCR are provided to monitor the system. A pressure controller is provided to maintain the steam-seal header pressure by signaling to the steam-seal header pressure control valves to discharge the excess steam into the main condenser by providing the signal to the unloading valve. All instrumentation of the TSSS is for the normal power operation, and not required for safe shutdown of the reactor.

10.4.4 Turbine Bypass System The TBS is a part of the MSS. The TBS provides the capability to flow main steam from the SGs to the main condenser, bypassing the main turbine to dissipate heat and to minimize transient effects on the RCS during startup, hot standby, cooldown, and generator step-load reduction.

10.4.4.1 Design Bases The TBS performs no safety-related functions and therefore has no nuclear safety-related design basis. The TBS is located in the T/G building. The TBS takes steam from the main steam line upstream of the turbine stop valves and discharges steam to the condenser.

The TBS is designed to accomplish the following functions:

a. Regulate steam flow to dissipate excess energy from the nuclear steam supply system (NSSS) following load rejections of any magnitude without tripping the reactor or opening the pressurizer pilot-operated safety relief valves (POSRVs) and/or MSSVs in conjunction with steam bypass control system (SBCS) and reactor power cutback system (RPCS) and reactor regulating system (RRS).

b. The TBS has the capacity to bypass 55 percent of the total saturated steam flow at normal full-power SG pressure to the main condenser.

c. Maintain the NSSS thermal conditions at no-load conditions

d. Provide a means for manual control of RCS temperature during NSSS heatup or cooldown.

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APR1400 DCD TIER 2 10.4.4.2 System Description 10.4.4.2.1 General Description The TBS discharges steam from the main steam line upstream of the turbine stop valves to the condenser in conjunction with the SBCS, as described in Subsection 7.7.1.1.d. The TBS consists of eight turbine bypass valves (TBVs) located in two lines (four TBVs per line) branched off from the main steam header and connected to the condensers. This arrangement is shown in Figure 10.3.2-1.

10.4.4.2.2 Component Description 10.4.4.2.2.1 Turbine Bypass Valves The total TBV capacity is 55 percent of the saturated steam flow at normal full-power SG pressure. No single TBV has a maximum capacity greater than 9.07 x 105 kg/hr (2.0 x 106 lb/hr) of saturated steam at normal full-power SG pressure.

TBVs are normally controlled by the SBCS but are capable of remote or local manual operation. The TBVs are equipped with handwheels to permit manual operation at the valve location. The TBVs are fail-closed valves to prevent uncontrolled bypass of steam to the condenser.

The TBVs are connected to the condensers in a manner that provides balanced loading of each condenser section with the valve sequencing as follows:

a. In the modulation mode, the SBCS opens the TBVs sequentially by group in five groups. Group I is valve 1, Group II is valve 2, Group III is valves 3 and 4, Group IV is valves 5 and 6, and Group V is valves 7 and 8.

b. In the quick-opening mode, the SBCS causes quick opening of the TBVs in two four-valve groups. The groups are opened sequentially as required by the magnitude of the load rejection. Group X consists of valves 1 through 4; Group Y consists of valves 5 through 8.

The TBV operating speeds are as follows:

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a. The TBVs stroke from the full-closed position to the full-open position or from the full-open position to the full-closed position in 15 to 20 seconds after the receipt of a modulation signal from the SBCS.

b. The TBVs stroke from the full-closed position to the full-open position in less than 1 second after the receipt of quick-opening signal from the SBCS.

10.4.4.2.3 System Operation 10.4.4.2.3.1 Normal Operation During normal operation, the TBVs are under the control of the SBCS, as described in Subsection 7.7.1.1.d. The SBCS provides control of the TBVs as necessary to remove excess energy from the NSSS. When the plant is in the normal operating mode, the SBCS is on standby and the TBVs are closed. During rapid load changes, if there are transient plant conditions in which the NSSS exceeds the turbine steam requirement, the SBCS provides modulation control of the valves to bypass steam and limit the pressure in the MSS.

10.4.4.2.3.2 Shutdown During hot standby, in order to remove RCP heat at a steady-state rate, at least one TBV is capable of controlling flow at 63,000 lb/hr (28,577 kg/hr) at an SG no-load pressure.

During the initial cooling period after plant shutdown, the main condenser removes decay heat from the RCS through the TBS.

10.4.4.2.3.3 Abnormal Operation Sudden Reduction of Turbine Load In conjunction with the RPCS and RRS, the SBCS dissipates excess energy from the NSSS by regulating steam flow through the TBVs following a load rejection of any magnitude, including a turbine trip from 100 percent power without a reactor trip or opening the POSRVs and/or MSSVs.

The TBVs are modulated based on the comparison of the main steam header pressure to NSSS power index. To increase the load rejection capability of the system, a quick opening of the valves, which overrides the modulation action, is produced when the load 10.4-15 Rev. 2

APR1400 DCD TIER 2 rejection is too large to be accommodated by valve modulation. Additionally, a rapid reduction in reactor power is produced through the RPCS if the magnitude of the load rejection exceeds the SBCS turbine bypass capacity. In this manner, a 100 percent load rejection can be accommodated by the TBVs and RPCS.

If a load rejection occurs concurrently with condenser unavailability, the spring-loaded MSSVs sequentially open with increasing pressure and discharge the required amount of steam to the atmosphere to prevent system pressure from exceeding the MSS maximum design pressure.

The TBVs close automatically or are blocked from opening whenever the condenser is not available.

Closure of Turbine Stop Valves When a rapid reduction of steam flow occurs resulting from a sudden closure of the turbine stop valves, the SBCS immediately generates the quick-open signal to the TBVs.

Large Reduction in Steam Flow If a reduction in steam flow is large enough (due to a sudden reduction in turbine load or a turbine trip), a signal is sent to the RPCS, rapidly reducing the reactor power.

10.4.4.3 Safety Evaluation The TBS has no safety-related function and is not required to operate during or after an accident.

This relieving capacity, in conjunction with the SBCS and RPCS, allows a turbine full load rejection without causing a reactor trip or lifting the POSRVs and/or MSSVs.

The TBVs fail closed upon loss of motive air or electric signal. In the unlikely event that one of the TBVs opens inadvertently, the maximum steam flow through one valve at full-load main steam pressure is less than the maximum permissible flow to limit a reactor transient.

The equipment and high-energy lines of the TBS are located in the turbine building. TBS piping failures would not affect any safety-related equipment because turbine building has no safety-related equipment in the vicinity of the TBS. Therefore, NUREG-0800 BTP 3-3 10.4-16 Rev. 2

APR1400 DCD TIER 2 and BTP 3-4 (References 12 and 13, respectively) are not applicable to the TBS. Pipe failures are addressed in Subsections 3.6.1 and 3.6.2.

10.4.4.4 Inspection and Testing Requirements Preoperational and startup tests conform with the recommendations of NRC RG 1.68 (Reference 14). A test is conducted to verify opening of the TBVs in response to a signal simulating turbine bypass from the SBCS. Additional descriptions of inspection and tests are provided in Subsection 14.2.12.1.29.

10.4.4.5 Instrumentation Requirements The valve position indication, valve inoperable alarm, and valve leakage alarm for the TBVs are monitored both in the MCR and the RSR. The SBCS instrumentation is described in Subsection 7.7.1.1.d.

10.4.5 Circulating Water System The CWS supplies cooling water to the condenser and the T/G building open cooling water system (TGBOCWS). The CW discharged from the condenser and the TGBCCW heat exchanger is ((returned to the cooling tower, where the heat is dissipated to the environment as a heat sink.)) ((The system configuration is site specific. The mechanical draft cooling tower is used as a heat sink.)) The TGBOCWS is described in Subsection 9.2.9.

10.4.5.1 Design Bases The design bases are as follows:

a. The CWS supplies cooling water at a flow rate sufficient to remove heat from the main condenser under all conditions of power plant loading.

b. The CWS is designed to supply the condenser with an adequate amount of cooling water to maintain condenser backpressure within the design limits.

c. The CW pumps are manually tripped in the event of gross leakage into the condenser pit to prevent flooding of the T/G building.

d. ((The cooling towers are designed for wind resistance.))

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e. Each waterbox is designed to be isolated and drained individually during operation in the event of tube leakage.

f. Pressure surges resulting from a hydraulic transient during startup, shutdown, and accidental loss of one or more CW pumps are minimized and would not damage system components.

g. The CWS is designed to meet the requirements of GDC 4, Environmental and Dynamic Effects Design Bases, by including design provisions so the intended safety function of a system or component will not be precluded by the effects of discharging water that may result from a failure of a component or piping in the CWS.

10.4.5.2 System Description The CWS consists of the ((CW pumps, cooling towers,)) condenser and piping, valves, and instrumentation with the following auxiliary systems:

a. Condenser tube cleaning system

b. CW pump bearing lubrication system

c. ((Cooling water makeup and blowdown system))

d. ((Cooling tower chemical injection system))

The CW pumps ((located in the CW pump house take CW from the cooling tower basin))

and supply the six condenser waterboxes through the individual supply conduits. The CW passes along the condenser tubes and is then discharged back to ((the cooling towers))

through the common discharge conduit. ((The cooling water is then distributed to the cooling towers and is returned to the cooling tower basin.))

The COL applicant is to provide the location and design of the cooling tower, basin, and the CW pump house, if used (COL 10.4(3)).

CWS flow diagrams are presented in Figure 10.4.5-1. The system design parameters based on the site-specific design parameters given in Section 2.0, Table 2.0-1, are listed in Table 10.4.5-1.

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APR1400 DCD TIER 2 10.4.5.2.1 Circulating Water Pumps The ((six)) CW pumps are vertical, wet-pit type, single-stage pumps driven by electric motors. ((Each CW pump has a capacity for 16.66 percent of the design flow for the condenser plus 25 percent of the design flow for the TGBCCW heat exchanger.)) As the cooling water temperature decreases, the number of CW pumps in operation can be reduced.

Motor-operated butterfly valves are provided at each CW pump discharge to permit isolation of the pump when it is out of service and at the condenser shell inlet and outlet to allow isolation of line faults or maintenance.

The CW pump discharge butterfly valves are programmed for sequential opening and closing during startup and shutdown of the CWS to prevent pump damage and the initiation of water hammer.

10.4.5.2.2 Condenser Tube Cleaning System The condenser tube cleaning system maintains condenser efficiency at design levels. The condenser tube cleaning system removes biofouling, sediment, corrosion products, and scaling with sponge rubber balls.

10.4.5.2.3 ((Cooling Towers and Auxiliaries))

((The conceptual design of the cooling tower is based on the mechanical draft cooling tower and consist of 56 cells in two rows with fans, motors, and components such as drift eliminators, fills, water distribution, and risers.)) ((The cooling towers have a sufficient capacity to dissipate the heat rejected from main condenser and TGBCCW heat exchanger to the environment in normal plant operation.))

((A basin screen is provided to prevent clogging of the CWS. The screen mesh size is selected to prevent flow blockage of the pump inlets and to limit ingestion of biofouling organics and debris.))

((During normal plant operation, the cooling tower chemical injection system intermittently adds chemicals including biocides. The cooling tower chemical injection system controls the water chemistry. The chemical injection pumps add biocide, algaecide, pH adjuster, dispersant, and corrosion and scale inhibitor to the cooling water. Biocides are used to 10.4-19 Rev. 2

APR1400 DCD TIER 2 control biological growth inside the condenser tubes and the growth of organisms in the basin.))

((The cooling water makeup system provides the raw water to compensate for the loss of water by evaporation, wind drift, and blowdown. Three 50 percent cooling water makeup pump supplies makeup water to the cooling tower basin.))

((The blowdown system controls the concentration of dissolved solids. Three blowdown pumps have 50 percent capacity each and take cooling water from the cooling tower basin and discharges when the conductivity that is proportional to the concentration of dissolved solid of the water is reached the preset value. Blowdown water is treated before discharge to meet regulations or requirements as necessary.))

10.4.5.2.4 Circulating Water Pumps Bearing Lubrication Each CW pump is supplied with an independent CW pump bearing lubrication consisting of a lube water booster pump, filtering equipment, piping, and valves. Provisions are included for freshwater lubrication during startup and shutdown.

10.4.5.2.5 System Operation The CWS operating modes of startup, shutdown, normal, and abnormal operations correspond to the same operation modes for the plant.

During plant startup, the CW pumps start sequentially and manually after initial filling.

During normal plant operation, CW pumps circulate cooling water through the condenser waterboxes. ((Then, the cooling water is distributed to the cooling towers and is returned to the cooling tower basin.)) ((Each cooling tower fan or CW pump is removed from service as the ambient wet bulb temperature or/and cooling load of the plant becomes lower than the design point as condenser vacuum conditions allow.)) Each CW pump is supplied with an independent CW pump lube water system. Lube water drawn from the discharge nozzle of each CW pump is supplied continuously to the individual pump by a lube water booster pump. ((CW bypasses the cooling tower and is delivered directly to the basin through the bypass line if required.))

((The cooling tower chemical injection system)) and condenser tube cleaning system operate during normal plant operation. ((The cooling tower chemical injection system 10.4-20 Rev. 2

APR1400 DCD TIER 2 adds chemicals to the CW to minimize fouling.)) Ball recirculation pumps inject sponge rubber balls upstream of each waterbox. After passing through the condenser tubes, the balls are collected in the strainer section and recirculated.

((The cooling water makeup system and blowdown system operate continuously during normal operation. The operation of cooling water makeup system is interlocked with the water level of cooling tower basin.))

The CWS is not required to operate during plant shutdown, anticipated operational occurrences (AOOs), or accident conditions such as LOOP. However, the CWS may operate until the power and condenser are available during shutdown. ((The cooling tower chemical injection system is removed from service automatically when the CW pumps are not in operation.))

The COL applicant is to confirm that the water hammer events are bounded by the system design pressure value with a hydraulic transient analysis or otherwise demonstrate that the design is acceptable to satisfy GDC 4 in regard to the design provisions that are implemented to accommodate the effects of discharging water that could result from a malfunction or failure of a component or piping in the system (COL 10.4(4)).

If flooding in the yard area occurs due to a failure in a portion of the CWS, the sloped yard will drain the water away from the auxiliary building and compound building, and ((the cooling towers are located sufficiently far from equipment or structures important to nuclear safety.)) The safe shutdown capability would therefore not be compromised by flooding in the yard area. The COL applicant is to provide elevation drawings (COL 10.4(5)).

A postulated failure in the CWS in the T/G building would flood the T/G building basement floor. The flood height due to CW piping failure in the T/G building is determined as 4.0 ft from El. 100 ft 0 in of the building. Floodwater is drained to the outside of the T/G building through the emergency flood relief opening (flood relief panel) which is installed at El. 100 ft 0 in of the building. The only access to the auxiliary building from the T/G building is sufficiently above the T/G building grade elevation, and the floodwater would therefore not enter the auxiliary building. Because there is no safety-related equipment in the T/G building, no safety-related equipment is affected.

A CW line leak is detected with high-high condenser pit water level switches in the condenser pit sump. In the event of gross leakage into the condenser pit, the condenser pit 10.4-21 Rev. 2

APR1400 DCD TIER 2 alarm is initiated and the CW pumps are manually stopped to prevent flooding of the T/G building. When CW inleakage to the main condenser exceeds the design value, the respective CW supply is isolated. The plant may operate at a reduced capacity when either a condenser water box or a CW pump is isolated from the CWS.

10.4.5.2.6 Design Features for Minimization of Contamination The APR1400 is designed with features to meet the requirements of 10 CFR 20.1406 and Regulatory Guide 4.21. 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 CWS.

The CWS contains chemically treated raw water for cooling but may become radioactively contaminated from tube leakage in the condensers. In accordance with RG 4.21, the CWS has been evaluated for leak identification from the system components, primarily the tubes in the condensers that contain radioactive or potentially radioactive steam and condensate, the areas and pathways where probable leak may occur, and methods of control incorporated in the design of the system. The leak identification evaluation indicated that the CWS is designed to provide capability for minimization of crosscontamination, assessment and evaluation of the responses, and methods for mitigation of the leak areas.

Thus unintended contamination of the facility and the environment is minimized or prevented by the design, and by operational procedures and programs for inspection and maintenance activities. Evaporative cooling in the mechanical cooling tower is used for rejection of heat in the CWS. The design of the cooling tower is site specific; The COL applicant is to address the design features for the prevention of contamination (COL 10.4(6)).

Prevention/Minimization of Unintended Contamination

a. The CWS, including all the CWS tubes and associated piping, is designed with corrosion- and erosion-resistant materials for lifecycle planning. The tubes are designed with continuous cleaning features to maintain heat transfer performance and tube integrity, thus minimizing fouling that may result from corrosion.

b. The CWS is designed in conjunction with the turbine generator building drain system. The sumps in the turbine generator building drain system are used to 10.4-22 Rev. 2

APR1400 DCD TIER 2 collect above-ground piping leakages and are equipped with dual level instruments to ensure control of liquid level, thus minimizing the spread of contamination and waste generation.

c. CW is sampled and analyzed periodically to monitor radiological contamination in the water. Contamination detected is to be tracked to the source(s) of leakage and corrective actions (repair and/or isolate through tube plugging) are to be initiated. This design approach minimizes leakage and unintended contamination of the facility and the environment.

d. The facility that houses the system components, including the equipment cubicles that contain radioactively contaminated or potentially contaminated fluid, shall have sloped floors with coating to facilitate the draining of fluid into drain pipes and/or trenches that direct liquid into a local sump.

e. Sumps that contain contaminated or potentially contaminated fluid shall be equipped with level switches to initiate pumping when sump levels reach a predetermined setpoint. The concrete sumps shall be coated and shall have seals to prevent unintended infiltration of liquid. The sumps shall be designed to facilitate periodic maintenance and inspection of the coating.

Adequate and Early Leak Detection CWS leakage is detected by sampling and analysis of the circulating water in the piping and fluid levels in the DTS sumps followed by analysis and inspection. This approach is consistent with industry practices and is effective.

Reduction of CrossContamination, Decontamination, and Waste Generation

a. The SSCs are designed with lifecycle planning through the use of nuclear industry-proven materials compatible with the chemical, physical, and radioactive environment, thus minimizing waste generation.

b. The CWS is designed to operate at a higher pressure than the condenser. This design approach minimizes infiltration of condensate into the circulating water and is effective.

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c. The areas in which the CWS SSCs are housed are designed with sloping floors, epoxy coating to provide drainage and cleanable surfaces, and local sumps to collect leakages and overflows. Cubicle curbs are also provided to reduce cross-contamination and spread of contamination to other areas.

Decommissioning Planning The CWS is designed with some buried piping in the yard because of the piping size. CW is sampled and analyzed periodically to monitor radiological contamination in the water.

Contamination detected is to be tracked to the source of leakage and corrective actions (repair and/or isolate through tube plugging) are to be initiated. This design approach minimizes unintended contamination of the soil surrounding the buried pipe.

Operations and Documentation

a. The CWS is designed for automated operations with manual initiation for the different modes of operation.

b. Adequate ingress and egress spaces are provided for prompt assessment and appropriate response to tube leaks when and where they are needed.

c. The COL applicant is to establish operational procedures and maintenance programs as related to leak detection and contamination control (COL 10.4(1)).

Procedures and maintenance programs are to be completed before fuel is loaded for commissioning.

d. The COL applicant is to maintain complete documentation of the system design, construction, design modifications, field changes, and operations (COL 10.4(2)).

Documentation requirements are included as a COL information item.

Site Radiological Environmental Monitoring The CWS is designed to be a nonradiological system but with the potential of a low level of contamination through leakage in the condenser tubes. Through monitoring, inspection, and lessons learned from industry experiences the integrity of the CWS is well maintained, with no noticeable contamination, or a very low level of contamination of the facility and the environment that is below the detectable limit. Hence the radiological environmental monitoring program is not required for this system.

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APR1400 DCD TIER 2 10.4.5.3 Safety Evaluation The CWS is non-safety-related and is not required for safe shutdown of the plant.

10.4.5.4 Inspection and Testing Requirements The performance test for CW pumps is performed at least every 20 months in accordance with the Hydraulic Institute (HI) standards (Reference 15) or applicable alternate test methods. Performance, hydrostatic, and leakage tests are performed on the butterfly valves in accordance with ANSI/AWWA C504 (Reference 16). ((The performance test for cooling towers is performed in accordance with ASME PTC 23 (Reference 17). The blowdown pumps and cooling water makeup pumps are also tested according to the HI standards or applicable alternate test method.))

10.4.5.5 Instrumentation Requirements CW pumps are controlled from the MCR where pump status is indicated. A CW pump trip is annunciated in the MCR.

CW pump discharge valves, the condenser inlet, and outlet valves are also controlled from the MCR where the valve status is indicated. CW pumps are interlocked to start only after their discharge valves have opened at least 20 percent. The CW pump discharge valve automatically closes when the pump stops.

CW pressures and temperatures at the condenser inlet and outlet are indicated locally and in the MCR. Pressure differential through condenser tubes are indicated locally. ((The water level of the cooling tower basin is indicated, and a low level is annunciated in the MCR.))

((Cooling water in the basin is periodically sampled to control the operation of the cooling tower chemical injection system and blowdown system. The conductivity of cooling water in the basin is measured to monitor the concentration of total dissolved solids and to control the operation of the blowdown system manually or automatically.))

((The cooling water makeup pump is interlocked with the level of cooling tower basin and operates when the water level is lower than predetermined level. The makeup and blowdown flow of cooling water are indicated locally.))

Level switches installed in the condenser pit sump monitor flooding conditions.

10.4-25 Rev. 2

APR1400 DCD TIER 2 10.4.6 Condensate Polishing System 10.4.6.1 Design Bases The condensate polishing system (CPS) is classified as non-safety-related, non-Class 1E, and seismic Category III.

The CPS removes dissolved and suspended impurities from the condensate.

The CPS maintains water quality as described in Subsection 10.3.5, as it relates to GDC 14.

The APR1400 secondary water chemistry program is based on the EPRI PWR Secondary Water Chemistry Guidelines (Reference 18).

The CPS is designed to continuously treat the full condensate flow supplied from the condensate pumps. The CPS may be operated in either full-flow operation or partial-flow operation when condensate purification is required under all load conditions including startup and power operation. The CPS can also be bypassed when condensate purification is not required.

The CPS follows the as low as reasonably achievable (ALARA) design and operational approach described in Sections 12.1 and 12.3 in accordance with NRC RG 8.8 (Reference 19). The CPS demineralizers are located in a shielded area to reduce occupational radiation exposure (ORE).

10.4.6.2 System Description 10.4.6.2.1 General Description The CPS consists of seven pairs of cation-bed ion exchanger vessels (CBVs) and mixed-bed ion exchanger vessels (MBVs) to remove the dissolved and suspended impurities from condensate under all load conditions including startup and power operation.

The CPS is shown schematically in Figure 10.4.6-1.

The CPS processes approximately 16 to 100 percent of the condensate flow during the normal plant operation. When operating in a partial flow, a bypass flow around the vessels is automatically controlled by the differential pressure across the condensate polisher.

10.4-26 Rev. 2

APR1400 DCD TIER 2 The CPS is located in the second floor of the T/G building.

10.4.6.2.2 Component Description Major component data are provided in Table 10.4.6-1.

Seven CBVs and seven MBVs are provided in the CPS to remove the dissolved and suspended impurities from the condensate. During the normal plant operation, the CPS has the capability to polish 100 percent of condensate through six CBVs and MBVs. The seventh CBV and MBV are isolated for standby service. All CBVs and MBVs are fabricated from stainless steel with rubber lining.

A resin trap and a resin collection tank are furnished downstream of each CBV and MBV to remove discharge of resin from each vessel to be permeated into the condensate and feedwater system in the event of failure of the outlet distributor inside each vessel.

Two recycle pumps are furnished to stabilize the effluent quality during each vessel startup in the recirculation line to the main header of the CBV and MBV.

Two spent resin holding tanks are provided for both the CBVs and MBVs. Each tank holds spent resin from each vessel until it is transported offsite. Spent resin holding tanks are fabricated from carbon steel with a rubber lining.

One resin holding tank holds fresh cation resin for charging to the CBV. The resin holding tank is fabricated from carbon steel with rubber lining.

One resin mixing and holding tank holds fresh mixed (cation and anion) resin for charging to the MBV. The resin mixing and holding tank is fabricated from carbon steel with rubber lining.

Resin addition equipment is provided to fill the fresh resin in the CPS.

Two sluice water pumps are provided to transfer and fill the resin.

A sampling system is provided for monitoring polishing demineralizer effluent chemistry.

The sampling system includes a sample sink with instruments for measuring sodium, chloride, conductivity, hydrazine and pH, as well as provisions for collecting grab samples.

10.4-27 Rev. 2

APR1400 DCD TIER 2 10.4.6.2.3 System Operation One CBV-MBV pair processes approximately 16 percent of the condensate flow. One set of the vessels is maintained on standby condition. As a result, the CPS remains in continuous operation without reducing processing capability.

An individual vessel is manually removed from service when the level of impurities in the effluent or the differential pressure exceeds the specified limits or after a specified amount of fluid has been processed.

The CPS design provides assurance that a ion exchanger vessel is always on standby. The exhausted resin is transferred by sluice water pumps to one of the spent resin holding tanks commensurate with resin, and the fresh resin in the resin holding tank and/or resin mixing and holding tank is immediately returned to each ion exchanger vessel. The spent resin holding tanks hold spent resin until it is sampled and prepared for transport offsite. Spent resin is normally nonradioactive, so it does not normally require any special handling method. When the spent resin is detected to be radioactively contaminated to a predetermined level, the contaminated CPS spent resin is packaged into shipping containers for off-site treatment and disposal. The COL applicant is responsible for provisions of temporary shielding, if required, and mobile equipment, including spent resin fill-head for packaging of the contaminated spent resin, provisions of temporary storage, and shipment of packaged contaminated CPS spent resin for off-site treatment and/or disposal (COL 10.4(7)).

A tube leak detection system is provided to permit sampling of the condensate in the condenser hotwell as described in Subsection 9.3.2. If circulating water inleakage occurs, this design feature helps to identify which tube bundle has sustained the leakage. When condenser tube leakage exceeds the design value for the CPS, the affected condenser hotwell is manually isolated by closing the motor-operated hotwell discharge valve. Plant power is reduced as necessary. The waterbox is then drained and the affected tubes are either repaired or plugged.

10.4.6.2.4 Design Features for Minimization of Contamination The APR1400 is designed with specific features to meet the requirements of 10 CFR 20.1406 (Reference 7) and NRC RG 4.21 (Reference 8). The basic principles of NRC RG 4.21, and the methods of controls suggested in the regulations, are specifically delineated into four design objectives and two operational objectives described in 10.4-28 Rev. 2

APR1400 DCD TIER 2 Subsection 12.4.2 of this DCD. The following evaluation summarizes the primary features to address the design and operational objectives for the CPS.

The CPS contains components that contain radioactive fluid resulting from SG leakage.

In accordance with NRC RG 4.21, the CPS has been evaluated for leak identification from the SSCs that contain radioactive or potentially radioactive materials, the areas and pathways where probable leakage may occur, and methods of control incorporated in the design of the system. The leak identification evaluation indicated that the CPS is designed to provide the capability for prompt assessment and evaluation of the responses, and sufficient space for mitigation of the leak areas. Thus, unintended contamination to the facility and the environment is minimized and/or prevented by the SSC design, supplemented by operational procedures and programs, and inspection and maintenance activities.

Prevention/Minimization of Unintended Contamination

a. The system design, including all the polishing cation and mixed-bed demineralizer columns, is designed as vendor-packaged modular units with carbon steel material with rubber lining and welded construction for life-cycle planning, thus minimizing leakage and unintended contamination of the facility and the environment.

b. The CPS cation- and mixed-bed demineralizer columns are designed with sufficient capacity to facilitate continuous partial to full flow during normal operation, including anticipated operational occurrences. The columns are designed with periodic resin replacement to prevent buildup of contaminants, thus minimizing the potential of accumulation of significant amount of contamination and waste generation.

c. The facility area that houses the system components, including the equipment cubicles that contain radioactively contaminated or potentially contaminated fluid, shall have sloped floors with coating to facilitate the draining of fluid into drain pipes and/or trenches that direct liquid into a local sump. In addition, the coated walls provide smooth surfaces for cleaning and to facilitate liquid draining. To the extent practicable, the cubicles shall also have early leak detection capabilities to detect component leakage, and shall have provisions to initiate alarm signals for 10.4-29 Rev. 2

APR1400 DCD TIER 2 operator actions. The facility layout shall facilitate the operators prompt assessment and fast response when needed.

d. Sumps that contain contaminated or potentially contaminated fluid shall be equipped with sump liner plates and level switches to initiate pumping when sump levels reach a predetermined setpoint. The sumps shall be designed to facilitate periodic maintenance and inspection.

e. Piping embedment shall be minimized to the extent practicable. Where embedment cannot be avoided, consideration shall be given to minimizing embedded piping lengths and using double-walled piping with leak detection capabilities on the outer piping.

Adequate and Early Leak Detection

a. The CPS vessels are designed with pressure instruments to provide reasonable assurance of safe operation of the SSCs, including the associated piping, and provide alarms to the operating personnel in the event of high pressure due to accumulation of impurities and low pressure from channeling and/or leakages.

b. The facility in which the CPS vessels are located is designed with a trench to collect leakage to the sump for processing and disposal. This design minimizes contamination of the facility and the environment from the accumulation of contaminated water.

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 radioactive environment, thus minimizing waste generation.

b. The condensate is located separately in an area that is shielded and is equipped with a leak collection trench. The trench is sloped and coated to enhance drainage and cleaning to minimize contamination of the facility and the environment. This design approach also minimizes cross-contamination and waste generation.

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APR1400 DCD TIER 2

c. The CPS is designed to operate in total, partial, and bypass flow modes to meet secondary chemistry requirements. The system is designed with on-line specific conductivity instruments, pH, and other process instrumentation for automated operation with manual initiation, and sampling and analyses to facilitate plant personnel to determine operating requirements. This design approach minimizes cross-contamination and waste generation.

d. Special internals are provided in the cation vessels to allow backwashing of the top layer of cation resin using service air and demineralized water.

e. The process piping containing contaminated solids is properly sized to facilitate flow and maintain sufficient velocities to prevent settling of solids. The piping is designed to reduce fluid traps, thus reducing the decontamination needs and waste generation.

f. Utility connections (sluice water and service air) are designed with a minimum of two barriers to prevent cross-contamination.

Decommissioning Planning

a. The SSCs are designed for the full service life and are fabricated as individual packaged assemblies for easy removal.

b. The CPS is designed with no embedded or buried piping.

Operations and Documentation

a. The CPS polishing operation is designed for automated operations with manual initiation for the different modes of operation. Adequate instrumentation, including conductivity, level, flow, and pressure elements, is provided to monitor and control the operations to prevent undue interruption, thus minimizing the spread of contamination and waste generation.

b. The COL applicant is to establish operational procedures and maintenance programs for leak detection and contamination control (COL 10.4(1)).

Procedures and maintenance programs are to be completed before fuel is loaded for commissioning.

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APR1400 DCD TIER 2

c. The COL applicant is to maintain the complete documentation of system design, construction, design modifications, field changes, and operations (COL 10.4(2)).

Documentation requirements are included as a COL information items.

Site Radiological Environmental Monitoring The CPS is designed with a low level of contamination through leakage in the SG.

Industry experience demonstrates that the integrity of the CPS is well maintained, resulting in minimal contamination of the facility and the environment. Hence, a radiological environmental monitoring program is not required for this system.

10.4.6.3 Safety Evaluation The CPS is a non-safety-related system and is not required for the safe shutdown of the plant.

10.4.6.4 Inspection and Testing Requirements All equipment is inspected and tested in accordance with the equipment specifications and codes.

10.4.6.5 Instrumentation Requirement A local control panel (LCP) is provided for monitoring and controlling the CPS.

Condensate flow to each CBV and MBV is indicated on the LCP. CBV and MBV outlet conductivity is monitored online on the LCP.

The CPS provides adequate process and chemistry instrumentation to keep operators apprised of system performance. The following instruments are included as a minimum:

pressure indicators, pressure differential indicators, flow totalizers, flow indicators, and recorders for specific conductivity, cation conductivity, sodium, and pH.

Differential pressure transmitters are provided across each vessel, each bank of vessels, and across the entire CPS. Associated indication and high alarm are provided at the control panel.

The flow totalizer is provided to measure outlet flow from each vessel. The flow rate and total volume processed are indicated on the control panel. An alarm at the control panel sounds when the vessel has reached its limit of volume processed.

10.4-32 Rev. 2

APR1400 DCD TIER 2 The system effluent quality including specific conductivity, cation conductivity, and sodium is also monitored continuously by the process sampling system as addressed in Subsection 9.3.2.

A CPS common trouble alarm is provided in the MCR and RSR; a plant operator is required to investigate the alarm condition.

10.4.7 Condensate and Feedwater System The condensate and feedwater system delivers feedwater from the condenser to the SG at the required pressure, temperature, flow rate, and water chemistry. The boundary of the condensate system is from the condenser hotwell outlet to the deaerator, and the feedwater system is from the outlet of the deaerator to the inlet of the SGs. Condensate is pumped from the condenser hotwell by the condensate pumps and passes through the low-pressure (LP) feedwater heaters to the deaerator storage tank. Feedwater is pumped from the deaerator storage tank by the feedwater booster pumps and main feedwater pumps through the high-pressure (HP) feedwater heaters to the SGs. The condensate and feedwater system is shown on Figure 10.4.7-1.

10.4.7.1 Design Bases The entire condensate system is non-safety-related. The portion of the feedwater system that is required to mitigate the consequences of an accident and allow safe shutdown of the reactor is safety-related. The safety-related portion is required to function following a design basis accident to provide containment and feedwater isolation. SSCs from the main steam valve house (MSVH) to the SG are designed as ASME Section III (Reference 4), Class 2, and seismic Category I. All other portions are designed as non-nuclear safety (NNS) and seismic Category III in conformance with NRC RG 1.29 (Reference 20). Table 3.2-1, Section 3.2 provides the classification of SSCs in the feedwater and condensate system in conformance with NRC RG 1.29.

The safety-related portion of the feedwater system is designed as follows:

a. In conformance with GDC 2, the safety-related portion is designed to withstand the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, floods, and tsunami without loss of capability to perform its safety function.

Refer to Section 3.3, 3.4, and 3.7.

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APR1400 DCD TIER 2

b. In conformance with GDC 4, the safety-related portion is designed to accommodate the effects of the environmental conditions associated with normal operation, maintenance, testing, and postulated accidents, including LOCAs.

The design includes protection against the dynamic effects, including internally generated missiles, pipe whipping, and discharging fluids due to equipment malfunctions. The system is protected from water hammer by conforming with the following requirements:

1) Guidance contained in Branch Technical Position 10-2 (Reference 21) for reducing the potential for water hammers in SGs

2) Guidance for water hammer prevention and mitigation in NUREG-0927 (Reference 22)

Refer to Sections 3.5, 3.6, 3.11, and Subsection 10.4.7.6.

c. In conformance with GDC 5, no equipment in the condensate and feedwater system is shared between units.

d. In conformance with GDC 44, the portion is designed to provide:

1) Capability to transfer heat loads from the reactor system to a heat sink under normal operating and accident conditions

2) Redundancy of components so that under accident conditions, the components safety functions can be performed assuming a single active component failure

3) Capability to isolate components, subsystems, or piping if required so that the system safety function is maintained

e. The condensate and feedwater system is designed to permit appropriate periodic inservice inspection of important components in conformance with GDC 45.

f. In conformance with GDC 46, the condensate and feedwater system is designed to permit appropriate functional testing of the system and components to provide reasonable assurance of structural integrity and leaktightness, operability, and 10.4-34 Rev. 2

APR1400 DCD TIER 2 performance of active components, and the capability of the integrated system to function as intended during normal, shutdown, and accident conditions.

g. The portion is designed to withstand loads arising from the various specified normal operating and design basis events (DBEs).

10.4.7.2 System Description 10.4.7.2.1 General Description The condensate and feedwater system delivers feedwater from condenser hotwells to the SGs at the required temperature, pressure, and flow rate. Condensate and feedwater is heated through the LP feedwater heaters and HP feedwater heaters. The condensate and feedwater system is composed of a condensate system and feedwater system.

The condensate system consists of three condensate pumps, three stages of three parallel LP heaters, a deaerator, and two deaerator storage tanks. Three 50 percent capacity motor-driven condensate pumps (two operating and one standby) deliver condensate from the condenser hotwells to the deaerator through the condensate polisher, a steam packing exhauster, and three stages of LP feedwater heaters. Condensate is provided to the SG blowdown regenerative heat exchanger for cooling.

The deaerator storage tank level is controlled by two pneumatic valves. The condenser hotwell level is maintained by receiving condensate from condensate storage tank and directing condensate overflow to the condensate overflow storage sump.

Drains from the LP feedwater heaters are cascaded to the next lower-pressure feedwater heaters with drains from the lowest-pressure feedwater heaters draining to the condenser.

The feedwater system consists of three main feedwater pumps, three feedwater booster pumps, a startup pump, three stages of two parallel HP heaters, main feedwater isolation valves (MFIVs), feedwater check valves, and feedwater control valves.

During normal power operation, three motor-driven feedwater booster pumps and three turbine-driven main feedwater pumps provide the required feedwater flow to the SGs.

Each combination of feedwater booster pump and main feedwater pump can provide a maximum of 55 percent of the flow requirements for the feedwater system. Feedwater booster pumps deliver condensate from the deaerator storage tank to the suction of the main 10.4-35 Rev. 2

APR1400 DCD TIER 2 feedwater pumps. Main feedwater pumps deliver feedwater through three stages of two parallel HP feedwater heaters to each SG.

Drains from the HP feedwater heaters are cascaded to the next lower-pressure heaters with drains from the lowest HP feedwater heaters draining to the deaerator.

The manner in which the feedwater flow is delivered to the SG varies with reactor power, as follows:

a. When reactor power is from 0 percent to 20 percent of full power, all feedwater is delivered to the SG through the downcomer line.

b. When the reactor power is above 20 percent of full power, the feedwater flow is split so that 10 percent of the full-power feedwater flow goes to the downcomer while the remainder of the feedwater flow goes to the economizer.

10.4.7.2.2 Component Description Major components design parameters are given in Table 10.4.7-1.

Piping and Valves The valves, piping, and associated supports and restraints of the main feedwater system from and including the MSVH to the SG feedwater nozzles are seismic Category I and designed to ASME Section III, Class 2 requirements.

ASME Section III, Class 2 main feedwater system piping is capable of being inspected and tested in accordance with ASME Section III and Section XI (Reference 23).

All ASME Section III, Class 2 valves are capable of being periodically inservice tested for structural integrity and leakage in accordance with ASME Section XI.

The design of the main feedwater piping and its supports and restraints accommodates the loads arising from the various normal operating conditions and DBEs that are specified in Subsection 3.9.3.

Feedwater system materials are covered in Subsection 10.3.6.

10.4-36 Rev. 2

APR1400 DCD TIER 2 Main Feedwater Isolation Valves The MFIVs and associated supports and restraints are ASME Section III, Class 2, and seismic Category I, and are designed to withstand loads arising from the various normal operating and DBEs as specified in Subsection 3.9.3.

Two redundant and fail-closed type MFIVs in series are installed in the economizer feedwater lines and downcomer feedwater lines. The MFIVs are located in the MSVH outside the reactor containment building as close to the containment wall as possible.

The MFIVs provide complete termination of feedwater flow to the SGs after receipt of a main steam isolation signal (MSIS) even after the effects of a single failure are imposed.

The MFIVs in each main feedwater line are remotely operated and capable of maintaining a tight shutoff of the transient conditions associated with a postulated pipe break in either direction of the valves.

Each MFIV actuator is physically and electrically independent of the other in series so that failure of one does not cause the failure of the other.

The safety analysis of these valves is described in Chapter 15.

Feedwater Check Valves The feedwater check valves and associated supports and restraints are ASME Section III, Class 2, and seismic Category I and are designed to withstand loads arising from the various normal operating and DBEs as specified in Subsection 3.9.3.

Two check valves in series are located in the downcomer feedwater lines and economizer feedwater lines to preclude blowdown of both SGs following a pipe rupture upstream of the check valves. In the economizer line, there is one check valve outside the containment and two check valves in parallel inside the containment. The economizer check valves inside the containment are located as close to the SG as possible to minimize the possibility of backflow from the SG.

The total reverse leakage rate of the feedwater check valves from each SG does not exceed the limitation of MSS SP-61 (Reference 24).

10.4-37 Rev. 2

APR1400 DCD TIER 2 Feedwater Control Valves The feedwater control valves are installed in the economizer feedwater lines and downcomer feedwater lines. The feedwater control valves are automatically controlled by the feedwater control system as described in Subsection 7.7.1.1.c to maintain the proper SG level.

The feedwater control valve and controller are designed to minimize the potential for oscillation instability, vibrations, and water hammer. This design is verified to be stable and compatible with all final designed operating conditions of the system. Precautions to avoid the potential for water hammer occurrences are described in plant operating and maintenance procedures.

Main Condenser The main condenser is described in Subsection 10.4.1.

Condensate Pumps Three 50 percent capacity condensate pumps are vertical, multistage, centrifugal and motor-driven, and operate in parallel. During normal operation, two pumps are running. The third pump is prepared as a standby and starts automatically on the loss of one of the two operating pumps, allowing the plant to remain at 100 percent power.

Startup Feedwater Pump During shutdown and startup, a motor-driven startup feedwater pump provides feedwater from the deaerator storage tank to the SGs. The startup feedwater pump is capable of providing 5 percent of the feedwater flow to both SGs in addition to pump recirculation flow.

Feedwater Booster Pumps Three 55 percent capacity feedwater booster pumps are horizontal, single-stage, centrifugal, and motor-driven with identical characteristics and operate in parallel. Each of the three feedwater booster pumps takes suction from the deaerator storage tank and discharge to its associated main feedwater pump. There are no isolation valves or check valves between the booster pumps and the main feedwater pumps.

10.4-38 Rev. 2

APR1400 DCD TIER 2 Main Feedwater Pumps Three 55 percent capacity main feedwater pumps are horizontal, single-stage, centrifugal and turbine-driven with identical characteristics, and operate in parallel. Each of the three main feedwater pumps takes suction from the individual feedwater booster pump and discharges to the SGs through the HP feedwater heaters. In order to reduce the incidence of low-suction pressure trips during the transient period, main feedwater pumps are capable of operating in a dry run condition for at least 3 minutes.

Low-Pressure Feedwater Heaters Three parallel LP feedwater heater trains are provided. Each LP train (A, B, and C) consists of feedwater heater nos. 1, 2, and 3. LP heaters nos. 1 and 2 are located within the condenser neck. Each LP feedwater heater train handles one-third of the condensate system design flow with all three trains running during normal operation. However, each heater train is designed to handle a maximum of 50 percent of the design system flow; thus, when one train is out of service, the remaining two trains handle 100 percent of the condensate system design flow.

The LP feedwater heater train bypass line is also designed to handle at least 50 percent of condensate system design flow when two of the three LP feedwater heater trains are out of service or required for startup flushing. The LP feedwater heater trains are isolated by closing the motor-operated inlet and outlet isolation valves provided for each train to prevent water induction into the LP turbine resulting from increased shell-side water level of the no. 1 or no. 2 LP feedwater heater due to tube rupture or drain control malfunction.

High-Pressure Feedwater Heaters Two parallel HP feedwater heater trains are provided. Each HP heater train (A and B) consists of feedwater heaters nos. 5, 6, and 7.

Each closed-type HP feedwater heater train handles 50 percent of the feedwater system design flow during normal operation. However, each parallel train is designed to pass approximately 75 percent of the feedwater flow, and the bypass valve passes approximately 25 percent of the feedwater flow. Each HP feedwater heater train has motor-operated inlet and outlet isolation valves.

10.4-39 Rev. 2

APR1400 DCD TIER 2 Deaerator and Storage Tanks The deaerator (feedwater heater no. 4) is located between the LP and HP feedwater heater trains. The deaerator is a spray-tray-type, single horizontal cylindrical, direct-contact heater. Condensate enters the deaerator from the top and heating steam flows from the bottom up. The heating steam is condensed and raises the temperature of the condensate to near saturation, liberating dissolved gases from the condensate. The condensate drains from the deaerator into the storage tank. Non-condensable gases are vented from the top of the deaerator and flow through an orifice and valve assembly to the atmosphere.

During the cleanup/recirculation mode and low-load condition, auxiliary steam from the auxiliary steam supply system is supplied to the deaerator and maintains the pressure in the tank at 1.41 kg/cm2A (20 psia). The steam heats the condensate for removal of any dissolved gases present in the condensate.

During normal operation, extraction steam from the LP turbines is supplied to the deaerator for condensate heating and is also used to remove any dissolved gases present in the condensate.

During large load rejection or turbine trip, main steam through the auxiliary steam header is also automatically supplied to the deaerator to maintain deaerator pressure above 1.41 kg/cm2A (20 psia).

10.4.7.2.3 System Operation System Startup The condensate system is filled with condensate from the condensate storage tanks, and the feedwater system filling is provided from the deaerator storage tank. The condensate storage tank capacity is provided in Table 9.2.6-1, Subsection 9.2.6.

After system filling, initial recirculation for the hotwell cleanup is performed through the condensate recirculation line from downstream of the steam packing exhauster to the condenser. The other recirculation line from the suction line of the feedwater booster pump to the condenser is used to clean up the entire condensate system.

One of the three feedwater booster pumps is manually started and recirculates feedwater through the recirculation line from downstream of HP feedwater heaters to the condenser.

10.4-40 Rev. 2

APR1400 DCD TIER 2 When the feedwater booster pump is stopped upon completion of cleanup/recirculation operation, the startup feedwater pump is manually started. Feedwater can then be introduced into the SG by using the startup feedwater pump and the downcomer feedwater line.

Before the reactor power level reaches 5 percent, one feedwater booster pump is manually started. After the feedwater booster pump reaches normal operating speed, the turbine-driven feedwater pump is started using the feedwater pump turbine control system.

After startup of the first feedwater pump / feedwater booster pump train is completed and the train is in minimum recirculation, the startup feedwater pump is then manually shut down.

When the feedwater control system (FWCS) supplies feedwater automatically to the SG and the reactor power level is below 40 percent, the second combination of the feedwater booster pump and main feedwater pump is started using the same procedure. When the reactor power level is between 40 and 80 percent, the third combination of feedwater booster pump and main feedwater pump is started.

System Shutdown On normal shutdown, the FWCS maintains automatic control of feedwater flow down to 0 percent reactor power level.

When the reactor power level is reduced to anywhere between 40 percent and 80 percent, one of the three operating feedwater pumps is manually shut down. Further, when the reactor power level is reduced to less than 40 percent, the second operating feedwater pump is manually shut down. The feedwater booster pump is interlocked to stop automatically when the associated feedwater pump is shut down.

When reactor power is reduced to approximately 5 percent, the startup feedwater pump is manually started by the control in the MCR and RSR.

When the startup feedwater pump is in normal operation, the operating feedwater pump is manually shut down. The SG level is automatically controlled by the downcomer feedwater control valve continuously until the reactor power level is reduced to 0 percent.

10.4-41 Rev. 2

APR1400 DCD TIER 2 Normal Operation During full-power operation, two out of three condensate pumps discharge condensate to the polishing demineralizers. The condensate polishing demineralizers remove suspended and dissolved solids from the condensate. The condensate polisher bypass flow is automatically controlled by the differential pressure across the condensate polisher.

After passing through the LP feedwater heaters nos. 1, 2, and 3, the condensate flow to the deaerator is regulated by the deaerator storage tank level control valves, which maintain an essentially constant deaerator storage tank water level at all plant operating conditions.

The deaerator, which is a direct-contact type deaerating heater, mixes and heats the condensate with extraction steam from the LP turbine. The deaerator removes entrained oxygen and non-condensable gases. The heated and deaerated condensate is stored in the deaerator storage tanks.

A separate FWCS is provided for each SG to control the SG water level. Each FWCS regulates the feedwater flow rate to the corresponding SG by adjusting the position of the economizer and downcomer feedwater control valves and the speed of the main feedwater pumps.

During low reactor power level operations (below 20 percent), the downcomer feedwater control valves regulate the feedwater flow to the SG. In this control mode, the economizer feedwater control valves are closed and the feedwater pump speed setpoint is at its programmed minimum speed.

During high reactor power level operation (above 20 percent), the downcomer feedwater control valves receive a bias signal that positions the valves to pass approximately 10 percent of total feedwater flow, and the economizer feedwater control valve positions and feedwater pump speed are adjusted to regulate the feedwater flow rate.

The speed of the feedwater pump turbine is controlled by changing the position of the feedwater pump turbine control valves. During plant high-power operation, when hot reheat steam pressure is high enough to drive the turbine at its demand speed, the equally sized LP steam control valves pass hot reheat steam to the turbine. During plant low-power operation, when hot reheat steam pressure is not high enough to drive the turbine at its required speed, main steam is automatically introduced through the HP steam control valve as a supplementary source to maintain the required turbine speed.

10.4-42 Rev. 2

APR1400 DCD TIER 2 The HP steam control valve is opened only after all LP steam control valves are fully opened. During these periods of operation, a mixture of hot reheat steam and main steam is supplied to the first stage of the turbine.

During normal plant operation, the startup feedwater pump is maintained in hot standby to minimize startup time in the event that all feedwater pumps trip.

The FWCS also provides manual control capability of the feedwater flow rate to each SG from 0 to 100 percent reactor power.

Abnormal Operation

a. Loss of one feedwater pump or one feedwater booster pump Loss of a feedwater booster pump is interlocked to trip the associated feedwater pump, and the loss of a feedwater pump is interlocked to trip the associated feedwater booster pump and close the motor-operated stop check valve downstream of the associated feedwater pump.

Upon loss of any one of the three operating feedwater pumps, the FWCS provides a pump speed setpoint demand signal to the remaining two feedwater pumps, and these pumps can supply feedwater automatically to the SGs at 110 percent system rated flow without reactor trip.

b. Loss of two of the three operating feedwater pumps or one of the two operating feedwater pumps A feedwater pump trip signal on two of the three operating feedwater pumps or one of the two operating causes actuation of the reactor power cutback system (RPCS) to reduce the plant power to a level based on fuel burnup and reactor power.

c. Isolation of one train of high-pressure feedwater heaters Each HP feedwater heater train has motor-operated inlet and outlet isolation valves.

The heater trains have a common bypass line provided with a motor-operated isolation valve. An entire train is isolated to repair any heater in the train. The feedwater heater bypass valve is manually opened when one train of the HP 10.4-43 Rev. 2

APR1400 DCD TIER 2 heaters is removed from service. The remaining heater train passes approximately 75 percent of the feedwater flow, and the bypass valve passes approximately 25 percent of the feedwater flow.

d. Isolation of feedwater system on main steam isolation signal After receipt of an MSIS, redundant main feedwater isolation valves provided in both the economizer and downcomer feedwater lines are automatically closed within limits, and the operating pumps (combination of feedwater/feedwater booster pumps and/or startup feedwater pump) are automatically tripped.

10.4.7.2.4 Design Features for Minimization of Contamination The condensate and feedwater system and the associated subsystems (extraction steam, heater drains, feedwater pump turbine, and feedwater heater drains and vents subsystems) are designed with specific features to meet the requirements of 10 CFR 20.1406 (Reference 7) and NRC RG 4.21 (Reference 8). The basic principles of NRC RG 4.21 and the methods of control are delineated in four design objectives and two operational objectives as described in Subsection 12.3.1.10. The following evaluation summarizes the primary features to address the design and operational objectives for these systems.

The identified systems have been evaluated for leakage identification for the SSCs that contain radioactive or potentially radioactive materials, the areas and pathways where leakage may occur, and the methods of leakage control incorporated in the design of the system. The leak identification evaluation indicated that these systems are designed to facilitate early leak detection and the prompt assessment and response to manage collected fluids. 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.

Prevention/Minimization of Unintended Contamination

a. The components for the condensate and feedwater system and the associated subsystems are located inside the turbine generator building (TGB). The floors are sloped, coated, and provided with drains that are routed to the TGB sumps.

The drains from the TGB sumps are monitored for radiological contamination.

Drainage that is detected to be contaminated is routed to the LWMS for treatment 10.4-44 Rev. 2

APR1400 DCD TIER 2 and release. The balance is routed to the wastewater treatment (WWT) facility for processing and release with other nonradiological wastewater. This design approach prevents the spread of contamination through the facility and to the environment.

b. The condensate and feedwater systems and the associated subsystems are designed with sufficient capacities to accommodate different modes of operation. The piping is adequately sized to prevent blockage; primary process piping is sloped to facilitate drainage and prevent fluid accumulation and crud buildup.

c. Process sampling connections are provided under each tube bundle in condenser hotwell to detect condenser tube leaks and determine location of condenser tube leaks.

d. The feedwater heaters are designed to Heat Exchange Institute (HEI) and Tubular Exchanger Manufacturers Association (TEMA) Standards and heater tubes are manufactured using high-grade austenitic stainless steel for minimization of unintended leakage.

e. The feedwater heaters are constructed of carbon steel and welded for life-cycle planning, thus minimizing leakage and unintended contamination of the facility and the environment.

f. The heat exchangers are designed so that tube-side pressure is higher than shell-side pressure to protect against leakage from the potentially contaminated steam to the clean circulating water system.

g. The feedwater pump turbine system is designed to exhaust steam into the condenser, and to direct the casing leakage from the turbine to the condenser pit sump.

h. To minimize the possibility of water impingement into the main turbine, drain pots are provided at low points in the extraction steam piping where water may collect.

Condensate from these drain pots is continuously removed with direct piping to the main condenser during normal plant power operation. Drain pots are provided with level instrumentation that opens the low-point drain valves upon a high signal. This design approach prevents the spread of contamination within the facility.

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i. Extraction steam piping material is ferritic alloy steel (Cr-Mo) and is designed to minimize the effects of erosion/corrosion.

Adequate and Early Leak Detection

a. The condensate and feedwater systems and the associated subsystems are designed with automated operation with manual initiation for the different modes of operation. Adequate instrumentation, including level, flow rate, temperature, and pressure elements, is provided to monitor and control the operations to prevent undue interruption. This design approach minimizes the spread of contamination and waste generation.

b. Radiation sampling connection is provided on the condenser vacuum pump exhaust line and the steam generator blowdown line to monitor contamination levels associated with the condensate and steam generator blowdown systems.

c. Leak detection trays are included at all tube-to-tubesheet interfaces. Provisions for early leak detection are provided for the tubesheet trays and in each hotwell section.

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, minimizing the spread of contamination and waste generation.

b. Normal and emergency drains are routed to the condenser and are forwarded to the condensate polishers for treatment, minimizing the spread of contamination.

c. If leakage occurs from the condensate and feedwater system equipment, the water is drained to local drain hubs by gravity and transferred to the TGB drain system sump for collection.

d. Extraction steam piping is designed to minimize the effects of erosion/corrosion, is adequately sized to limit velocities, and is routed with long-radius elbows to minimize potential erosion and waste generation.

10.4-46 Rev. 2

APR1400 DCD TIER 2 Decommissioning Planning

a. The SSCs are designed for the full 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 used and surface finishes are intended to minimize the need for decontamination, and hence reduce waste generation.

c. The systems are designed without any embedded or buried piping. The feedwater piping between the TGB and the AB is routed at a high elevation and is provided with a piping sleeve. Any leakage is drained back to the building and is collected by the floor drain system, thus minimizing unintended contamination of the environment.

Operations and Documentation

a. The components of these systems are located in open areas inside the AB and TGB. Adequate spaces are provided around the equipment to enable prompt assessment and responses.

b. The COL applicant is to provide operational procedures and maintenance programs as related to leak detection and contamination control (COL 10.4(1)).

Procedures and maintenance programs are to be completed before fuel is loaded for commissioning.

c. The COL applicant is to maintain complete documentation of the system design, construction, design modifications, field changes, and operations (COL 10.4(2)).

Documentation requirements are included as a COL information item.

Site Radiological Environmental Monitoring These systems have the potential to contain low levels of contamination. However, these systems are located inside the buildings and drainage is collected and treated before release.

Hence, these systems are not required to be directly and individually monitored for environmental contamination.

10.4-47 Rev. 2

APR1400 DCD TIER 2 10.4.7.3 Safety Evaluation The safety-related portion of the feedwater system is designed in accordance with the design bases addressed in Subsection 10.4.7.1. Failure in the non-safety class portions of the condensate and feedwater system does not prevent safe shutdown of the reactor.

Safety-related portions of the feedwater system are located in seismic Category I structures and are designed to protect against environmental hazards such as wind, tornadoes, hurricanes, floods, and missiles and against the effects of high- and moderate-energy pipe rupture, as described in Sections 3.3, 3.4, 3.5, and 3.6.

SG overfill due to a feedwater system malfunction is prevented by automatic closure of the feedwater isolation valves upon receiving an MSIS, which is generated when the high SG water level setpoint is reached.

The effects of feedwater system equipment malfunction on the RCS are presented in Subsections 15.1.1, 15.1.2, 15.2.7, and 15.2.8.

The design consideration of water hammer prevention is described in Subsection 10.4.7.6.

Release of radioactivity to the environment in the event of line break is negligible because of the minimal amount of radioactivity in the system.

The results of condensate and feedwater system failure mode and effects analysis are shown in Table 10.4.7-2.

10.4.7.4 Inspection and Testing Requirements The condensate and feedwater system testing includes functional testing of the systems and components to provide reasonable assurance of structural integrity, leaktightness, operability and performance of active components, and testing of the capability of the integrated system to function as intended during normal, shutdown, and accident conditions.

ASME Section III piping is inspected and tested in accordance with ASME Sections III and XI. ASME Section III, Class 2 valves are periodically inservice tested for exercising and leakage in accordance with ASME OM (Reference 25).

10.4-48 Rev. 2

APR1400 DCD TIER 2 10.4.7.5 Instrumentation Requirements Sufficient instrumentation and controls are provided to adequately monitor and control the condensate and feedwater system.

Alarms are installed for low NPSH of feedwater booster pump and main feedwater pump and high pressure of the main feedwater pump discharge header. Instrumentation and controls are installed for maintaining minimum pump recirculation flow to prevent pump damage.

Upon loss of one of two operating condensate pumps, the standby pump is started automatically.

The MCR and RSR have feedwater flow, condensate flow, deaerator pressure, and deaerator storage tank level indications. The MCR and RSR have SG narrow-range and wide-range level indications and alarms.

MFIVs automatically close on receipt of an MSIS and also can be manually controlled in the MCR and RSR.

The feedwater control system is described in Subsection 7.7.1.1.c.

10.4.7.6 Water Hammer Prevention The feedwater system design minimizes the potential for a water hammer and its effects.

The SG design features, including a feedwater ring for water hammer prevention, are described in Subsection 5.4.2.1.2.1.2. The design features avoid the formation of a steam pocket in the feedwater piping that when collapsed, could create water hammer. The feedwater connection to each SG is the highest point of each feedwater line downstream of the MFIV. The feedwater lines contain no steam pockets that could trap steam and lead to a water hammer.

Feedwater piping analysis considers the following factors and events in the evaluation:

a. Rapid closure of the main feedwater check valve due to line breaks

b. Pump trips

c. Spurious MFIV trip

d. Feedwater piping, anchors, supports, and snubbers as applicable 10.4-49 Rev. 2

APR1400 DCD TIER 2 Water hammer prevention and mitigation are implemented in accordance with the following, as specified in NUREG-0927 and BTP 10-2:

a. The horizontal length of feedwater piping between the SG and the vertical run of piping is minimized by providing downward-turning elbows immediately upstream of feedwater nozzles.

b. The top feedwater lines are maintained full at all times.

c. The design consideration of the main feedwater control valve in terms of oversizing and instability reduce the frequency and severity of a water hammer.

d. A check valve is provided upstream of the auxiliary feedwater connection to the top feedwater line.

e. Operator training and operational and maintenance procedures (e.g., warmup of line, adequate valve operation, vent/drain, and removal of void) reduce the frequency and severity of a water hammer.

f. For a water hammer anticipated by intended system operation (or steam hammer),

the generated load is considered for piping and support designs.

Check valves are installed in each feedwater line outside the containment. During normal and abnormal conditions, the main feedwater check valve prevents reverse flow from the SG when the feedwater pumps are tripped. In addition, the closure of the valves prevents SG from blowing down in the event of a feedwater pipe break. The main feedwater check valve is designed to limit blowdown from the SG and to prevent a slam resulting in potentially severe pressure surges due to a water hammer. The valves are designed to withstand the closure forces encountered during the normal and abnormal conditions.

Rapid closure associated with a feedwater line break does not impose unacceptable loads on the SG.

The COL applicant is to provide operating and maintenance procedures in accordance with NUREG-0927 and a milestone schedule for implementation of the procedure (COL 10.4(8)). The procedures are to address:

a. Prevention of rapid valve motion

b. Introduction of voids into water-filled lines and components 10.4-50 Rev. 2

APR1400 DCD TIER 2

c. Proper filling and venting of water-filled lines and components

d. Introduction of steam or heated water that can flash into water-filled lines and components

e. Introduction of water into steam-filled lines or components

f. Proper warmup of steam-filled lines

g. Proper drainage of steam-filled lines

h. Effects of valve alignments on line conditions 10.4.7.7 Flow-Accelerated Corrosion The condensate and feedwater system is designed to avoid FAC and erosion/corrosion damage. The methods described in Subsection 10.3.6 are used to minimize FAC and erosion/corrosion degradation based on GL 89-08 (Reference 26).

10.4.8 Steam Generator Blowdown System The steam generator blowdown system (SGBS) consists of two subsystems, the blowdown subsystem (BDS) and wet lay-up subsystem (WLS). The SGBS assists in maintaining the chemical characteristics of the secondary side water, within permissible limits, during normal plant operation and anticipated operational occurrences (AOOs), due to main condenser tube leak or SG primary-to-secondary tube leakage. The SGBS is designed to remove impurities concentrated in SGs by continuous blowdown (CBD), periodical high-capacity blowdown (HCBD), and emergency blowdown (EBD).

During normal power operation, the CBD from each SG is used to control chemistry in the steam generator secondary side water. The CBD is defined for two conditions, Normal Blowdown (NBD) and Abnormal Blowdown (ABD). When the chemistry is within the normal limits, the NBD is maintained. If the water chemistry is above the normal limits, the ABD is used. Periodically, HCBD is provided to remove any accumulated sludge near the tube sheet area. EBD using HCBD valves and piping can be operated to reduce the steam generator water level during Multiple Steam Generator Tube Rupture (MSGTR) event.

10.4-51 Rev. 2

APR1400 DCD TIER 2 10.4.8.1 Design Bases 10.4.8.1.1 Safety Design Bases The following safety-related functions of the SGBS are performed following a design basis accident (DBA):

a. Steam generator shell pressure boundary

b. Containment isolation The SGBS has the following design basis requirements and criteria:

a. The safety-related function of the SGBS is performed against a single active component failure associated with a loss of offsite power (LOOP).

b. Air-operated valves (AOVs) for containment isolation have an active safety-related function under loss of electric power to the valve actuating solenoid or pneumatic pressure to the valves.

c. All components, piping, and their associated supports from the SG blowdown nozzles to the outermost containment isolation valves are safety Class 2 (refer to Subsection 3.2.3) and are designed according to ASME Section III (Reference 4),

Class 2 and seismic Category I requirements. The SG blowdown system piping, supports, and restraints are designed to withstand the loads arising from the various normal operating and DBA.

d. The safety-related portion of the SGBS is designed to function during normal operation and following a DBA, and is protected against earthquakes, wind, tornadoes, hurricanes, floods, and missiles (GDC 2).

e. The safety-related piping, supports, and restraints of the SGBS are designed to withstand dynamic loads related to the postulated rupture of piping as described in Section 3.6.

10.4.8.1.2 Non-Safety Power Generation Design Bases The non-safety-related functions and design basis requirements of the SGBS are as follows:

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APR1400 DCD TIER 2

a. Remove non-volatile materials generated from condenser tube leaks, primary-to-secondary tube leaks, and corrosion that would otherwise become more concentrated in the shell side of the SGs, in order to help maintain SG shell-side water chemistry as specified in Table 10.3.5-1 (GDC 13)

b. Enable blowdown concurrent with SG tube leak to remove radioactive materials from the secondary side without release of radioactivity to the environment

c. Sample blowdown water for chemistry analysis and monitor the SG primary-to-secondary tube leakage with SG blowdown water radiation monitor (GDC 14)

d. Establish and maintain wet and dry lay-up of the steam during plant shutdown

e. Drain the secondary water of the SG for maintenance

f. Control the blowdown water temperature to protect the demineralizer resin from high temperatures

g. Monitor the radiation level downstream of the post-filter All components, piping, and their associated supports downstream of the outermost containment isolation valves of the SGBS are non-safety. The SGBS meets the quality standards of Position C.1.1, C.4, and C.7 of NRC RG 1.143 (Reference 27).

a. Table 10.4.8-3 details the equipment codes for design and construction as required in Table 1 of NRC RG 1.143. The structures, systems, and components (SSCs) of the SGBS are designed in conformance with applicable codes and standards, and guidelines provided in NRC RG 1.143.

The SGBS components are determined for the radioactive safety classification in accordance with the guidance provided in RG 1.143. The radioactive inventories in the SGBS components are determined based on 1 percent fuel defect and compared with the A1 and A2 values in Appendix A of 10 CFR 71 (Reference 40).

If the radioactivity inventories of a component exceed the A1 quantities, the component is classified as RW-IIa. If the radioactivity inventories are less than A1 quantities and greater than A2 quantities, the component is classified as RW-IIb. All other components are classified as RW-IIc. The results are included in Table 10.4.8-4. The component safety classification is summarized in Table 10.4-53 Rev. 2

APR1400 DCD TIER 2 10.4.8-1. Accordingly, the SGBS is classified as RW-IIc, based on the highest safety classification for the components within the system boundary. The SGBS components are housed within the auxiliary building, which is classified as RW-IIa.

All components connected to the SGBS components classified as RW-IIc (Piping, pumps, etc.) are also classified as RW-IIc, up to and including the nearest isolation component (ex. Isolation valves), on each connection, to the RW-IIc component.

b. The quality assurance (QA) program for the design, installation, procurement, and fabrication of SGBS components conforms with Regulatory Position C.7 of NRC RG 1.143. The QA program is described in Table 3.2-1.

c. The SGBS is designed and tested to the codes and standards listed in Table 10.4.8-3 in accordance with Regulatory Positions C.1.1.1 and C.4 of NRC RG 1.143.

The SGBS follows the ALARA design and operational approach described in Sections 12.1 and 12.3 in accordance with NRC RG 8.8 (Reference 19). The SGBS demineralizers are located in a shielded area to reduce the occupational radiation exposure (ORE).

10.4.8.2 System Description 10.4.8.2.1 General Description SGBS schematic diagrams are shown in Figure 10.4.8-1. Classification of SGBS equipment and components is shown in Section 3.2.

The blowdown subsystem (BDS) consists of blowdown piping connected to each SG, a blowdown flash tank, a regenerative heat exchanger, two pre-filters, two demineralizers, a post-filter, and control valves. The wet lay-up subsystem (WLS) consists of two recirculation trains (one for each SG) and shares filters and demineralizers with the BDS.

10.4.8.2.2 Component Description Component design parameters are shown in Table 10.4.8-1.

a. SG blowdown flash tank The blowdown flash tank is a vertical pressure vessel with level, pressure, and temperature instruments and is designed to accommodate CBD, HCBD, and EBD 10.4-54 Rev. 2

APR1400 DCD TIER 2 rates and to send them to the regenerative heat exchanger. The blowdown flash tank pressure is controlled by one of two control valves located in the blowdown flash tank steam vent line. The blowdown flash tank is equipped with blowdown inlet and outlet nozzles, a safety relief valve nozzle, a steam vent nozzle, fill and drain nozzles, and instrument nozzles.

b. SG blowdown regenerative heat exchangers The regenerative heat exchanger is a shell-tube type. The hot blowdown water from the SG flows to the shell side, and the condensate from downstream of the condensate polisher flows to the tube side so that thermal energy is regenerated.

The blowdown water temperature at the exits of the regenerative heat exchanger is controlled by regulating condensate flow.

c. SG blowdown filters There are two pre-filters and a post-filter. The pre-filters remove undissolved solid particles to prevent the blocking of the demineralizer. The post-filter is installed downstream of the demineralizer to filter resin particles escaped from the demineralizer vessels.

d. SG blowdown demineralizers Two demineralizers are provided to purify the blowdown to a water quality that is sufficient to return it to the condensate system. Both demineralizers are normally used in series during blowdown. One demineralizer is used while the other is in standby. The two demineralizers can be aligned in parallel.

e. Wet lay-up recirculation pump The centrifugal wet lay-up recirculation pump recirculates the SG secondary side water through filters and demineralizers during wet lay-up of the SG. The pumps are also used to drain and fill the SG secondary side.

10.4-55 Rev. 2

APR1400 DCD TIER 2 10.4.8.2.2.1 Flow-Accelerated Corrosion The SGBS is designed to avoid FAC and erosion/corrosion damage. The same water chemistry conditions of the secondary system that are controlled to minimize corrosion is applied to the SGBS. The following portion of SGBS is designed to address FAC:

a. SGBS piping from the SGs to the blowdown flash tank is made of chrome-moly materials.

b. Stainless steel is installed between pre-filter isolation valves, the demineralizer isolation valves, and post-filter isolation.

c. The wet lay-up piping is made of stainless steel.

d. Other SG blowdown piping is made of carbon steel with 1.524 mm (0.06 in) additional margin in the design.

e. The carbon steel portions of SGBS are managed by the FAC program during plant operations (COL 10.3(5)).

10.4.8.2.3 System Operation 10.4.8.2.3.1 Plant Startup The SGs are maintained in wet lay-up by the WLS when the plant is expected to be shut down for a long period. After the WLS operation is ceased, the water in the SG is transferred to either the ((wastewater treatment facility)) or the liquid radwaste system. If the SG water is nonradioactive, it is drained to the ((wastewater treatment facility)) by gravity or by using the wet lay-up recirculation pump until the required water quality is met and the desired water level is achieved. If the SG water is radioactive, it is drained to the liquid radwaste system by gravity or by using the wet lay-up recirculation pump until the required water quality is met and the desired water level is achieved.

The abnormal blowdown (ABD) is started following feedwater pump startup operation.

The ABD of 1 percent of SGs maximum steaming rate (SGMSR) is maintained until the water quality is within the normal limits. SGMSR is 4,071 ton/hr (8,975,000 lbm/hr) for each steam generator.

10.4-56 Rev. 2

APR1400 DCD TIER 2 10.4.8.2.3.2 Normal Operation During normal power operation, the CBD that flows from each SG is maintained to keep the SG secondary side water chemistry within the specified limits. The CBD flow rate is 0.2 percent in normal blowdown or 1 percent in ABD from each SGMRS.

The blowdown system cools the blowdown water with regenerative heat exchanger to a temperature that is acceptable for processing filters and demineralizers.

The blowdown water returns to the secondary system and after being filtered and demineralized, meets the applicable chemistry requirements to return the water to the main condenser.

The blowdown system removes suspended and dissolved impurities that are concentrated in the secondary-side liquid of the SG using the CBD.

Each SG has two branch lines connected respectively to the hot leg and the economizer regions of the SG shell side. The blowdown is directed independently into the blowdown flash tank, where the flashed steam is returned to the cycle through the high-pressure feedwater heaters. The liquid portion flows to the regenerative heat exchanger, where it is cooled by the condensate system and then directed through one of two parallel blowdown pre-filters, where the major portion of the suspended solids is removed. After filtration, the blowdown fluid is processed by the blowdown demineralizers and returned to the condenser using a common discharge line.

The blowdown water temperature at the exit of the regenerative heat exchanger is maintained at 57.2 °C (135 °F) to avoid the demineralizer resin damage by controlling the condensate flow rate to the regenerative heat exchanger. The temperature controller at the exit of the regenerative heat exchanger automatically controls the condensate control valve.

When the blowdown water is unacceptable for use or contaminated with radioactive materials, the water is directed to the wastewater treatment system or liquid radwaste system.

When the CBD is operated, the blowdown flash tank level controller is set to automatic mode, and the level control valve downstream of the post-filter maintains the water level in the blowdown flash tank. Before the HCBD or EBD is opened, the blowdown flash tank level controller is set to manual mode, and the level control valve is manually set to the normal blowdown (NBD) or ABD opening. When the HCBD or EBD is operated, the 10.4-57 Rev. 2

APR1400 DCD TIER 2 water level in the blowdown flash tank increases. After the HCBD or EBD operation is stopped, the water level on the blowdown flash tank is returned to the normal level manually by setting the level control valve to the ABD opening. Each CBD (normal blowdown or ABD) flow is controlled by remotely opening and closing a corresponding CBD isolation valves in series with a flow regulation valve.

The APR1400 SGs use a central blowdown system arrangement. In this arrangement, blowdown holes are drilled from the lower part of blowdown pipe where it is installed at the top of tube sheet. This arrangement is shown as Figure 10.4.8-2 and facilitates effective sludge removal from the tube sheet. The blowdown from each SG is depressurized by the pressure control valves located in the vent line of the blowdown flash tank where water and flashing vapor are separated. The vented steam is discharged to the high-pressure feedwater heater. When the high-pressure feedwater heater is unavailable, the vent pass is diverted to condenser.

The BDS is designed to handle intermittent HCBD of up to 5 percent of SGMSR from one steam generator and 1 percent of SGMSR from the other for two minutes.

10.4.8.2.3.3 Plant Shutdown During long-term shutdown periods, the WLS is used to control the water chemistry in the SG. Following draining or dry lay-up, the WLS refills the SGs.

10.4.8.2.3.4 Steam Generator Drain The SGBS is used to drain the SGs for maintenance or for a refueling shutdown. In this mode, the blowdown drain water is directed to the liquid radwaste system only when radioactivity is detected, otherwise drained to ((the wastewater treatment system (WWTS))).

The COL applicant is to describe the nitrogen or equivalent system design for the SG drain mode (COL 10.4(9)).

10.4.8.2.3.5 Abnormal Operation

a. Condenser tube leakage In the event of a main condenser tube leakage and concurrent high sodium concentration downstream of the demineralizers and filters treating impurities, the blowdown water is discharged to ((the WWTS)).

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APR1400 DCD TIER 2

b. Containment isolation signals The containment isolation valves are automatically isolated at the following signals:

1) Main steam isolation signal

2) Diverse protection system auxiliary feedwater actuation signal

3) Containment isolation actuation signal

4) Auxiliary feedwater actuation signal The outermost containment isolation valves in the blowdown lines are interlocked to close automatically on high-high level signal from the blowdown flash tank and on a high radiation signal from the radiation monitor installed at the outlet of the post-filter.

c. Abnormal water chemistry condition When the radioactivity level at the outlet of the SG blowdown demineralizers exceeds the predetermined limit, blowdown water is discharged to the liquid radwaste treatment system. When the water chemistry condition as specified in Table 10.3.5-1 exceeds the specified limit, blowdown water is discharged to the WWTS.

d. SG Tube Leakage In the case of SG primary to secondary tube leakage within tube leak rate as specified in the plant Technical Specifications, blowdown water continues to be purified with SG blowdown demineralizers to remove the radioactivity entering from leaking SG tube(s).

e. Malfunction in SGBS component The following conditions indicate respectively the potential malfunctions of the blowdown flash tank vent line, the regenerative heat exchanger, and blowdown flash tank:

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APR1400 DCD TIER 2

1) High-pressure alarm for the blowdown flash tank

2) High-temperature alarm at the exit of the regenerative heat exchanger

3) High-level alarms for the blowdown flash tank The malfunctions of the above SGBS components isolate the SGBS lines and after those conditions are restored, the SGBS is in service.

10.4.8.2.3.6 Multiple Steam Generator Tube Rupture In the event of a multiple steam generator tube rupture (MSGTR) that is beyond the design basis accident, the EBD is operated to reduce the SG water level using the HCBD valve and piping. The EBD flow rate are approximately 14 percent of SGMSR from one steam generator to reduce a steam generator water level during MSGTR.

10.4.8.2.4 Design Features for Minimization of Contamination The SGBS is designed with specific features to meet the requirements of 10 CFR 20.1406 (Reference 7) and Regulatory Guide 4.21 (Reference 8). The basic principles of NRC RG 4.21 and the methods of control are delineated in four design objectives and two operational objectives, as described in Subsection 12.4.2. The following evaluation summarizes the primary features to address the design and operational objectives for the SGBS.

The SGBS has been evaluated for leak identification from the SSCs that contain radioactive or potentially radioactive materials, the areas and pathways where leakage may occur, and the methods of leakage control incorporated in the design of the system. The leak identification evaluation indicated that the SGBS is designed to facilitate early leak detection and the prompt assessment and response to manage collected fluids. Unintended contamination to the facility and the environment is minimized and/or prevented by the SSC design, supplemented by operational procedures and programs and inspection and maintenance activities.

Prevention/Minimization of Unintended Contamination

a. The SGBS components are located in elevated cubicles inside the auxiliary building. The cubicle floors are sloped, coated with epoxy, and provided with 10.4-60 Rev. 2

APR1400 DCD TIER 2 drains that are routed to the local drain hubs. This design approach prevents the spread of contamination through the facility and to the environment.

b. The SGBS is designed with sufficient capacity for different modes of operation, including CBD, ABD, HCBD, and emergency BD. The system piping is adequately sized to prevent blockage and is sloped to facilitate drainage and prevent crud buildup.

c. The heat exchangers, filters, demineralizers, and the wetted parts of the WLS recirculation pumps are fabricated from stainless steel material and use welded construction for life-cycle planning, thus minimizing leakage and unintended contamination of the facility and the environment.

d. The facility areas that house the system components, including the equipment cubicles that contain radioactively contaminated or potentially contaminated fluid, are designed with sloped floors with epoxy coating to facilitate the draining of fluid into drain pipes that direct liquid into a local sump. The SGBS component cubicles have epoxy coated walls to facilitate cleaning. The facility layout facilitates the operators' prompt assessment and fast response when needed.

Adequate and Early Leak Detection The SGBS is designed with automated operation with manual initiation for the different modes of operation. Adequate instrumentation, including level, flow rate, temperature, and pressure elements, and a process radiation monitor, is provided to monitor the system operation to prevent undue interruption.

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 SGBS components are provided with demineralized water for decontamination. Nitrogen and other utilities are provided to facilitate operations.

The utility connections are designed with a minimum of two barriers to prevent contamination of clean systems.

10.4-61 Rev. 2

APR1400 DCD TIER 2

c. Process sampling connections are provided to determine the levels of contamination, treatment requirements, and confirmation of the continual radiation monitoring output. Continuous process radiation monitoring is provided on the outlet line of the treated blowdown water. The detection of high radiation levels initiates automatic valve closure for isolation and operator actions, minimizing cross-contamination.

Decommissioning Planning

a. The SSCs are designed for the full service life and are fabricated as individual assemblies for easy removal to the maximum extent possible.

b. The SSCs are designed to facilitate decontamination. Design features, such as the welding techniques used and surface finishes, minimize the need for decontamination and the resultant waste generation.

c. The SGBS is designed without any embedded or buried piping. Piping between buildings is equipped with piping sleeves or tunnel, as applicable, with leak detection features, thus preventing contamination of the environment.

Operations and Documentation

a. The removal and packaging of spent filter elements and spent resin are designed for remote manual operation. Adequate space is provided around the equipment to enable prompt assessment and responses.

b. The COL applicant is to establish operational procedures and maintenance programs as related to leak detection and contamination control (COL 10.4(1)).

Procedures and maintenance programs are to be completed before fuel is loaded for commissioning.

c. The COL applicant is to maintain complete documentation of the system design, construction, design modifications, field changes, and operations (COL 10.4(2)).

Documentation requirements are included as a COL information item.

Site Radiological Environmental Monitoring The SGBS is part of the overall plant and is included in the site radiological environmental monitoring program for monitoring the potential for environmental contamination. The 10.4-62 Rev. 2

APR1400 DCD TIER 2 program includes sampling and analysis of waste samples, meteorological conditions, hydrogeological parameters, and potential migration pathways of the radioactive contaminants. The COL applicant is to prepare the site radiological environmental monitoring program (COL 10.4(10)).

10.4.8.3 Safety Evaluation

a. The design of the SGBS satisfies GDC 1 as it relates to the system components being designed, fabricated, erected, and tested for quality standards.

b. Seismic, design and fabrication codes, and quality group classifications of the SGBS components are provided in Section 3.2.

c. The power and control function related to the safety functions of the system is Class 1E.

d. The portion of SG secondary side pressure boundary inside the containment and the portion used as containment isolation are designed as safety Class 2.

e. The safety-related portions of the SGBS are located in the containment and the auxiliary building. These buildings are designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other natural phenomena.

f. The safety-related portion of the SGBS is designed to remain functional during and after a safe shutdown earthquake.

g. The safety-related components of the SGBS are qualified to function in normal and accident environmental conditions. The environmental qualification program is described in Section 3.11.

h. The SGBS maintains the secondary water chemistry within specified limits (GDC 13). The blowdown system is sampled continuously to monitor the secondary water chemistry. The sampling system is described further in Subsection 9.3.2.

i. The SGBS maintains the secondary water chemistry in the SGs within specific limits through the CBD (GDC 14). The secondary water chemistry program and 10.4-63 Rev. 2

APR1400 DCD TIER 2 associated limits are described in Subsection 10.3.5. The SGBS meets the intent of NUREG-0800 Branch Technical Position (BTP) 5-1 (Reference 28).

j. Controls are provided to prohibit SGBS demineralizer resin damage from high temperatures. The single failure criterion is applied to the containment isolation valves. Subsections 6.2.4 and 6.2.6 describe the system containment isolation arrangement and containment leakage testing.

k. The results of the failure modes and effects analysis, as shown in Table 10.4.8-2, are that safety-related equipment remains functional considering a single failure coincident with a LOOP. The results of the failure modes and effects analysis for the SGBS sampling isolation valve are described Table 9.3.2-5, considering a single failure coincident with a LOOP.

10.4.8.4 Inspection and Testing Requirements The SGBS and components are inspected and tested during plant startup using the test program. The SGBS lines within the containment and up to the second isolation valve outside the containment are inspected in accordance with ASME Sections III (Reference 4) and XI (Reference 23) during preservice and inservice inspections. SGBS components are designed and located to permit preservice and inservice inspections to the extent practicable.

Inspection and tests are described further in Section 14.2.

10.4.8.5 Instrumentation Requirements Pressure, level, flow, temperature, differential pressure, and radiation instrumentation monitors and controls system operation.

The blowdown flash tank is provided with a level and pressure instrument.

Flow elements downstream of the isolation valves measure and indicate blowdown flow from each SG.

The blowdown water temperature instrumentation monitor at the exit of the regenerative heat exchanger controls the condensate flow rate to the regenerative heat exchanger to maintain the temperature below approximately 57.2 °C (135 °F).

10.4-64 Rev. 2

APR1400 DCD TIER 2 The differential pressure indicators display locally the differential pressure across the pre-filters, demineralizers, and post-filters.

The SG blowdown water radiation monitor, located in the downstream of the post-filter detects the radioactivity in the SG blowdown water.

10.4.9 Auxiliary Feedwater System 10.4.9.1 Design Bases 10.4.9.1.1 Functional Requirements

a. The auxiliary feedwater system (AFWS) provides an independent safety-related means of supplying auxiliary feedwater (AFW) to the SG(s) for the following events whenever the reactor coolant temperature is above the cut-in temperature for shutdown cooling system initiation and the main feedwater system is inoperable. The AFWS and supporting systems are designed to provide the required flow to the SG(s) with a loss of offsite power (LOOP) event, assuming a single active failure.

1) Loss of normal feedwater

2) Main steam line break (MSLB) or feedwater line breaks (FLB)

3) Steam generator tube rupture (SGTR)

4) Transient conditions or postulated accidents such as reactor trip

5) Any incident that results in station blackout (SBO)

6) Small-break loss-of-coolant accident (SBLOCA)

7) Anticipated transients without scram (ATWS)

b. Following the above events, the AFWS supplies AFW inventory in the SG(s) for residual heat removal and is capable of maintaining hot standby and facilitating a plant cooldown (at the maximum administratively controlled rate of 41.7 °C/hr (75 °F/hr) from hot standby to shutdown cooling system initiation.

10.4-65 Rev. 2

APR1400 DCD TIER 2

c. The AFWS is also designed to be initiated with operator action following a primary-side LOCA to keep the SG tubes covered for the long term to enhance the closed-system containment boundary.

d. Each AFW pump is capable of providing the required minimum flow of 2,461 L/min (650 gpm) under the following conditions:

1) The maximum SG downcomer nozzle pressure is 87.2 kg/cm2A (1,240 psia),

which accounts for the SG design pressure, safety valve uncertainty, and feed nozzle losses from the downcomer nozzle to the SG steam space.

2) Pump suction is at the minimum suction pressure.

e. The AFWS is capable of providing the required minimum flow to the intact SG without isolation of the depressurized SG, assuming a postulated pipe failure concurrent with a single active component failure, in accordance with the SG makeup flow requirement.

f. The AFWS is designed to restrict the maximum AFW flow by a cavitating venturi to provide reasonable assurance that the containment is not overpressurized and that the SG is not overfilled following a main steam line break without operator action to modulate or terminate the AFW flow for 30 minutes after AFWS actuation. The AFW flow can be terminated by operator action within 30 minutes to close the AFW isolation valves and/or shut off the associated AFW pumps if the SG is faulted (i.e., the main feedwater or main steam line breaks).

g. The AFWS has two 100 percent capacity auxiliary feedwater storage tanks (AFWSTs). Each tank has a minimum usable safety-related water volume of 1,514,165 L (400,000 gal) to achieve a safe cold shutdown based on the following:

1) 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of operation at hot-standby conditions

2) Subsequent cooldown of RCS within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to conditions that permit operation of the shutdown cooling system

3) Feedwater line break without isolation of auxiliary feedwater to the affected SG for 30 minutes in accordance with NUREG-0611 and NUREG-0635 (References 29 and 30, respectively) 10.4-66 Rev. 2

APR1400 DCD TIER 2 The safety-related water volume provides reasonable assurance of sufficient feedwater to allow an orderly plant cooldown to shutdown cooling entry conditions following the above events.

h. The AFWS consists of two 100 percent capacity motor-driven pumps, two 100 percent capacity turbine-driven pumps, two 100 percent auxiliary feedwater storage tanks (AFWSTs), valves, two cavitating flow-limiting venturis, and instrumentation. One motor-driven pump and one turbine-driven pump are configured into one mechanical division.

i. The AFWS is an ASME Section III (Reference 4), Class 2 and 3, seismic Category I, redundant system with Class 1E electric components. The AFWS is designed to remain functional after a safe shutdown earthquake (SSE).

10.4.9.1.2 Design Criteria

a. The AFWS components are located in the auxiliary building and reactor containment building, which is designed as seismic Category I and protects the AFWS components from external environmental hazards such as wind, tornado, hurricane, flood, and earthquake, as described in Sections 3.3, 3.4, and 3.7. Each redundant and diverse AFW line is physically separated from the others within the auxiliary building to protect the AFWS components from the effects of internally and externally generated missiles as described in Section 3.5.

b. All mechanical components and piping up to the AFW isolation valves are safety Class 3 and designed to ASME Section III requirements. All components and piping from and including the containment isolation valves to the SGs are safety Class 2 and designed to ASME Section III requirements. All components and piping essential to the safety function are designed to seismic Category I requirements, as described in Section 3.7. The seismic category and safety classification and quality assurance requirements of the AFWS components are listed in Section 3.2, Table 3.2-1.

c. The safety-related portions of the AFWS are appropriately protected against the possible effects of postulated high- or moderate-energy pipe failure including pipe whip or jet impingement, as described in Section 3.6.

10.4-67 Rev. 2

APR1400 DCD TIER 2

d. A failure of a non-essential equipment or component does not affect the AFWS safety functions.

e. The AFWS components are provided with emergency power and adequate redundancy, diversity, and separation to perform design basis functions in the event of an SBO coincident with the following:

1) A single active mechanical component failure

2) A single active electrical component failure

3) The effects of a high- or moderate-energy pipe rupture

f. The AFWS is provided with diverse power sources so that either of the power sources (AC or DC) meets the AFWS performance requirements.

g. The AFWS provides double isolation valves from the main feedwater system with one check valve and one Class 1E, DC-powered AFW isolation valve in normal open position.

h. The AFWS is designed to preclude water hammer by conforming with the following requirements:

1) Guidance contained in Branch Technical Position (BTP) 10-2 (Reference 21) for reducing the potential for water hammers in SGs

2) Guidance for water hammer prevention and mitigation in NUREG-0927, Rev. 1 (Reference 22)

i. Suitable flood protection during abnormally high water levels is provided to the building where the AFWS components are located, as addressed in Section 3.4.

j. The equipment and floor drainage system is provided with collection and detection of AFWS leakage, which may originate in each AFW pump room, in each AFWST, and areas containing AFWS piping where a moderate- or high-energy pipe rupture is postulated, as defined in Section 3.6.

k. Means are provided to permit periodic surveillance testing of AFW pumps and valves and functional testing of the integrated operation of the system in 10.4-68 Rev. 2

APR1400 DCD TIER 2 accordance with the Technical Specifications, Subsection 3.7.5, providing limiting conditions for operation and the surveillance testing requirements for the system to provide reasonable assurance of continued system reliability during plant operation.

l. Adequate instrumentation and controls are provided to verify that the AFWS is correctly operating in each mode.

m. The automatic initiation signals and circuits are designed so that their failure does not result in the loss of the ability to be manually initiated from the MCR in accordance with NRC RG 1.62 (Reference 31). Details of the engineered safety features system are provided in Section 7.3.

n. The AFWS meets the recommendations identified in NUREG-0635.

o. An AFWS reliability analysis is performed in accordance with Three Mile Island (TMI) Action Item II.E.1.1 of NUREG-0737 (Reference 32). The AFWS is designed to have unavailability from 10-5 to 10-4 per demand as shown in Table 19.1-162 and discussed in Section 19.1.7.6.

p. The AFWS design meets the provision of TMI Action Plan Item II.E.1.2 of NUREG-0737 and 10 CFR 50.62(c)(1) (Reference 33). The AFWS can be either manually actuated or automatically actuated by an auxiliary feedwater actuation signal (AFAS) from the engineered safety feature actuation system (ESFAS) described in Section 7.3 or the diverse protection system (DPS) described in Subsection 7.8.1.1.

q. In conformance with guidance in 10 CFR 50.63 and NRC RG 1.155 (References 34 and 35, respectively), the APR1400 is provided with an AAC power source to cope with an SBO event as described in Section 8.4.

r. The AFWS piping, associated supports, and restraints are designed so that the following do not occur as a result of a single event, such as a ruptured auxiliary feedwater line or a closed isolation valve:

1) Initiating a LOCA 10.4-69 Rev. 2

APR1400 DCD TIER 2

2) Causing failure of the other SGs safety class steam and feedwater lines, MSIVs, MFIVs, SG blowdown isolation valves, or MSADVs

3) Reducing the capability of the ESFAS or the plant protection system

4) Transmitting excessive loads to the containment pressure boundary

5) Compromising the function of the MCR

6) Precluding an orderly cooldown of the RCS

s. Each turbine-driven pump is supplied with steam from a single SG (i.e., the one to which it supplies AFW).

t. The AFW is delivered to the downcomer nozzles of the SGs.

u. A non-safety-grade source of condensate from the condensate storage tank (by gravity feed) can be aligned if the safety-related source is exceeded before shutdown cooling system entry conditions are reached.

v. The principal AFWS pressure-retaining materials are shown in Table 10.4.9-5.

w. The recommendations of NRC RG 1.28 (Reference 3) are applied during fabrication of the AFWS, and preheat guidelines in ASME Section III, Appendix D, Article D-1000 for carbon steel are applied to the AFWS components.

10.4.9.2 System Description 10.4.9.2.1 General Description The AFWS is shown in Figures 10.4.9-1. The AFWS consists of two 100 percent capacity motor-driven pumps, two 100 percent capacity turbine-driven pumps, two 100 percent auxiliary feedwater storage tanks (AFWSTs), valves, two cavitating flow-limiting venturis, and instrumentation. The SG makeup flow requirement is given in Table 19.1-162 and discussed in Subsection 19.1.7.6.

Each pump takes suction from a respective AFWST and has a respective discharge header.

Each pump discharge header contains a pump discharge check valve, flow-modulating valve, AFW isolation valve, and SG isolation check valve. One motor-driven pump and one turbine-driven pump are configured into one mechanical division and joined together 10.4-70 Rev. 2

APR1400 DCD TIER 2 inside containment to feed their respective SG through a common AFW header, which connects to the SG downcomer feedwater line. Each common AFW header contains a cavitating venturi to restrict the maximum AFW flow rate to each SG.

A cross-connection is provided between the AFWSTs so that either tank can supply either division of the AFWS. Each of the safety Class 3, seismic Category I AFWSTs contains 100 percent of the total volume specified in Subsection 10.4.9.1.1. A manually operated isolation valve is provided for each AFWST to provide separation. The line connected to non-safety sources can be manually aligned for gravity feed to either AFW pump suction if the AFWSTs reach low levels before shutdown cooling system entry conditions are reached.

A flow recirculation line is provided downstream of each pump discharge to allow for the following:

a. A continuous minimum recirculation flow to the AFWST for pump

b. Full or minimum recirculation flow testing of the pumps A multi-stage flow-restrictive orifice restricts the flow to the minimum required for pump protection.

A non-condensing AFW pump turbine with an atmospheric discharge line is provided for each turbine-driven pump. Each turbine is supplied with the driving steam from its respective SG upstream of the main steam isolation valves (MSIVs) in the main steam system. Each supply line contains an air-operated steam isolation valve.

The turbine exhaust steam is discharged to atmosphere through a seismic Category I vent line routed through the roof.

Portable pump connections is provided at each turbine-driven pump suction and discharge line. The piping section connected at the AFW supply lines is designed as safety Class 3, seismic Category I. The piping section downstream of the isolation valve at the exterior of the auxiliary building up to the connector is designed as non-safety Class, seismic Category I.

10.4.9.2.2 Component Description A summary of design parameters and codes for the major AFWS components is given in Table 10.4.9-1.

10.4-71 Rev. 2

APR1400 DCD TIER 2 10.4.9.2.2.1 Auxiliary Feedwater Pumps The AFWS pumps are horizontal, multistage, centrifugal pumps. Each pump is capable of delivering the system design flow of 2,461 L/min (650 gpm) to the SG(s) over the entire range of SG pressure of 6.3 through 87.2 kg/cm2A (90 through 1,240 psia).

Each pump has adequate flow capacity to provide the required design basis flow to the SGs plus the capacity to continuously recirculate this flow. The recirculation lines are adequately sized so that full pump flow can be recirculated through the bypass provided around the flow restrictive orifice for full flow pump testing during power operation. The bypass line contains a manual flow control valve to vary the pump flow for performance testing.

10.4.9.2.2.2 Turbine-Driven Auxiliary Feedwater Pump Turbines Each turbine is supplied with a hydraulic governor valve and a turbine trip and throttle valve with reset capability. The turbine speed is automatically controlled by the governor valve and is maintained to provide the required AFW flow. The turbine can be stopped by remotely closing the turbine trip and throttle valve using a trip switch located in the MCR, RSR, or local control panel.

Each AFW pump turbine is capable of being started and put on line very quickly from a cold condition. The steam supply line up to AFW pump turbine steam isolation valve is pressurized at near operating temperature during normal power operation to implement fast turbine start and to prevent thermal shock. A low-point drain, located upstream of the AFW pump turbine steam isolation valve, provides a continuous blowdown through a pressure-reducing orifice to prevent water slugs from entering the turbine.

10.4.9.2.2.3 Auxiliary Feedwater Storage Tanks Two AFWSTs (one tank in division 1 and one tank in division 2) provide a primary source for the AFW. Each tank contains 100 percent of the required water volume given in Subsection 10.4.9.1.1. A common tie line with two normally closed manual valves connects the two AFWSTs.

Each tank, which consists of a stainless-steel-lined, reinforced concrete enclosure, is an integral part of the safety-related, seismic Category I auxiliary building and is protected 10.4-72 Rev. 2

APR1400 DCD TIER 2 against environmental hazards. The provisions are provided so that a failure or leaking of the tank does not adversely affect other essential components.

Periodic grab sampling is performed to provide reasonable assurance that the suspended solids do not exceed 0.1 ppm. Any excess in the suspended solids is corrected by operator actions using the feed-and-bleed method. The AFWS is supplied with makeup water from the demineralized water storage tank. The minimum and maximum temperatures of the condensate supplied or stored in each tank are 4.4 °C (40 °F) and 48.9 °C (120 °F),

respectively. The design temperature of the AFWST is 60 °C (140 °F).

A non-safety-related backup water source by gravity feed to AFW pump suction is also available from the condensate storage tank and raw water storage tank.

Two external water injection lines are provided to makeup AFWST at the AFWST cross-connection line when the AFWSTs and non-safety-related backup water source run out.

10.4.9.2.2.4 Auxiliary Feedwater Cavitating Venturis A cavitating venturi is located in the common AFW supply line to each SG. Each cavitating venturi limits the maximum AFW flow that can be supplied to a SG.

10.4.9.2.2.5 Valves The following valves are required to maintain their functional capability during a safe plant shutdown.

a. Auxiliary feedwater isolation valves The auxiliary feedwater isolation valves are normally open during normal plant operations. These valves, in series with check valves, provide containment double isolation. These valves are automatically closed by the ESFAS signal at a SG level high than the normal operation water level. These valves can be individually opened or closed remotely from the MCR and at the RSR. The valves are provided with motor operators and with manual handwheels.

b. Auxiliary feedwater modulating valves The auxiliary feedwater modulation valves are normally open when the system is in standby. These valves have a close/modulating control mode. When the 10.4-73 Rev. 2

APR1400 DCD TIER 2 valves are in modulating mode, the associated SG level signal controls the valves to the desired position or closes the valves. The valve control switches and position indicators are provided on the MCR and RSR. The valves can be controlled manually and are provided with solenoid operators. The failure mode of these valves is fail-open.

c. Auxiliary feedwater pump turbine steam isolation valves The auxiliary feedwater pump turbine steam isolation valves isolate the steam supply to the AFW pump turbines. Opening of these valves supplies steam to the turbines and starts governor control of the steam flow to the turbines. These valves are automatically opened on an AFAS from the ESFAS or DPS. These valves can be remotely opened and closed from the MCR and at the RSR.

10.4.9.2.3 Electrical Power Supply Each AFW line receives power from an associated Class 1E emergency power system. In the event of LOOP, power is supplied by emergency diesel generators. In accordance with NUREG-0611 and NUREG-0635, all instrumentation, controls, and valves that are essential to the operation of the turbine-driven AFW pump lines are supplied from battery-backed Class 1E power supplies for 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. Battery-backed power is also available for the governor speed control of the AFW pump turbine. An AAC source of standby power is provided for the SBO. The emergency power train designations for the motor-driven AFW pumps, power-operated valves, instrumentation, and controls are given in Table 10.4.9-2. A more detailed description of the onsite power systems is provided in Section 8.3.

10.4.9.2.4 Auxiliary Feedwater System Operation and Control The AFWS is normally in standby mode, available for operation during normal power operation and during plant transients and accidents. The AFWS is not used during plant startup and normal plant shutdown. The AFWS supply capacity is adequate for makeup to the SGs during hot standby and cooldown conditions following a transient or accident condition. The AFWS can be manually or automatically actuated by an AFAS from the ESFAS described in Section 7.3 or the DPS described in Subsection 7.8.1.1. The AFWS is designed to deliver flow to the SG(s) within 60 seconds upon receipt of an AFAS.

10.4-74 Rev. 2

APR1400 DCD TIER 2 At the low water level setpoint of the SG, the AFAS from the ESFAS and DPS actuates the AFWS as follows:

a. Starts the associated motor-driven pump

b. De-energizes the solenoid to open the associated turbine steam isolation bypass valve

c. Starts associated turbine-driven pump by de-energizing the solenoid to open the associated turbine steam isolation valve

d. Opens the associated AFW isolation valves if they are closed

e. Modulates the associated AFW modulating valves

f. Verifies that turbine governor speed control is at full rated speed After the AFWS is actuated, the AFW modulating valve controls the flow to the SG(s) to control the SG normal water level. If the AFW modulating control becomes inoperable, the AFW isolation valve is controlled by a cycling signal based on the SG high and low levels. If automatic flow control fails, the operator can control the SG water level through the open/close of associated AFW isolation valves via a control switch or handwheel.

The AFW flow can be terminated by operator action within 30 minutes to close the AFW isolation valves and/or shut off the associated AFW pumps if the SG is faulted (i.e., the main feedwater or main steam line breaks).

10.4.9.2.5 Design Features for Minimization of Contamination The AFWS is designed with specific features to meet the requirements of 10 CFR 20.1406 (Reference 7) and Regulatory Guide 4.21 (Reference 8). The basic principles of NRC RG 4.21, and the methods of control suggested in the regulations, are specifically delineated in four design objectives and two operational objectives, as described in Subsection 12.4.2.

The following evaluation summarizes the primary features to address the design and operational objectives for the AFWS.

10.4-75 Rev. 2

APR1400 DCD TIER 2 Prevention/Minimization of Unintended Contamination

a. The AFWS is designed with specific features to meet the requirements of 10 CFR 20.1406 (Reference 7) and Regulatory Guide 4.21 (Reference 8). The basic principles of NRC RG 4.21, and the methods of control suggested in the regulations, are specifically delineated in four design objectives and two operational objectives, as described in Subsection 12.4.2. The following evaluation summarizes the primary features to address the design and operational objectives for the AFWS.

b. The auxiliary feedwater pump turbine system piping uses carbon steel material and is fabricated to ASME Section III, Class 3 requirements.

Adequate and Early Leak Detection The valve stem leak-offs and drains are collected and directed to the liquid radwaste system for treatment and release.

Reduction of Cross-Contamination, Decontamination, and Waste Generation The auxiliary feedwater pump turbine system piping uses carbon steel material and is fabricated to ASME Section III, Class 3 requirements up to the containment isolation check valves. Auxiliary feedwater piping is required to be fabricated of stainless steel material, be of welded construction, and be designed to safety Class 3 and seismic Category I requirements. In addition, any leakage developed on this segment of piping is expected to be collected in the sump. Hence, the risk for leakage and the consequence of contamination is low. This design approach minimizes leakage and unintended contamination of the facility and the environment.

Decommissioning Planning The SSCs are designed for the full service life and are fabricated as individual assemblies for easy removal.

Operations and Documentation The COL applicant is to maintain the complete documentation of system design, construction, design modifications, field changes, and operations (COL 10.4(2)).

Documentation requirements are included as a COL information item.

10.4-76 Rev. 2

APR1400 DCD TIER 2 Site Radiological Environmental Monitoring Because of its normal status in standby mode and low possibility for contamination, the potential for environmental contamination from liquid leakage is minimal. Therefore, inclusion of the auxiliary feedwater system 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 of radiological contamination.

10.4.9.3 Safety Evaluation An adequate safety-related water supply, designed to seismic Category I, is available to allow the plant to remain at hot standby for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> followed by an orderly cooldown to shutdown cooling system entry condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, in conformance with BTP 5-4 (Reference 36). This is possible even if the initiating event is a main feedwater line break with a spill of the AFW for 30 minutes at the maximum AFW flow.

For the design basis considerations in Subsection 10.4.9.1, sufficient AFW flow can be provided at the required temperature and pressure, even if a secondary pipe break event occurs, if any one AFW pump fails to deliver flow and no operator action is taken for up to 30 minutes following the event.

The AFWS is the only safety-related source of makeup water to the SGs for heat removal when the feedwater system is inoperable or during postulated accidents. Therefore, the AFWS is designed with redundancy, diversity, and separation to provide reasonable assurance of its ability to perform the safety function.

A minimum of 1,514,165 L (400,000 gal) of dedicated AFW is available in each mechanical division. The basis for 1,514,165 L (400,000 gal) of dedicated AFW in each mechanical division is as follows:

10.4-77 Rev. 2

APR1400 DCD TIER 2 AFW to remove decay heat during hot standby  : 799,971 L (211,330 gal)

(8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />) and cooldown (6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />)

AFW to remove RCS sensible heat  : 173,849 L (45,926 gal)

AFW to make up the intact SG  : 210,912 L (55,717 gal)

AFW to make up the ruptured SG  : 100,605 L (26,577 gal)

AFW to remove one RCP operation dispersion heat for  : 146,325 L (38,655 gal) 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> Total minimum required AFW storage inventory  : 1,431,662 L (378,205 gal)

A minimum volume per tank determined  : 1,514,165 L (400,000 gal)

In conformance with BTP 10-1 (Reference 37), the AFWS has diversity in motive power sources and consists of two full-capacity independent divisions that use separate and multiple power sources. Redundancy is provided by using two 100 percent capacity motor-driven AFW pumps, two 100 percent turbine-driven AFW pumps (one each for each SG), and two 100 percent capacity auxiliary feedwater storage tanks.

Diversity is provided by using two types of pump drivers (steam turbines and electrical motors) and AC and DC emergency electrical power sources. Separation is provided with separate power and instrumentation and control subsystems having appropriate measures that preclude interaction between subsystems. In addition, independent piping subsystems are incorporated into the design and protected at interconnection points with appropriate isolation or check valves to provide redundancy and diversity for the AFW flow path to SGs.

In the event of a SBO, the turbine-driven pump lines provided with battery-backed power are capable of providing AFW to the SGs coincident with a single failure for 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.

Battery-backed power is also available to the turbine governor speed control. An AAC source of standby power is provided for the SBO.

The failure modes and effects analysis, assuming a postulated pipe failure concurrent with a single active component failure, is presented in Table 10.4.9-3. Analysis of transients and accidents requiring the AFWS to function (addressed in Chapter 15), demonstrates that the AFWS satisfies the design basis described in Subsection 10.4.9.1.

Following a primary-side LOCA, the AFWS may be used to provide reasonable assurance that the SG tubes are covered to enhance the closed-system containment boundary. The 10.4-78 Rev. 2

APR1400 DCD TIER 2 two motor-driven pumps are used for this purpose because steam for the turbine-driven pumps may or may not be available.

Water hammer can be caused by conditions such as introduction of voids, steam, or heated water in normally water-filled lines, condensation, and water entrainment in steam-filled lines, or rapid valve actuation. The AFWS is designed as follows to preclude water hammer in accordance with BTP 10-2 and NUREG-0927:

a. The temperature upstream of the AFW isolation check valve on each AFW line is continuously monitored for early detection of backleakage from the main feedwater to minimize heated water introduction, and is alarmed in the MCR.

b. The steam supply line up to the AFW pump turbine steam isolation valve is warmed during normal power operation to minimize condensation.

c. A low-point drain upstream of the AFW pump turbine steam isolation valve provides a continuous blowdown through a pressure-reducing orifice to minimize water entrainment.

The COL applicant is to provide operating and maintenance procedures for the following items in accordance with NUREG-0927 and a milestone schedule for implementation of the procedures (COL 10.4 (8)).

a. Introduction of void, steam, or heated water in water-filled lines and components

b. Filling and venting of water-filled lines and components

c. Condensation and water entrainment in steam-filled lines and components

d. Warmup and drainage of steam-filled lines

e. Prevention of rapid valve actuation

f. Valve alignment effects on line conditions Steam binding of the AFW pumps is minimized by the following design and operational features:

a. The temperature upstream of the AFW isolation check valve on each AFW line is monitored continuously for early detection of backleakage from the main 10.4-79 Rev. 2

APR1400 DCD TIER 2 feedwater and is alarmed in the MCR. In the event of loss of MCR indication, the sensor also provides alarm and conditions monitored locally.

b. As the leakage continues, the steam voids, which can occur around the check valve and can reach the AFW pump casing, may cause the AFW pump to become steam binding. The AFWS is designed to avoid steam binding of the AFW pumps by continuous system venting through the AFWST and by the use of check valves upstream of the interface with the feedwater system. In the event that steam binding of the AFW pumps occurs, the MCR alarm associated with the temperature sensor described above signals the plant operator to vent the AFW pumps. Leakage through the check valve(s) is corrected by implementing appropriate procedures.

The AFWS is designed in conformance with the intent of GDC 2 regarding the effects of natural phenomena such as wind, tornado, hurricane, flood, and earthquake, as described in Sections 3.3, 3.4, and 3.7. All AFWS components are located in seismic Category I structures, which also protects the components from external environmental hazards in conformance with NRC RG 1.29 (Reference 20), Seismic Design Classification.

The AFWS is designed in conformance with the intent of GDC 4 regarding the dynamic effects including the effects of missiles, pipe whipping, and discharge of fluids.

All piping and components essential to AFW operation are designed to seismic Category I standards as described in Section 3.7, and are designed to accommodate, are located to protect against, or are protected from internal flooding and internal missiles as described in Sections 3.4 and 3.5. All components and piping are designed to protect against the effects of high- and moderate-energy pipe ruptures as described in Section 3.6.

The AFWS is designed in conformance with the intent of GDC 5 regarding sharing of systems among nuclear power units.

The AFWS can be manually or automatically actuated by an AFAS from the MCR to safely shutdown and maintain the plant under normal and accident conditions, including LOCAs, in conformance with GDC 19.

The AFWS is designed in conformance with the intent of GDC 34 and 44 regarding suitable redundancy in components and features to remove residual heat. The AFWS is provided with AC and DC emergency power and suitable redundancy in components and 10.4-80 Rev. 2

APR1400 DCD TIER 2 features to supply AFW to the SG(s) for removal of heat in the event of single active component failure.

In conformance with GDC 45 and 46, the system is designed to perform periodic inspection of the system components, and periodic pressure and functional testing for the system operability and functional performance as described in Subsection 10.4.9.4.

10.4.9.4 Inspection and Testing Requirements Inspections and tests during the AFWS component fabrication are performed and documented in accordance with ASME Section III for the safety-related components and ASME B31.1 (Reference 5) for the non-safety-related components. The component performance tests are performed in the vendors facility as necessary. The AFWS is designed and installed for inservice inspections and tests in accordance with ASME Section XI (Reference 23).

10.4.9.4.1 Auxiliary Feedwater Performance Tests Testing of the AFWS is conducted in accordance with Subsection 14.2.12.

The COL applicant is to develop procedures to perform periodic testing or maintenance, including independent verification in accordance with NUREG-0635 (COL 10.4(11)).

10.4.9.4.2 Reliability Tests and Inspections

a. System-level tests Following completion of installation, and prior to initial startup, the entire AFWS is hydrostatically tested in accordance with the requirements of ASME Section III.

After the plant is brought into operation, periodic tests and inspections of the AFWS components and subsystems are performed in accordance with Technical Specifications to provide assurance of proper operation.

The scheduled tests and inspections are necessary to verify system operability, since during normal plant operation, the AFWS components are aligned for emergency operation and serve no other function. The tests defined permit a complete checking at the component level during normal plant operation.

Satisfactory operability of the complete system can be verified during a normal 10.4-81 Rev. 2

APR1400 DCD TIER 2 scheduled refueling shutdown. The complete schedule of tests and inspections of the AFWS is detailed in Chapter 16.

b. Component tests In addition to the system-level tests, tests to verify proper operation of the AFWS components are also conducted. These tests supplement the system-level tests by verifying acceptable performance of each active component in the AFWS.

Pumps and valves are tested in accordance with ASME OM (Reference 25). A full-flow test line is provided so that the pumps can be performance-tested after maintenance at various flow rates up to and including the design point.

In accordance with the recommendations of NUREG-0635, a 48-hour endurance test is to be performed on the AFW pumps to demonstrate that the pumps have the capability for continuous operation over an extended time period without failure.

10.4.9.5 Instrumentation Requirements Sufficient instrumentation and controls are provided to adequately monitor and control the AFWS. Appropriate methods are employed to provide reasonable assurance of independent operation of the instrumentation and control channels to prevent any adverse and undesirable interaction between the AFW lines. All non-safety-related instrumentation and controls are designed so that any failure will not cause degradation of any safety-related equipment function. All valve and pump controls, and status and parameter indications, are listed in Table 10.4.9-4. The emergency power train designations for instrumentation and controls are given in Table 10.4.9-2. All AFWS parameter measurements and indication instrumentation are described below.

10.4.9.5.1 Pressure Instrumentation

a. Auxiliary feedwater pump discharge pressure The MCR and RSR are provided with a discharge pressure indication downstream of each of motor-driven AFW pump and turbine-driven AFW pump.

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APR1400 DCD TIER 2

b. Auxiliary feedwater pump suction pressure The MCR and RSR are provided with a suction pressure indication and low-pressure alarm upstream of each of motor-driven AFW pump and turbine-driven AFW pump.

c. Auxiliary feedwater pump turbine inlet pressure The MCR and RSR are provided with inlet pressure indication for AFW pump turbines.

d. Local pressure indications Local pressure indications are provided at the following locations:

1) AFW pump turbine steam inlets

2) AFW pump turbine steam exhausts

3) Each AFW pump suction

4) Each AFW pump discharge 10.4.9.5.2 Temperature Instrumentation

a. Auxiliary feedwater isolation valve downstream temperature The MCR is provided with temperature indication downstream of AFW isolation valves and a high-temperature alarm for detection of backleakage and steam voiding.

b. Auxiliary feedwater storage tank temperature The MCR is provided with AFWST temperature indication and high-temperature and low-temperature alarms.

c. Auxiliary feedwater pump turbine bearing temperatures The MCR has an AFW pump bearing temperature indication.

10.4-83 Rev. 2

APR1400 DCD TIER 2 10.4.9.5.3 Flow Instrumentation

a. Auxiliary feedwater pump discharge flow Flow indications for the motor-driven AFW pump and turbine-driven AFW pump discharge are provided locally in the MCR and RSR. These are designed and procured to meet the criteria given in NRC RG 1.97 (Reference 38).

b. Auxiliary feedwater pump recirculation flow Flow indications for the motor-driven AFW pump and turbine-driven AFW pump recirculation are provided locally and in the MCR and RSR.

10.4.9.5.4 Level Instrumentation

a. Auxiliary feedwater storage tank level Level indications and low-level alarms for AFWSTs are provided in the MCR and RSR. These are provided by redundant level instrumentation on each tank.

The low-level alarm is set at a point to allow 30 minutes for manual alignment of the other AFWST or the non-safety backup makeup supply before the level decreases to a point where pump suction is lost. These are designed and procured to meet the criteria given in NRC RG 1.97.

b. Steam supply line drip leg level high-high alarms An alarm is annunciated in the MCR when the drip leg level is at the high-high level. This alerts the operator that the drip leg level control valve is not operating properly and is to be opened manually from the MCR.

10.4.9.5.5 Turbine-Driven Pump Turbine Speed Instrumentation is provided in the MCR and RSR for indication of the turbine speed. The AFW pump turbine is brought to the rated speed by modulating the associated AFW pump turbine governor valve.

10.4-84 Rev. 2

APR1400 DCD TIER 2 10.4.10 Auxiliary Steam System The auxiliary steam system supplies auxiliary steam to all usage points through an auxiliary steam header interconnecting the main steam system and the auxiliary boiler.

10.4.10.1 Design Basis The auxiliary steam system has the following functions:

a. During normal plant operation, the auxiliary steam system furnishes auxiliary steam to various equipment by extracting main steam, and then the condensate from this equipment is returned to the condenser.

b. During plant startup, shutdown, or cleanup/recirculation when main steam is unavailable, the auxiliary steam comes from the auxiliary boiler and is supplied to various equipment, and the condensate from this equipment is collected into the auxiliary boiler.

10.4.10.2 System Description 10.4.10.2.1 General Description The auxiliary steam system flow diagram is shown in Figure 10.4.10-1.

The auxiliary steam system consists primarily of a main steam pressure-reducing valve on the auxiliary steam header, a condensate receiver tank with vent condenser, condensate return pumps, an auxiliary boiler package, and associated piping, valves, instrumentation, and controls.

The auxiliary steam system provides steam for the following purposes:

a. Deaerator pegging during recirculation/cleanup and low-power operation mode

b. Turbine seals until main turbine extraction steam is available

c. Feedwater pump turbine seals until main steam is available

d. Feedwater pump turbine testing during plant shutdown

e. Auxiliary feedwater pump turbine testing during plant shutdown 10.4-85 Rev. 2

APR1400 DCD TIER 2

f. Boric acid concentrator package and gas stripper package in the chemical and volume control system

g. Decontamination services in the reactor containment building and fuel handling area

h. Solid radwaste system (SRS) for heating SRS concentrates treatment system Condensate from the boric acid concentrator package, gas stripper package, and solid waste treatment system is collected in the condensate receiver tank and transferred to the condenser if the source of steam is from the MSS, or to the auxiliary boiler if the source of steam comes from the auxiliary boiler by using the condensate return pumps. Any condensate that flashes inside the condensate receiver tank is condensed in the attached vent condenser and then returns to the condensate receiver tank.

At the upstream of the condensate return pump, the condensate is monitored continuously for radioactivity. If contaminated, the radiation monitor actuates an alarm in the MCR and automatically diverts the radioactive or potentially radioactive condensate to the liquid radwaste system.

Condensate from the others is collected at the condenser because it is considered non-potentially radioactive condensate.

The auxiliary boiler is located inside the auxiliary boiler building in yard area, and makeup water to the auxiliary boiler is provided from the makeup demineralizer system.

10.4.10.2.2 System Operation The auxiliary boiler supplies saturated steam at 16.2 kg/cm2A (230 psia) to the auxiliary steam header during plant startup, cleanup/recirculation, and shutdown when main steam is not available.

During plant normal operation, the main steam system of the unit provides steam to the auxiliary steam header. When main steam is used as the source of auxiliary steam, the steam enters the auxiliary steam header by opening a motor-operated valve. The steam pressure is reduced to 15.1 kg/cm2G (215 psig) through a pressure-reducing valve.

10.4-86 Rev. 2

APR1400 DCD TIER 2 However, when the auxiliary steam boiler is used as the source of auxiliary steam, the motor-operated valve is closed.

If a pressure-reducing valve fails closed, manual bypass valves are provided to allow for manual operation. If a pressure-reducing valve fails open, pressure relief valves downstream of the pressure-reducing valve are provided to protect the piping system and equipment from overpressurization. Manual isolation valves are provided upstream and downstream of the valve to allow for maintenance of the pressure-reducing valve. A drain valve located between the upstream isolation valve and the pressure-reducing valve is provided for drainage of the hot fluid.

The condensate return pumps are controlled by the water level in the condensate receiver tank. When the condensate reaches the high water level, one condensate return pump starts. When the condensate reaches the low water level, the pump stops. If the lead pump is tripped, the standby pump automatically starts.

10.4.10.2.3 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 controls 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 auxiliary steam system.

The auxiliary steam system is designed to provide process steam during plant startup, shutdown, and normal operation. The auxiliary steam system shares the same process heat exchangers and other steam loads that are supplied with extraction steam during normal operation.

The auxiliary steam system has been evaluated for leak potential 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 auxiliary steam system is designed to contain leaks, with sufficient spaces for prompt assessment and evaluation of the adequacy and the appropriateness of responses to isolate and mitigate leaked areas. Thus, unintended contamination to the facility and the environment is minimized or prevented by 10.4-87 Rev. 2

APR1400 DCD TIER 2 the SSC packaged design and facility design, supplemented by operational procedures and programs for inspection and maintenance activities.

Prevention/Minimization of Unintended Contamination

a. The auxiliary steam system condensate receiver tank, vent condenser, and pumps are located in an enclosed area at the foundation level inside the auxiliary building.

The boiler is located in its auxiliary boiling building outside the auxiliary building.

The components are designed to be skid-mounted and vendor-packaged units.

The floors are sloped, coated, and drains are directed to the local drain hubs and then sump. This design approach prevents unintended contamination of the facility and the environment.

b. The auxiliary steam system is designed with sufficient capacities and redundancy to support plant operation when main steam is not available. The components are designed in accordance with ASME Section VIII (Reference 39) and other applicable codes for life-cycle planning, thus minimizing unintended contamination and waste generation.

c. The facility area that houses the system components, including the equipment cubicles that contain radioactively contaminated or potentially contaminated fluid, shall have sloped floors with coating to facilitate the draining of fluid into drain pipes and/or trenches that direct liquid into a local sump. Tank cubicles shall have coated walls to a height that can provide temporary barriers of the contained fluids. In addition, the coated walls provide smooth surfaces for cleaning and to facilitate liquid draining. To the extent practicable, the cubicle shall also have early leak detection capabilities to detect component leakage, overflow, and/or tank rupture, and shall have provisions to initiate alarm signals for operator actions.

The facility layout shall facilitate the operators prompt assessment and fast response when needed.

d. Sumps that contain contaminated or potentially contaminated fluid shall be equipped with level switches to initiate pumping when sump levels reach a predetermined setpoint. The concrete sumps shall be coated and shall have seals to prevent unintended infiltration of liquid into the concrete sumps. The sumps shall be designed to facilitate periodic maintenance and inspection of the coating.

10.4-88 Rev. 2

APR1400 DCD TIER 2

e. Piping embedment shall be minimized to the extent practicable. Where embedment cannot be avoided, consideration shall be given to minimizing embedded piping lengths and using double-walled piping with leak detection capabilities on the outer piping.

f. Buried piping in the yard and between buildings and facilities shall be minimized to the extent practicable. Piping tunnels with leak detection capability and accessibility shall be used for piping that contains radioactive or potentially radioactive fluids.

Adequate and Early Leak Detection The auxiliary steam system is designed with automated operation with manual initiation for the different modes of operation. Adequate instrumentation, including level and pressure elements and a radiation monitor, is provided to monitor and control operations. Upon a high radiation signal, the condensate is diverted to the LWMS for treatment and release.

This design approach thus provides early detection and minimizes spread of contamination and waste generation.

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 radioactive environment, thus minimizing waste generation.

b. The auxiliary steam system is equipped with a radiation sampling to continuously check the contamination level in the condensate, and sampling and analysis for confirmation and calibration of the radiation monitor, if necessary. If contamination is detected at or above a setpoint, an alarm is initiated for operator actions, and a signal is sent to open the condensate transfer valves to the LWMS for treatment and release. This design approach minimizes cross-contamination to other components.

c. The auxiliary boiler blowdown and drains are routed to the auxiliary boiler building sump and then are routed to the turbine generator building (TGB) sump for radiation monitoring. When contamination level of the drains is detected and exceeds a predetermined setpoint, they are routed to the LWMS for processing and release via the condensate polishing area sump.

10.4-89 Rev. 2

APR1400 DCD TIER 2 Decommissioning Planning

a. The SSCs are designed for the full service life and are fabricated as individual assemblies for easy removal.

b. The SSCs are designed with decontamination capabilities. Demineralized water is provided for makeup as well as for decontamination. Design features such as welding techniques used and surface finishes are intended to minimize the need for decontamination, and hence reduce waste generation.

c. The auxiliary steam system is designed with minimum embedded or buried piping, thus minimizing unintended contamination due to leaking of buried or embedded piping. Yard piping is routed in an underground concrete tunnel that is designed with a leakage collection sump, level switch, and pump. An alarm is also provided in the MCR for operator actions in the event of detection of liquid.

Operations and Documentation

a. The auxiliary steam system is designed with adequate instrumentation for automatic operation with manual initiation. The boiler is a self-contained vendor package complete with its own instrumentation. Operation of the boiler operation is controlled from a local panel but with remote shutdown at low fuel oil level, or at operator initiation from the MCR.

b. The auxiliary steam system condensate receiver tank, vent condenser, and pumps are located in an enclosed cubicle inside the auxiliary building, and the boiler is located in an independent auxiliary boiler building for separation purposes.

Adequate ingress and egress spaces are provided for prompt assessments and appropriate responses when and where they are needed.

c. The COL applicant is to establish operational procedures and maintenance programs as related to leak detection and contamination control in accordance with NRC RG 4.21 (COL 10.4(1)).

d. The COL applicant is to maintain complete documentation of system design, construction, design modifications, field changes, and operations (COL 10.4(2)).

Site Radiological Environmental Monitoring 10.4-90 Rev. 2

APR1400 DCD TIER 2 The auxiliary steam system is designed with a low level of contamination through leakage in the condensate receiver tank, the vent condenser, pumps, boiler, and the associated piping and instruments. Industry experience demonstrates that the integrity of the auxiliary steam system is well maintained, and the control methods included in the current design further minimize or prevent contamination of the facility and the environment.

Hence, a radiological environmental monitoring program is not required for this system.

10.4.10.3 Safety Evaluation The auxiliary steam system has no safety-related function and therefore does not require a nuclear safety evaluation.

10.4.10.4 Inspection and Testing Requirements Preoperational testing of the auxiliary steam system is performed as described in Section 14.2 to demonstrate that the systems and components operate in accordance with applicable test programs and specifications.

10.4.10.5 Instrumentation Requirements The auxiliary steam system pressure is indicated locally and in the MCR and RSR. High and low steam pressures are alarmed in the MCR and RSR. Main steam flows to the auxiliary steam header are indicated in the MCR and RSR.

Steam flow rate to the boric acid concentrator package is indicated locally. The fluid level and pressure in the condensate receiver tank are indicated locally. High-high and low-low level alarms are provided at the local panel. The auxiliary boiler package is provided with the necessary controls and indications for local or remote monitoring of system operation.

The radiation monitor is provided to monitor leaked radioactive materials in the condensed water from the boric acid concentrator package, gas stripper package, or solid waste treatment system. If the condensate is contaminated, the radiation monitor actuates an alarm in the MCR and automatically redirects the condensate to the liquid waste management system for treatment.

10.4.11 Combined License Information COL 10.4(1) The COL applicant is to establish operational procedures and maintenance programs for leak detection and contamination control.

10.4-91 Rev. 2

APR1400 DCD TIER 2 COL 10.4(2) The COL applicant is to maintain the complete documentation of system design, construction, design modifications, field changes, and operations.

COL 10.4(3) The COL applicant is to provide the location and design of the cooling tower, basin, and CW pump house, if used.

COL 10.4(4) The COL applicant is to confirm that the water hammer events are bounded by the system design pressure value with a hydraulic transient analysis or otherwise demonstrate that the design is acceptable to satisfy GDC 4 in regard to the design provisions that are implemented to accommodate the effects of discharging water that could result from a malfunction or failure of a component or piping in the system.

COL 10.4(5) The COL applicant is to provide elevation drawings.

COL 10.4(6) The COL applicant is to address the design features for the prevention of contamination.

COL 10.4(7) The COL applicant is responsible for provisions of temporary shielding, if required, and mobile equipment, including spent resin fill-head for packaging of the contaminated spent resin, provisions of temporary storage, and shipment of packaged contaminated CPS spent resin for off-site treatment and/or disposal.

COL 10.4(8) The COL applicant is to provide operating and maintenance procedures in accordance with NUREG-0927 and a milestone schedule for implementation of the procedures.

COL 10.4(9) The COL applicant is to describe the nitrogen or equivalent system design for SG drain mode.

COL 10.4(10) The COL applicant is to prepare the Site Radiological Environmental Monitoring Program.

COL 10.4(11) The COL applicant is to develop procedures to perform periodic testing or maintenance, including independent verification in accordance with NUREG-0635.

10.4-92 Rev. 2

APR1400 DCD TIER 2 COL 10.4(12) The COL applicant is to determine the wet bulb temperature correction factor to account for potential interference and recirculation effects.

10.4.12 References

1. HEI Standards for Steam Surface Condensers, 9th Edition, Heat Exchanger Institute, 2006.

2. NRC RG 1.26, Quality Group Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants, Rev. 4, U.S.

Nuclear Regulatory Commission, March 2007.

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

Rev. 4, U.S. Nuclear Regulatory Commission, June 2010.

4. 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 2008 Addenda.

5. ASME B31.1, Power Piping, The American Society of Mechanical Engineers, 2010.

6. NUREG-0800, Standard Review Plan, Section 10.4.2, "Main Condenser Evacuation System," Rev. 3, U.S. Nuclear Regulatory Commission, March 2007.

7. 10 CFR 20.1406, Radiological Criteria for Unrestricted Use, U.S. Nuclear Regulatory Commission.

8. NRC RG 4.21, Minimization of Contamination and Radioactive Waste Generation:

Life-Cycle Planning, U.S. Nuclear Regulatory Commission, June 2008.

9. HEI Performance Standards for Liquid Ring Vacuum Pumps, 3rd Edition, Heat Exchange Institute, 2005.

10. ASME B16.34, Valves-Flanged, Threaded, and Welding End, The American Society of Mechanical Engineers, 2009.

11. ASME Boiler and Pressure Vessel Code,Section V, Nondestructive Examination, The American Society of Mechanical Engineers, 2010.

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APR1400 DCD TIER 2

12. NUREG-0800, Standard Review Plan, BTP 3-3, Protection Against Postulated Piping Failures in Fluid Systems Outside Containment, Rev. 3, U.S. Nuclear Regulatory Commission, March 2007.

13. NUREG-0800, Standard Review Plan, BTP 3-4, Postulated Rupture Locations in Fluid System Piping Inside and Outside Containment, Rev. 2, U.S. Nuclear Regulatory Commission, March 2007.

14. NRC RG 1.68, Initial Test Programs for Water-Cooled Nuclear Power Plants, Rev. 3, U.S. Nuclear Regulatory Commission, March 2007.

15. ANSI/HI Standards, Hydraulic Institute, 2010.

16. ANSI/AWWA C504, Rubber-Seated Butterfly Valves, American Water Works Association, 2010.

17. ASME PTC 23, Atmospheric Water Cooling Equipment, The American Society of Mechanical Engineers, 2003.

18. EPRI PWR Secondary Water Chemistry Guidelines: Rev. 6, EPRI 1008224, December 2004 and Rev. 7, EPRI 1016555, Electric Power Research Institute, February 2009.

19. NRC RG 8.8, Information relevant to Ensuring the Occupational Radiation Exposures at Nuclear Power Stations will be ALARA, Rev. 3, U.S. Nuclear Regulatory Commission, June 1978.

20. NRC RG 1.29, Seismic Design Classification, Rev. 4, U.S. Nuclear Regulatory Commission, March 2007.

21. NUREG-0800, Standard Review Plan, BTP 10-2, Design Guidelines for Avoiding Water Hammers in Steam Generators, Rev. 4, U.S. Nuclear Regulatory Commission, March 2007.

22. NUREG-0927, Evaluation of Water Hammer Occurrences in Nuclear Power Plants, Rev. 1, U.S. Nuclear Regulatory Commission, March 1984.

23. 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 2008 Addenda.

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APR1400 DCD TIER 2

24. MSS SP-61, Pressure Testing of Valves, the Manufacturers Standardization Society, 2009.

25. ASME OM, Code for Operation and Maintenance of Nuclear Power Plants, The American Society of Mechanical Engineers, 2001.

26. NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, U.S.

Nuclear Regulatory Commission, May 2, 1989.

27. NRC RG 1.143, Design Guidance for Radioactive Waste Management Systems, Structures, and Components Installed in Light-Water-Cooled Nuclear Power Plants, Rev. 2, U.S. Nuclear Regulatory Commission, November 2001.

28. NUREG-0800, Standard Review Plan, BTP 5-1, Monitoring of Secondary Side Water Chemistry in PWR Steam Generators, Rev. 3, U.S. Nuclear Regulatory Commission, March 2007.

29. NUREG-0611, Generic Evaluation of Feedwater Transients and Small Break Loss-of-Coolant Accidents in Westinghouse - Designed Operating Plants, U.S. Nuclear Regulatory Commission, January 1980.

30. NUREG-0635, Generic Evaluation of Feedwater Transients and Small Break Loss-of-Coolant Accidents in Combustion Engineering - Designed Operating Plants, U.S.

Nuclear Regulatory Commission, January 1980.

31. NRC RG 1.62, Manual Initiation of Protective Actions, Rev.1, U.S. Nuclear Regulatory Commission, June 2010.

32. NUREG-0737, Clarification of TMI Action Plan Requirements, U.S. Nuclear Regulatory Commission, November 1980.

33. 10 CFR 50.62, Requirements for Reduction of Risk from Anticipated Transient without Scram (ATWS) Events for Light-water-cooled Nuclear Power Plants, U.S.

Nuclear Regulatory Commission.

34. 10 CFR 50.63, Loss of All Alternating Current Power, U.S. Nuclear Regulatory Commission.

35. NRC RG 1.155, Station Blackout, August 1988.

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36. NUREG-0800, Standard Review Plan, BTP 5-4, Design Requirements of the Residual Heat Removal System, U.S. Nuclear Regulatory Commission, March 2007.

37. NUREG-0800 Standard Review Plan, BTP 10-1, Design Guidelines for Auxiliary Feedwater System Pump Drive and Power Supply Diversity for Pressurized Water Reactor Plants, U.S. Nuclear Regulatory Commission, March 2007.

38. NRC RG 1.97, Criteria for Accident Monitoring Instrumentation for Nuclear Power Plants, Rev. 4, U.S. Nuclear Regulatory Commission, June 2006.

39. ASME Boiler and Pressure Vessel Code,Section VIII, Rules for Construction of Pressure Vessels, The American Society of Mechanical Engineers, the 2007 Edition with 2008 Addenda.

40. 10 CFR 71, Packaging and Transportation of Radioactive Material, U.S. Nuclear Regulatory Commission.

10.4-96 Rev. 2

APR1400 DCD TIER 2 Table 10.4.1-1 Main Condenser Design Parameters Description Parameter Condenser type Single-pressure, Single-pass, Surface cooling type Number of shells 3 Design operating pressure 0.09 kg/cm2 A (2.6 in HgA)

Heat transfer rate 2,659 MW (9.1 x 109 Btu/hr)

Circulating water flow 4,580,349 L/min (1,210,000 gpm)

Circulating water inlet temperature 32.4 °C (90.3 °F)

Circulating water outlet temperature 40.8 °C (105.4 °F)

Circulating water temperature rise 8.4 °C (15.1 °F)

Hotwell storage capacity Supply maximum condensate flow for 5 minutes Tube outside diameter 25 mm (1 in.)

Tube thickness (BWG) 22 Design shell pressure Full vacuum ~ 1.054 kg/cm2G (Full vacuum ~ 15 psig)

Material Shell Carbon steel Tube Titanium Tube sheet Titanium clad Waterbox Carbon steel with lining 10.4-97 Rev. 2

APR1400 DCD TIER 2 Table 10.4.2-1 Condenser Vacuum Pump Design Parameters Condenser Vacuum Pump Quantity 4 Capacity per pump 707,920 SCCM (25 SCFM) at 0.035 kg/cm2A (1.0 in HgA)

Type Water-sealed rotary type Driver Electric motor 10.4-98 Rev. 2

APR1400 DCD TIER 2 Table 10.4.5-1 (1 of 2)

Circulating Water System Design Parameters Cooling Tower Type Mechanically induced draft Number of towers 2 Number of cells (total) 56 Design inlet wet bulb temperature 27.2 °C (81 °F) including recirculation of 1.1 °C (2 °F) (1)

Cooling tower inlet temperature 40.7 °C (105.2 °F)

Cooling tower outlet temperature 32.4 °C (90.3 °F)

Process Parameter Circulating water system flow for condenser 4,580,349 L/min (1,210,000 gpm)

Flow for TGBCCW heat exchanger 56,781 L/min (15,000 gpm)

Number of circulating water pumps 6 CW pump capacity (per each) 779,795 L/min (206,000 gpm)

System maximum design pressure 4.5 kg/cm2 G (50 psig)

System minimum design pressure 0.0 kg/cm2 G (-14.7 psig)

Materials Cooling tower and basin structure Concrete reinforced with ASTM A615 Grade 60 Conduit Concrete reinforced with ASTM A615 Grade 60 CW pipe discharge pipe ASTM A672 Grade B60 welded carbon steel with lining Circulating water pump 316 L Super austenitic stainless steel 10.4-99 Rev. 2

APR1400 DCD TIER 2 Table 10.4.5-1 (2 of 2)

Cooling water makeup system Capacity 83,279 L/min (22,000 gpm)

Number of makeup water pumps 3 Pump capacity (per each) 41,640 L/min (11,000 gpm)

Blowdown system Capacity 49,210 L/min (13,000 gpm)

Number of blowdown pumps 3 Pump capacity (per each) 24,605 L/min (6,500 gpm)

(1) The COL applicant is to determine wet bulb temperature correction factor to account for the potential interference and recirculation effects (COL 10.4(12)).

10.4-100 Rev. 2

APR1400 DCD TIER 2 Table 10.4.6-1 Condensate Polishing System Design Parameters Cation-bed ion exchanger vessel Number of vessels 7 Type Vertical Design flow rate per vessel 395 L/min (3,850 gpm)

Design pressure 242 kg/cm2 (650 psig)

Materials Carbon steel with rubber lining Mixed-bed ion exchanger vessel Number of vessels 7 Type Vertical Design flow rate per vessel 395 L/min (3,850 gpm)

Design pressure 242 kg/cm2 (650 psig)

Materials Carbon steel with rubber lining Spent resin holding tank Number of vessels 2 Type Vertical Number of vessels Carbon steel with rubber lining Resin holding tank Number of vessels 1 Type Vertical Number of vessels Carbon steel with rubber lining Resin mixing and holding tank Number of vessels 1 Type Vertical Number of vessels Carbon steel with rubber lining Resin trap Number of vessels 14 (for service) 2 (for recirculation)

Type Vertical, cylindrical Number of vessels 304 stainless steel with 304 liner 10.4-101 Rev. 2

APR1400 DCD TIER 2 Table 10.4.7-1 (1 of 3)

Major Components Design Parameters Condensate Pump Quantity 3 Type Vertical, centrifugal, can type Motor 13.2 kV/3 phase/60 Hz Rated flow 48,075 L/min (12,700 gpm)

Rated head 305 m (1,000 ft)

Main Feedwater Pump Quantity 3 Type Turbine-driven variable speed, horizontal, centrifugal Rated flow 54,131 L/min (14,300 gpm)

Rated head 610 m (2,000 ft)

Feedwater Booster Pump Quantity 3 Type Horizontal, centrifugal, single stage Motor 13.2 kV/3 phase/60 Hz Rated flow 54,131 L/min (14,300 gpm)

Rated head 294 m (963 ft) 10.4-102 Rev. 2

APR1400 DCD TIER 2 Table 10.4.7-1 (2 of 3)

Startup Feedwater Pump Quantity 1 Type Horizontal, centrifugal Motor 13.2 kV/3 phase/60 Hz Rated flow 9,085 L/min (2,400 gpm)

Rated head 854 m (2,800 ft)

Low-Pressure Feedwater Heaters Quantity 9 Type Horizontal U-tube Rated flow 722 kg/s (5,732,067 lb/hr)

Material (shell) Carbon steel Material (tube) Stainless steel High-Pressure Feedwater Heaters Quantity 6 Type Horizontal U-tube Rated flow 1,187 kg/s (9,417,714 lbm/hr)

Material (shell) Carbon steel Material (tube) Stainless steel Deaerator Quantity 1 Type Combination spray-tray, horizontal, cylindrical No. of spray valves 338 No. of trays 2,288 Material Carbon steel Deaerator Storage Tanks Quantity 2 Type Horizontal, cylindrical Capacity 1,097,012 L (289,800 gal) below normal operating level 10.4-103 Rev. 2

APR1400 DCD TIER 2 Table 10.4.7-1 (3 of 3)

Downcomer Main Feedwater Isolation Valves Quantity 4 Type Gate Size 254 mm (10 in.)

Actuator Hydraulic to open, gas spring to close Economizer Main Feedwater Isolation Valves Quantity 4 Type Gate Size 610 mm (24 in.)

Actuator Hydraulic to open, gas spring to close Downcomer Feedwater Control Valves Quantity 2 Type Globe Size 254 mm (10 in.)

Actuator Pneumatic piston Economizer Feedwater Control Valves Quantity 2 Type Globe Size 610 mm (24 in.)

Actuator Pneumatic piston 10.4-104 Rev. 2

APR1400 DCD TIER 2 Table 10.4.7-2 Condensate and Feedwater System Failure Modes and Effects Analysis Failure Component Fail Mode Effect on System Detection Main feedwater Fail closed or No safety-related effect. Valve position isolation valves fail to open on No adverse effect on integrity of the reactor indication in (MFIVs) demand or reactor coolant pressure boundary. MCR FW-V121, V122, V123, Plant can remain hot standby mode or go to V124, V131, hot shutdown.

V132, V133, V134 10.4-105 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-1 (1 of 4)

Steam Generator Blowdown System Major Component Design Parameters Flash Tank Type Vertical cylindrical Number of tanks 1 Capacity One SG EBD and the other ABD with 200 seconds Design pressure 2.06 MPa (300 psig)

Design temperature 216.6 °C (422 °F)

Operating pressure 1.72 MPa (250 psig)

Operating temperature 207.7 °C (406 °F)

Materials of construction Carbon steel Radwaste safety class RW-IIc Regenerative Heat Exchangers Type Shell and tube Number of exchangers 1 Design heat duty 14.91 x 106 W (50.9 x 106 Btu/hr)

Operating conditions Shell side Tube side Fluid SG blowdown water Condensate Operating temperature In 207.7 °C (406 °F) 53.3 °C (128 °F)

Out 57.2 °C (135 °F) 143.3 °C (291 °F)

Design flow rate 78.9 ton/hr 140.6 ton/hr (174 x 103 lb/hr) (310 x 103 lb/hr)

Design pressure 2.06 MPa (300 psig) 4.27 MPa (620 psig)

Design temperature 216.6 °C (422 °F) 216.6 °C (422 °F)

Materials of construction Carbon steel Stainless steel Radwaste safety class RW-IIc 10.4-106 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-1 (2 of 4)

Wet Lay-Up Recirculation Pump Number of pumps 2 Type Horizontal, centrifugal Design flow rate 1,627 lpm (430 gpm)

Total discharge head 112.7 m (370 ft)

Radwaste safety class RW-IIc Pre-filter Type Cartridge Number of filters 2 Design flow rate 3,255 lpm (860 gpm)

Operating pressure 1.72 MPa (250 psig)

Operating temperature 57.2 °C (135 °F)

Design pressure 2.06 MPa (300 psig)

Design temperature 121.1 °C (250 °F)

Rating 98 removal efficiency for the particles greater than 0.5 micron Material of construction Filter Stainless steel Body Stainless steel Radwaste safety class RW-IIc 10.4-107 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-1 (3 of 4)

Post-Filter Type Vertical cylindrical, cartridge Number of filters 1 Design flow rate 3,255 lpm (860 gpm)

Operating pressure 1.72 MPa (250 psig)

Operating temperature 57.2 °C (135 °F)

Design pressure 2.06 MPa (300 psig)

Design temperature 121.1 °C (250 °F)

Rating 98 removal efficiency for particles larger than 25 microns Material of construction Filter Stainless steel Body Stainless steel Radwaste safety class RW-IIc Demineralizers Number of demineralizers 2 Type Mixed bed Resin amount 6.5 m3 (230 ft3)

Design flow rate 3,255 lpm (860 gpm)

Operating pressure 1.72 MPa (250 psig)

Operating temperature 57.2 °C (135 °F)

Design pressure 2.06 MPa (300 psig)

Design temperature 121.1 °C (250 °F)

Materials of construction Stainless steel Radwaste safety class RW-IIc 10.4-108 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-1 (4 of 4)

Containment Isolation Valves Number of valves 4 Type Air-operated gate (2) / motor-operated gate (2)

Nominal valve size 200 mm (8 in.)

Design pressure 8.17 MPa (1,185 psig)

Design temperature 298.8 °C (570 °F)

Material of construction, body Stainless steel Construction Code ASME Section III, Class 2 Seismic Category I 10.4-109 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-2 Steam Generator Blowdown System Failure Modes and Effects Analysis Potential Failure Symptoms & Local Effect Method of Inherent Compensating Remarks & Other Name/No. Mode Plant Condition Including Dependent Failure Detection Provisions Effects

1. Steam generator a. Fails to close Loss of No safety-related Valve information: Redundant SG blowdown Normally open, blowdown containment on demand non-emergency impact on plant Valve position isolation valve fail-closed, isolation valve AC power indication in MCR air-operated valve SGS-AOV-005/006 Loss of normal Isolation is achieved by redundant feedwater SG blowdown isolation valve Feedwater system pipe (SGS-AOV-007/008).

break SGTR Safe shutdown

b. Fails to close LOCA No safety-related Valve information: Redundant Normally open, on demand impact on plant Valve position SG blowdown fail-closed, air-Containment boundary indication in MCR isolation valve operated valve remains intact with redundancy provided by this valve, SG lines.

2. Steam generator a. Fails to close Loss of No safety-related Valve information: Redundant SG blowdown Normally open, blowdown CV isolation on demand non-emergency impact on plant Valve position isolation valve fail-as-is, motor-valve AC power indication in MCR operated valve SGS-AOV-007/008 Loss of normal Isolation is achieved by redundant feedwater SG blowdown isolation valve Feedwater system pipe (SGS-AOV-005/006).

break SGTR Safe shutdown

b. Fails to close LOCA No safety-related Valve information: Redundant SG blowdown Normally open, on demand impact on plant Valve position isolation valve fail-as-is, motor-Containment boundary remains indication in MCR operated valve intact with redundancy provided by this valve, SG lines.

10.4-110 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-3 Codes and Standards for Equipment in the SGBS Welder Design and Qualifications Inspection and Equipment Fabrication Material and Procedures Testing Pressure vessels ASME Section ASME Sec. II ASME Sec. IX ASME Section VIII, Div. 1 or 2 VIII, Div. 1 or 2 Pumps API-610; ASME Sec. II ASME Sec. IX ASME Sec. III, API-674; Class 3 API-675; ASME Sec. VIII, Div. 1 or Div. 2 Piping and valves ANSI/ASME ASME Sec. II ASME Sec. IX ANSI/ASME B31.3 B31.3 Demineralizer ASME Sec. VIII, ASME Sec. II ASME Sec. IX ASME Sec. VIII, Div. 1 Div. 1 Filters ASME Sec. VIII, ASME Sec. II ASME Sec. IX ASME Sec. VIII, Div. 1 Div. 1 Heat exchangers TEMA STD, ASTM B359-98 ASME Sec. IX ASME Section 8th Edition; or ASME Sec. II VIII, Div. 1 or 2 ASME Sec. VIII Div. 1 or Div. 2 10.4-111 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-4 (1 of 3)

Design Basis Radioactive Source Terms for SGBD Components (1 % Fuel Defect)

Wet Layup SGBD Regenerative SGBD Pre-filter SGBD Post-filter SGBD Demineralizer SGBD Flash Tank Recirculation Pump Heat Exchanger 1)

Nuclide Ci Bq Ci Bq Ci Bq Ci Bq Ci Bq Ci Bq Br-84 - - - - 7.11E-06 2.63E+05 1.13E-06 4.17E+04 7.73E-06 2.86E+05 1.13E-06 4.17E+04 I-131 - - - - 1.03E+00 3.81E+10 4.49E-04 1.66E+07 3.07E-03 1.13E+08 4.49E-04 1.66E+07 I-132 - - - - 2.21E-03 8.19E+07 8.08E-05 2.99E+06 5.53E-04 2.05E+07 8.08E-05 2.99E+06 I-133 - - - - 1.51E-01 5.58E+09 6.03E-04 2.23E+07 4.13E-03 1.53E+08 6.03E-04 2.23E+07 I-134 - - - - 3.41E-04 1.26E+07 3.30E-05 1.22E+06 2.26E-04 8.35E+06 3.30E-05 1.22E+06 I-135 - - - - 2.41E-02 8.90E+08 3.00E-04 1.11E+07 2.06E-03 7.61E+07 3.00E-04 1.11E+07 Rb-88 - - - - 2.30E-04 8.50E+06 7.16E-05 2.65E+06 4.91E-04 1.82E+07 7.16E-05 2.65E+06 Cs-134 - - - - 2.15E+00 7.95E+10 7.11E-05 2.63E+06 4.87E-04 1.80E+07 7.11E-05 2.63E+06 Cs-136 - - - - 3.22E-02 1.19E+09 9.49E-06 3.51E+05 6.50E-05 2.41E+06 9.49E-06 3.51E+05 Cs-137 - - - - 2.68E+00 9.93E+10 8.22E-05 3.04E+06 5.63E-04 2.08E+07 8.22E-05 3.04E+06 N-16 - - - - 2.70E-09 9.98E+01 2.76E-06 1.02E+05 1.88E-05 6.96E+05 2.76E-06 1.02E+05 Na-24 - - - - 1.38E-03 5.12E+07 7.76E-06 2.87E+05 5.31E-05 1.96E+06 7.76E-06 2.87E+05 Sr-89 - - - - 8.11E-03 3.00E+08 5.97E-07 2.21E+04 4.10E-06 1.52E+05 5.97E-07 2.21E+04 Sr-90 - - - - 1.47E-03 5.43E+07 4.08E-08 1.51E+03 2.80E-07 1.04E+04 4.08E-08 1.51E+03 Sr-91 - - - - 9.11E-05 3.37E+06 7.92E-07 2.93E+04 5.42E-06 2.01E+05 7.92E-07 2.93E+04 Y-91m - - - - 2.14E-06 7.93E+04 2.16E-07 8.00E+03 1.48E-06 5.48E+04 2.16E-07 8.00E+03 Y-91 - - - - 1.29E-03 4.78E+07 8.70E-08 3.22E+03 5.96E-07 2.20E+04 8.70E-08 3.22E+03 10.4-112 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-4 (2 of 3)

Wet Layup SGBD Regenerative SGBD Pre-filter SGBD Post-filter SGBD Demineralizer SGBD Flash Tank Recirculation Pump Heat Exchanger 1)

Nuclide Ci Bq Ci Bq Ci Bq Ci Bq Ci Bq Ci Bq Y-93 - - - - 2.24E-06 8.27E+04 1.84E-08 6.81E+02 1.26E-07 4.66E+03 1.84E-08 6.81E+02 Nb-95 - - - - 9.16E-04 3.39E+07 9.38E-08 3.47E+03 6.43E-07 2.38E+04 9.38E-08 3.47E+03 Mo-99 - - - - 4.03E-02 1.49E+09 5.03E-05 1.86E+06 3.44E-04 1.27E+07 5.03E-05 1.86E+06 Tc-99m - - - - 1.83E-03 6.78E+07 2.58E-05 9.53E+05 1.77E-04 6.53E+06 2.58E-05 9.53E+05 Ru-103 - - - - 3.51E-04 1.30E+07 3.24E-08 1.20E+03 2.22E-07 8.20E+03 3.24E-08 1.20E+03 Ru-106 - - - - 4.22E-04 1.56E+07 1.38E-08 5.11E+02 9.47E-08 3.50E+03 1.38E-08 5.11E+02 Ag-110m - - - - 6.73E-03 2.49E+08 2.37E-07 8.77E+03 1.62E-06 6.01E+04 2.37E-07 8.77E+03 Te-129m - - - - 1.03E-02 3.82E+08 1.09E-06 4.03E+04 7.47E-06 2.76E+05 1.09E-06 4.03E+04 Te-129 - - - - 7.97E-06 2.95E+05 5.84E-07 2.16E+04 4.00E-06 1.48E+05 5.84E-07 2.16E+04 Te-131m - - - - 1.76E-03 6.51E+07 4.92E-06 1.82E+05 3.37E-05 1.25E+06 4.92E-06 1.82E+05 Te-131 - - - - 2.73E-06 1.01E+05 5.49E-07 2.03E+04 3.76E-06 1.39E+05 5.49E-07 2.03E+04 Te-132 - - - - 3.27E-02 1.21E+09 3.54E-05 1.31E+06 2.42E-04 8.94E+06 3.54E-05 1.31E+06 Ba-137m - - - - 1.30E-06 4.82E+04 2.57E-06 9.52E+04 1.76E-05 6.52E+05 2.57E-06 9.52E+04 Ba-140 - - - - 2.66E-03 9.85E+07 7.30E-07 2.70E+04 5.00E-06 1.85E+05 7.30E-07 2.70E+04 La-140 - - - - 1.19E-04 4.41E+06 2.49E-07 9.20E+03 1.70E-06 6.30E+04 2.49E-07 9.20E+03 Ce-141 - - - - 2.51E-04 9.29E+06 2.73E-08 1.01E+03 1.87E-07 6.90E+03 2.73E-08 1.01E+03 Ce-143 - - - - 2.92E-05 1.08E+06 7.43E-08 2.75E+03 5.09E-07 1.88E+04 7.43E-08 2.75E+03 Ce-144 - - - - 2.28E-03 8.44E+07 7.84E-08 2.90E+03 5.36E-07 1.98E+04 7.84E-08 2.90E+03 10.4-113 Rev. 2

APR1400 DCD TIER 2 Table 10.4.8-4 (3 of 3)

Wet Layup SGBD Regenerative SGBD Pre-filter SGBD Post-filter SGBD Demineralizer SGBD Flash Tank Recirculation Pump Heat Exchanger 1)

Nuclide Ci Bq Ci Bq Ci Bq Ci Bq Ci Bq Ci Bq W-187 - - - - 1.21E-04 4.49E+06 4.27E-07 1.58E+04 2.92E-06 1.08E+05 4.27E-07 1.58E+04 Np-239 - - - - 2.61E-04 9.66E+06 3.89E-07 1.44E+04 2.67E-06 9.87E+04 3.89E-07 1.44E+04 Cr-51 1.80E-02 6.65E+08 1.80E-04 6.65E+06 1.98E-02 7.32E+08 1.21E-03 4.49E+07 1.73E-05 6.39E+05 1.21E-03 4.49E+07 Mn-54 7.89E-03 2.92E+08 7.89E-05 2.92E+06 8.68E-03 3.21E+08 9.05E-02 3.35E+09 2.00E-06 7.40E+04 9.05E-02 3.35E+09 Fe-55 6.76E-03 2.50E+08 6.76E-05 2.50E+06 7.43E-03 2.75E+08 1.02E-02 3.76E+08 1.50E-06 5.55E+04 1.02E-02 3.76E+08 Fe-59 5.97E-04 2.21E+07 5.97E-06 2.21E+05 6.57E-04 2.43E+07 1.05E-01 3.88E+09 3.75E-07 1.39E+04 1.05E-01 3.88E+09 Co-58 1.28E-02 4.74E+08 1.28E-04 4.74E+06 1.41E-02 5.22E+08 3.24E-03 1.20E+08 5.74E-06 2.12E+05 3.24E-03 1.20E+08 Co-60 3.08E-03 1.14E+08 3.08E-05 1.14E+06 3.38E-03 1.25E+08 4.05E-04 1.50E+07 6.63E-07 2.45E+04 4.05E-04 1.50E+07 Zr-95 1.60E-03 5.91E+07 1.60E-05 5.91E+05 1.76E-03 6.50E+07 3.05E-04 1.13E+07 7.57E-07 2.80E+04 3.05E-04 1.13E+07 Zn-65 2.39E-03 8.83E+07 2.39E-05 8.83E+05 2.62E-03 9.71E+07 7.27E-05 2.69E+06 6.37E-07 2.36E+04 7.27E-05 2.69E+06 Sum of Fractions 1.17E-03 1.17E-05 1.96E-01 8.01E-03 7.48E-04 8.01E-03 Ai/A1i 1.22E-03 1.22E-05 3.59E-01 8.16E-03 1.75E-03 8.16E-03 Ai/A2i Radwaste Classification RW-IIc RW-IIc RW-IIc RW-IIc RW-IIc RW-IIc

1) The SGBD Regenerative Heat Exchanger is located downstream of the SGBD Flash tank. Therefore, source term of the SGBD Regenerative Heat Exchanger is assumed to be same as the SGBD Flash Tank.

10.4-114 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-1 (1 of 3)

Auxiliary Feedwater System Component Parameters Auxiliary Feedwater Pumps Quantity 2 motor driven, 2 turbine driven Type Multi-stage, horizontal, centrifugal Design Code ASME Section III, Class 3 Seismic Category I Design pressure 201.4 kg/cm2A (2,864 psia)

Design temperature 60 °C (140 °F)

Design flow rate 2,461 L/min (650 gpm) (1)

Design head at 48.9 °C (120 °F) 1,066.8 m (3,500 ft)

NPSH available (design point) at 48.9 °C (120 °F) 9.4 m (31 ft)

Maximum shutoff head at rated speed 1,356.4 m (4,450 ft)

Auxiliary Feedwater Cavitating Venturi Quantity 2 Design code ASME Section III, Class 2 Seismic Category I Design pressure 201.4 kg/cm2A (2,864 psia)

Design temperature 298.9 °C (570 °F) 2 Choked flow at inlet pressure of 122.8 kg/cm A 3,407 L/min (900 gpm)

(1,743 psia)

Operating temperature range 4.4 °C (40 °F) - 48.9 °C (120 °F)

Minimum pressure recovery at choked flow, % 85 (1) Flow rate is 2,461 L/min (650 gpm) to SG, excluding the recirculation flow for minimum flow pump protection.

10.4-115 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-1 (2 of 3)

Auxiliary Feedwater Storage Tanks Quantity 2 Design Code ASME Section III, Class 3 Seismic Category I Minimum usable volume per tank 1,514,165 L (400,000 gal)

Design pressure, internal/external 0.07 kg/cm2G (1.0 psig) /

0.035 kg/cm2G (0.5 psig)

Design temperature 60 °C (140 °F)

Auxiliary Feedwater Modulating Valves Quantity 4 Type Globe valve Size 150 mm (6 in.)

Design pressure 201.4 kg/cm2A (2,864 psia)

Design temperature 60 °C (140 °F)

Material Stainless steel Design Code ASME Section III, Class 3 Seismic Category I Auxiliary Feedwater Isolation Valves Quantity 4 Type Gate valve Size 150 mm (6 in.)

Design pressure 201.4 kg/cm2A (2,864 psia)

Design temperature 60 °C (140 °F)

Material Stainless steel Design Code ASME Section III, Class 2 Seismic Category I 10.4-116 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-1 (3 of 3)

Auxiliary Feedwater Pump Turbine Steam Isolation Valves Quantity 2 Type Globe valve Size 200 mm (8 in.)

Design pressure 97.4 kg/cm2A (1,385 psia)

Design temperature 301.7 °C (575 °F)

Material Carbon steel Design Code ASME Section III, Class 3 Seismic Category I 10.4-117 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-2 (1 of 3)

Auxiliary Feedwater System Emergency Power Sources Auxiliary Feedwater System Pump Motors Motor Train Motor-driven auxiliary feedwater pump (PP02A) motor A Motor-driven auxiliary feedwater pump (PP02B) motor B Auxiliary Feedwater System Electrically Operated Valves Valve Train AFW isolation valve V0043 A AFW isolation valve V0044 B AFW isolation valve V0045 C AFW isolation valve V0046 D AFW modulating valve V0035 A AFW modulating valve V0036 B AFW modulating valve V0037 B AFW modulating valve V0038 A Steam supply line drip leg level control valve V007 C Steam supply line drip leg level control valve V008 D Instrumentation and Controls Controls Train Motor-driven AFW pump (PP02A) start/stop A Motor-driven AFW pump (PP02B) start/stop B Turbine-driven AFW pump (PP01A) start/stop C Turbine-driven AFW pump (PP01B) start/stop D AFW isolation valve V0043 open/close A AFW isolation valve V0044 open/close B AFW isolation valve V0045 open/close C AFW isolation valve V0046 open/close D AFW modulating valve V0035 position controls A AFW modulating valve V0036 position controls B 10.4-118 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-2 (2 of 3)

Instrumentation and Controls (cont.)

Controls Train AFW modulating valve V0037 position controls B AFW modulating valve V0038 position controls A Steam isolation valve V0009 open/close C Steam isolation valve V0010 open/close D AFW pump turbine (TA01A) speed control C AFW pump turbine (TA01B) speed control D Steam supply line drip leg level control valve V0007 C open/close Steam supply line drip leg level control valve V0008 D open/close Indication and Alarms Train Motor-driven AFW pump PP02A discharge pressure A Motor-driven AFW pump PP02B discharge pressure B Turbine-driven AFW pump PP01A discharge pressure C Turbine-driven AFW pump PP01B discharge pressure D AFW isolation valves (V0043, V0045) downstream temperature and high- A temperature alarm AFW isolation valves (V0043, V0045) downstream temperature and high- C temperature alarm AFW isolation valves (V0044, V0046) downstream temperature and high- B temperature alarm AFW isolation valves (V0044, V0046) downstream temperature and high- D temperature alarm Motor-driven AFW pump PP02A suction pressure A and low-pressure alarm Motor-driven AFW pump PP02B suction pressure B and low-pressure alarm Turbine-driven AFW pump PP01A suction pressure C and low-pressure alarm Turbine-driven AFW pump PP01B suction pressure D and low-pressure alarm Turbine-driven AFW pump turbine (TA01A) inlet pressure C Turbine-driven AFW pump turbine (TA01B) inlet pressure D Motor-driven AFW pump PP02A flow A Motor-driven AFW pump PP02B flow B 10.4-119 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-2 (3 of 3)

Instrumentation and Controls (cont.)

Indication and Alarms Train Turbine-driven AFW pump PP01A flow C Turbine-driven AFW pump PP01B flow D AFWST TK01A level and low alarm A AFWST TK01A level B AFWST TK01A level C AFWST TK01A level D AFWST TK01B level and low alarm B AFWST TK01B level A AFWST TK01B level C AFWST TK01B level D Turbine-driven AFW pump turbine TA01A speed C Turbine-driven AFW pump turbine TA01B speed D Motor-driven AFW pump PP02A running status A Motor-driven AFW pump PP02B running status B Turbine-driven AFW pump PP01A running status C Turbine-driven AFW pump PP01B running status D AFW isolation valve V0043 open/close position A AFW isolation valve V0044 open/close position B AFW isolation valve V0045 open/close position C AFW isolation valve V0046 open/close position D AFW modulating valve V0035 close/modulating position A AFW modulating valve V0036 close/modulating position B AFW modulating valve V0037 close/modulating position B AFW modulating valve V0038 close/modulating position A Steam isolation valve V0009 open/close position C Steam isolation valve V0010 open/close position D Steam supply line drip leg level control valve V0007 C open/close position Steam supply line drip leg level control valve V0008 D open/close position 10.4-120 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-3 (1 of 2)

Auxiliary Feedwater System Failure Modes and Effects Analysis Symptoms and Local Effects Inherent Compensating Remarks and No. Component Failure Mode Cause Including Dependent Failures Method of Detection Provision Other Effects

1. Motor-driven Fails to start or Electrical malfunction, Loss of auxiliary feedwater Flow and discharge pressure Redundant 100 percent -

auxiliary run bearing failure flow from affected AFW line indicators in MCR or RSR capacity, turbine-driven feedwater pump to intact SG pump line AFW - PP01A/B

2. Turbine-driven Fails to start or Governor fails to control Loss of auxiliary feedwater Flow, discharge pressure, and Redundant 100 percent -

auxiliary run steam flow, trip and flow from affected AFW line speed indicators in MCR or RSR capacity, motor-driven feedwater pump throttle valve trips closed, to intact SG Steam isolation valve, trip and pump line AFW - PP02A/B steam isolation valves fail throttle valve, or governor valve to open. position indicators in MCR or RSR

3. Pump discharge Fails to open Mechanical binding, Loss of auxiliary feedwater Flow indicator in MCR or RSR Redundant 100 percent This valve is check valve corrosion flow from affected AFW line capacity, motor-driven normally AFW - V1003A/B, to intact SG or turbine-driven pump closed in line standby mode.

V1004A/B

4. Auxiliary Fails to open Mechanical binding, Loss of auxiliary feedwater Flow indicator and valve Redundant 100 percent Valves fail-feedwater corrosion flow from affected AFW line position indicator in the MCR or capacity, motor-driven open on loss of modulating to intact SG RSR or turbine-driven pump power.

valves line AFW - V0035 ~ This valve is 38 normally open in standby mode.

Fails to Electrical failure, Flow of auxiliary feedwater Flow indicator and valve Flow control to intact -

modulate or mechanical binding to intact or affected SG position indicators in MCR or SG is accomplished by close cannot be controlled utilizing RSR open/close control of the valve. AFW isolation valve.

AFW flow to affected SG may be terminated by operator action within 30 minutes to close the AFW isolation valves and/or shut off the associated AFW pumps.

10.4-121 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-3 (2 of 2)

Symptoms and Local Effects Inherent Compensating Remarks and No. Component Failure Mode Cause Including Dependent Failures Method of Detection Provision Other Effects

5. Auxiliary Fails to open Mechanical binding Loss of auxiliary feedwater Flow indication and valve Redundant 100 percent Valves feedwater flow from affected AFW line position indication in MCR or capacity, motor-driven fail-lock on isolation valves to intact SG RSR or turbine-driven pump loss of power.

AFW - V0043 ~ line This valve is 46 normally open in standby mode.

Fails to close Electrical failure, Flow of auxiliary feedwater Flow indication and valve Flow to intact SG can -

mechanical binding to intact or affected SG position indicator in MCR or be controlled by the cannot be controlled utilizing RSR flow-modulating valves.

this valve AFW flow to affected SG may be terminated by operator action within 30 minutes to close the AFW isolation valves and/or shut off the associated AFW pumps.

6. Auxiliary Fails to open Mechanical binding, Loss of auxiliary feedwater Flow indicator in MCR and RSR Redundant 100 percent This valve is feedwater corrosion flow from the affected AFW capacity, motor-driven normally isolation check line to intact SG or turbine-driven pump closed in valves line standby mode.

AFW -

V1007A/B, V1008A/B

7. Steam isolation Fails to open Solenoid failure, plugged See Item 2 See Item 2 See Item 2 -

valves air port, mechanical AT - V0009~10 binding 10.4-122 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-4 Auxiliary Feedwater System Instrumentation and Control Main Remote Control Shutdown Item Room Room Motor-driven AFW pump start/stop x x Turbine-driven AFW pump start/stop x x Individual auxiliary feedwater isolation valves open/close x x Individual valve position for AFW modulating valves x x Steam isolation bypass valves open/close x x Steam isolation valves open/close x x AFW pump turbine stop valves control x -

AFW pump turbine speed control x -

Steam supply line drip leg level control valves open/close x -

Motor-driven AFW pump discharge pressure x x Turbine-driven AFW pump discharge pressure x x Motor-driven AFW pump suction pressure and low-pressure alarm x x Turbine-driven AFW pump suction pressure and low-pressure alarm x x Turbine-driven AFW pump turbine inlet pressure x x AFW isolation valves downstream temperature and high-temperature x x alarm AFWST temperature and high-temperature and low-temperature alarm x x Motor-driven AFW pump flow x x Turbine-driven AFW pump flow x x Individual steam supply line drip leg level high-high-level alarms x x Turbine-driven AFW pump turbine speed x -

Motor-driven pump running status x x Turbine-driven AFW pump running status x -

Individual AFW modulating valves position indication x x Steam isolation bypass valves open/closed position indication x x Steam isolation valves open/closed position indication x x 10.4-123 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-5 Principal Auxiliary Feedwater System Pressure-Retaining Materials ESF Component Material Class, Grade, or Type Auxiliary Feedwater Pumps Pump outer casing SA-487 Gr. CA6NM Closure stud bolts SA-193 Gr. B7 Closure stud nuts SA-194 Gr. 2H Auxiliary Feedwater Pump Turbines Turbine casing SA-216 Gr. WCB Closure stud bolts SA-193 Gr. B7 Closure stud nuts SA-194 Gr. 2H Auxiliary Feedwater Pump Turbines Piping SA-312 Gr. TP304 SA-106 Gr. B Valves SA-216 Gr. WCB SA-105 SA-351 Gr. CF8M SA-182 Gr. F316 Fitting / flange SA-105 SA-234 Gr. WPB SA-403 Gr. WP304 SA-182 Gr. F304 Weld filler material SFA-5.1 E7016, E7018 SFA-5.4 E308-15, E308-16, E308L-15, E308L-16, E309L-16 SFA-5.9 ER308, ER309, ER308L, ER309L SFA-5.18 ER70S-2, ER70S-6 10.4-124 Rev. 2

APR1400 DCD TIER 2 Table 10.4.9-6 Steam Generator Makeup Flow Requirement Flow requirement 2,461 L/min (650 gpm) to 1 SG 10.4-125 Rev. 2

APR1400 DCD TIER 2 SEAL WATER SHEET 2 "A" WI WI NO SHEET 2 "A" SHEET 2 "B" HS CONDENSER SHELL A B C D E F G H PI PI A,B,C PRESS. HIGH PI K AIR I J CONDENSER SEPARATOR VACUUM PUMP A LS LG LAL WS NO, FC PS PDS RECIRCULATION PUMP A CONDENSER C WS A H SEAL WATER COOLER CONDENSER C WS NO HS CONDENSER SHELL PI PI A,B,C PRESS. HIGH I PI AIR CONDENSER SEPARATOR VACUUM PUMP B LS LG LAL WS NO, FC CONDENSER B WS PS PDS RECIRCULATION PUMP B CONDENSER B WS B G SEAL WATER COOLER NO HS CONDENSER SHELL PI PI A,B,C PRESS. HIGH J PI AIR CONDENSER SEPARATOR VACUUM PUMP C LS LG LAL WS NO, FC PS PDS RECIRCULATION PUMP C C F SEAL WATER COOLER CONDENSER A WS NO CONDENSER A WS HS CONDENSER SHELL PI PI A,B,C PRESS. HIGH K

PI AIR CONDENSER SEPARATOR VACUUM PUMP D LS LG LAL WS NO, FC PS PDS RECIRCULATION PUMP D D E SEAL WATER COOLER Figure 10.4.2-1 Condenser Vacuum System Flow Diagram (1 of 2) 10.4-126 Rev. 2

APR1400 DCD TIER 2 FET I

PR RX SHEET 2 PR SHEET 2 DEAERATOR PR HS HS SHEET 2 TURBINE STEAM SEAL SYSTEM SHEET 1 "B" ESF-CIAS CLOSE QIAS-P PR NO,FL SHEET 2 M HS 013 M

RCB DRAIN SUMP AREA PC LO FL 242 V1023 BOOSTER FAN DD D BI BI D TGB AB AB RCB SHEET 1 "A" Figure 10.4.2-1 Condenser Vacuum System Flow Diagram (2 of 2) 10.4-127 Rev. 2

APR1400 DCD TIER 2 PT HS I

CD NO SHEET 2 "B" HS STEAM PACKING CA EXHAUSTER SHEET 2 "B" NO CD SHEET 2 "C" STEAM PACKING EXHAUSTER BLOWER FEEDWATER PUMP TURBINE CONDENSER WS DT WS FE COMBINED COMBINED COMBINED FEEDWATER PUMP INTERMEDATE VALVE INTERMEDATE VALVE INTERMEDATE VALVE TURBINE H.P TURBINE L.P. TURBINE "A" L.P. TURBINE "B" L.P. TURBINE "C" MAIN TURBINE CONTROL VALVE COMBINED COMBINED COMBINED INTERMEDATE VALVE INTERMEDATE VALVE INTERMEDATE VALVE MAIN TURBINE STOP VALVE CONDENSER STEAM SEAL HEADER FEEDWATER PUMP TURBINE CONDENSER ZL CONDENSER STEAM EXTRACTION FO ZL CONDENSER FC HS HS M

M HS ZL FO HS M

MS SHEET 2 FO M

AS SHEET 1 "C" FO Figure 10.4.3-1 Turbine Steam Seal System Flow Diagram 10.4-128 Rev. 2

APR1400 DCD TIER 2 SHEET 2 "E" SHEET 2 "F" SHEET 2 "A" SHEET 2 "B" SHEET 2 "C" SHEET 2 "D" YARD YARD YARD CW PUMP CW PUMP CW PUMP BUILDING BUILDING BUILDING MANHOLE MANHOLE FL FL FL FL FL FL M M M M M M TE VET VET TE TE VET VET TE TE VET VET TE ISAH IAH PTI IAH ISAH ISAH IAH PTI PTI IAH ISAH ISAH IAH PTI PTI IAH ISAH PTI BLOW DOWN I I I I I I COOLING WATER SOURCE M M M M

CIRCULATING WATER PUMPS FE DOUBLE SCREEN LTIS FE M

BASIN M M M M BLOW DOWN PUMPS M M M MECHANICAL DRAFT COOLING TOWER MECHANICAL DRAFT COOLING TOWER SHEET 2 "G" Figure 10.4.5-1 Circulating Water System Flow Diagram (1 of 2) 10.4-129 Rev. 2

APR1400 DCD TIER 2 SHEET 1 "F" SHEET 1 "E" SHEET 1 "D" SHEET 1 "C" SHEET 1 "B" SHEET 1 "A" YARD TGB WH SHEET 1 "H" M M M NO NO M M NO NO M CONDENSER TUBE CONDENSER TUBE CONDENSER TUBE CONDENSER TUBE CONDENSER TUBE CONDENSER TUBE CLEANING SYSTEM CLEANING SYSTEM CLEANING SYSTEM CLEANING SYSTEM CLEANING SYSTEM CLEANING SYSTEM PI PI PI PI PI PI TEW TEW TEW TEW TEW TEW I I I I I I TI TI TI TI TI TI PDI PDI PDI PDI PDI PDI CONDENSER CONDENSER CONDENSER TEW TEW TEW TEW TEW TEW I I I I I I PI PI PI PI PI PI TI TI TI TI TI TI CONDENSER TUBE CLEANING SYSTEM CONDENSER TUBE CLEANING SYSTEM CONDENSER TUBE CLEANING SYSTEM CONDENSER TUBE CLEANING SYSTEM CONDENSER TUBE CLEANING SYSTEM CONDENSER TUBE CLEANING SYSTEM CONDENSER TUBE CLEANING SYSTEM M M CONDENSER TUBE CLEANING SYSTEM CONDENSER TUBE CLEANING SYSTEM M M CONDENSER TUBE CLEANING SYSTEM CONDENSER TUBE CLEANING SYSTEM M M CONDENSER TUBE CLEANING SYSTEM NO M M NO NO M M NO NO M M NO WH SHEET 1 "I" SHEET 1 "G" DISCHARGE MANIFOLD YARD TGB Figure 10.4.5-1 Circulating Water System Flow Diagram (2 of 2) 10.4-130 Rev. 2

APR1400 DCD TIER 2 FC 8" 8" RT 8"

SERVICE AIR FI FI 2" F SERVICE AIR NC 2" F

PSAH PI FI PSAL RESIN PI TRANSFER 4 RESIN TRANSFER PDIT SHEET 2 "D" SHEET 2 "A" SAH 4"

NO 8" 8 NC FC NO 10" 6" RT 1 1 "

" FE CEIT CEIT AITR CITR SAHR SAH SAHL SAH NC 3/4 NC FL

" FL RECYCLE PUMP 4 SC CC

" SC PH NC FC FC TEWI NO FITQ SAH FITQ PI SAH PI SAH 3/4" CONDENSATE CONDENSATE NO NC NO NC OUTLET PIPE INLET PIPE 4 3

12" FL NO 32" NO FL FL NO NO FL 12" 2

34" 1

" 2 1 2 1

RT RT MIXED BED VESSEL CATION BED VESSEL (7EA)

(7EA) PDIT PDIT FE FE 3/4" SAH SAH CITR 3/8" SAH FC FC CC FC CITR FC SAH SC FIT FIT FE FE SAH SAH FC FC 4

4 "

2 3 2 3 " " "

SHEET 2 "E" SHEET 2 "C" RESIN PI PI FITQ RESIN TRANSFER TRANSFER SLUICE WATER CT 4" 6" NO SHEET 2 "B" 6" NO 5" SHEET 1 "E" PDIT PDIT FS SAH SAH SLUICE WATER PDIT PUMP 1/2" 3/8" 1/2" SAH 1/2" 3/8" 1/2" POLISHING SUBSYSTEM SECTION Figure 10.4.6-1 Condensate Polishing System Flow Diagram (1 of 2) 10.4-131 Rev. 2

APR1400 DCD TIER 2 RESIN TRANSFER RESIN TRANSFER SLUICE WATER TO CBV SLUICE WATER TO MBV SHEET 1 "B" SHEET 1 "A" SHEET 2 "B" SHEET 1 "B" SERVICE AIR SERVICE AIR RESIN FILLING RESIN FILLING LIT LIT RESIN HOLDING RESIN MIXING AND TANK HOLDING TANK RESIN TRANSFER SHEET 1 "C"/"E" SERVICE AIR LIT SPENT RESIN HOLDING TANK (2EA)

SPENT RESIN TO OFFSITE TRANSPORT SUBSYSTEM SECTION Figure 10.4.6-1 Condensate Polishing System Flow Diagram (2 of 2) 10.4-132 Rev. 2

APR1400 DCD TIER 2 PS M M PS PS M M PS PS M M PS SHEET 2 70 70 SHEET 2 SHEET 2 70 70 SHEET 2 SHEET 2 SHEET 2 PS M M PS PS M M PS PS M M PS SHEET 2 70 70 SHEET 2 SHEET 2 70 70 SHEET 2 SHEET 2 SHEET 2 LG LT LG LT CONDENSER A CONDENSER B CONDENSER C LG LG CISAHL LT LT CISAHL LG LT LT LG CISAHL CISAHL HS HS CISAHL CISAHL HS HS S HS S TEW HS CT WS CT WS TEW S

SHEET 1 I SHEET 1 S FC WS CT FC S CT WS S TEW SHEET 1 CT SHEET 1 I CT WS FC WS SHEET 1 FC SHEET 1 I FC FC A B C B E F M PS PS PS M M M PS SHEET 2 PS M SHEET 2 PS M SHEET 2 SHEET 2 SHEET 2 SHEET 2 HS HS HS NO,FL NO,FL NO,FL HS NO,FL HS HS NO,FL NO,FL M M M M M M WS WS WS WS WS WS CONDENSATE CONDENSATE CONDENSATE OVERFLOW OVERFLOW OVERFLOW BLOCK BLOCK BLOCK WS WS WS ZL NO ZL HS ZL HS ZL ZL HS ZL NO NO LDP LDP A B C D E F HOT WELL HOT WELL HOT WELL LEVEL LO-LO LEVEL LO-LO LEVEL LO-LO VET TE TE VET VET TE IAH I I IAH IAH I HS 004 PTI PTI PTI IA I I HS I S CHEMICAL WASTE POND NC,FC CONDENSATE CONDENSATE CONDENSATE PUMP C CONDENSER PUMP A PUMP B OVERBOARD PUMP PTI PTI PTI SHEET 2 "G" I

I I FTI ZIS ZIS PTI ICKSAL I

FL HS M HS HS M FL ZIS FL M SHEET 2 "A" CONDENSATE VALVE SEAL WATER VACUUM BREAKER SEAL WATER FEED WATER PUMP A/B/C SEAL WATER Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (1 of 11) 10.4-133 Rev. 2

APR1400 DCD TIER 2 SHEET 3 "B" HS M

SHEET 1 HS FL HS S CONDENSATE PDIKCS POLISHER HS ZL HS ZL HS ZL CIKSAH M HS PS SHEET 2 FL S

M M M FL NC,FO FT LP FW HEATER 1A FE LP FW HEATER 1B LP FW HEATER 1C LEVEL HI-HI LEVEL HI-HI FT LEVEL HI-HI LP FW HEATER 2A I LP FW HEATER 2B LP FW HEATER 2C FT FE FE LEVEL HI-HI LEVEL HI-HI LEVEL HI-HI I I ETHANOLAMINE PI PI PI HYDRAZINE PS SHEET 2 NITROGEN NITROGEN NITROGEN TEW TEW TEW LO I I I LP FW HEATER 3A LP FW HEATER 3B LP FW HEATER 3C ED HE03A TURBINE GLAND SEAL SHEET 1 "D" TEW TEW TEW I I I TURBINE GLAND SEAL LP FW HEATER 2A LP FW HETER 2B LP FW HETER 2C SHEET 1 "C" PR FL M SHEET 2 HOTWELL LO LEVEL HI HOTWELL LEVEL HI-HI FE S

CONDENSATE OVERFLOW TEW TEW STORAGE SUMP TEW I I FC I

LP FW HEATER 1A LP FW HEATER 1B LP FW HEATER 1C TEW LO I

PTI CONDENSER A CONDENSER B CONDENSER C ISAL TEW TEW PI PI I

TEW I PI I

LP TBN EXHAUST HOOD HS ZL HS ZL HS ZL 218 218 219 219 M FL M FL M FL SHEET 1 "G" CONDENSER FO CONDENSER FE SD SHEET 1 MS TGB ENCLOSURE AB DD F F Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (2 of 11) 10.4-134 Rev. 2

APR1400 DCD TIER 2 ZL FL PS SHEET 4 ZL FIT IR FL TEW I

SHEET 2 "B" PIT I

SHEET 6 "A" SHEET 6 "C" DEAERATOR SHEET 6 "B" SHEET 6 "D" SHEET 9 "H" LIC IA SHEET 9 "E" DEAERATOR DEAERATOR LTI SHEET 9 "F" STORAGE TANK A STORAGE TANK B IRKCS SHEET 9 "G" AHHL CONDENSER FI TEWI I

CONDENSER WS SHEET 9 "C" SHEET 9 "D" FO SHEET 9 "A" SHEET 9 "B" WS FE FC IA FO S S WS WS TGB DII DIII MS ENCLOSURE AB SD SHEET 1 Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (3 of 11) 10.4-135 Rev. 2

APR1400 DCD TIER 2 TURBINE TRIP SCAVENGING M

STEAM 4" 4" 3" SHEET 6 "A" FL TEW FEEDWATER HEATER 7A HI-HI LEVEL I H.P FEEDWATER HEATER TRAIN A ISOLATION VALVES LO M

CD CONDENSER B WS 4" 4" WS 3" FL 6"

16" 10" MOISTURE SEPARATOR/REHEATER A 2ND STAGE REHEATER A HS 6"

16" 10" 1ST STAGE REHEATER A SCAVENGING TURBINE TRIP M

STEAM 11/2" 3" 3" SHEET 6 "C" FL TEW TURBINE LS 10" 2" 2" 2" 2" 10" 10" 2" 2" 2" 10" 10" 2" 2" 2" 10" 10" 2" 2" 2"

2" 2" 10" FEEDWATER 2"

TRIP I HEATTER 6A AH H.P FEEDWATER HI-HI LEVEL 3" HEATER TRAIN A ISOLATION VALVES LO M

CD CONDENSER A WS 1 1/2 3" WS FL 24" 6"

LCTKIS LCTKIS 1ST STAGE REHEATER MOISTURE SEPARATOR LCTKIS 2ND STAGE REHEATER DRAIN TANK A DRAIN TANK A DRAIN TANK A IAHL IAHL IAHL TEW TEW TEW I FEEDWATER I HEATER 6A I HI-HI LEVEL PS SECONDARY SAMPLE PS SECONDARY SAMPLE PS SECONDARY LOCAL COOLER RACK COOLER RACK GRAB SAMPLE COOLER RACK.

3/4 1/2 3/4 1/2 3/4" FEEDWATER HEATER FEEDWATER HEATER 7A HI-HI LEVEL BELOW 5A HI-HI LEVEL BELOW TURBINE TURBINE BELOW LOAD TURBINE LOAD 16" LOAD 10" 10" S S S DRAIN PIPE DRAIN PIPE DRAIN PIPE 10" 10" 10" 10" 18" SHEET 6 "B" SHEET 6 "D" SHEET 6 "E" FC FC FC 10" 10" 16" BELOW TURBINE LOAD T/G CONTROL SYSTEM BELOW BELOW S LO CD EMERGENCY DRAIN S LO CD EMERGENCY DRAIN TURBINE LOAD TURBINE LOAD S WS 12 TO CONDENSER C WS TO CONDENSER B MS DRAIN TANK A LO WS 12 LO WS LO CD EMERGENCY DRAIN 12" 12" HI LEVEL

" " TO CONDENSER A FO FO LO WS WS 16" 16" FO Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (4 of 11) 10.4-136 Rev. 2

APR1400 DCD TIER 2 TURBINE TRIP SCAVENGING M

STEAM 4" 4" 3" SHEET 6 "A" V1002 V1028 OR05 FL TEW FEEDWATER HEATER I H.P FEEDWATER 7B HI-HI LEVEL HEATER TRAIN B ISOLATION VALVES LO M

CD CONDENSER B WS WS 4" 4" 3" V1024 FL 6"

16" 10" MOISTURE SEPARATOR/REHEATER B 2ND STAGE REHEATER B HS 6"

16" 10" 1ST STAGE REHEATER B TURBINE TRIP SCAVENGING M 11/2" STEAM 3" 3" SHEET 6 "C" FL 10" 10" 10" 2"

10" 10" 10" 2" 2" 2" 2" 2" 2" 10" 2" 2" 2" LAH 2" 10" 2" 2" 2" 2" TURBINE 2" TEW FEEDWATER HEATTER 3" TRIP 6B HI-HI LEVEL I HP FEEDWATER HEATER TRAIN B ISOLATION VALVE LO 032 M 1 1/2" CD CONDENSER A WS WS 3"

FL 24" 6"

LCTKIS LCTKIS 1ST STAGE REHEATER MOISTURE SEPARATOR LCTKIS 2ND STAGE REHEATER 1D DRAIN TANK B DRAIN TANK B DRAIN TANK B IAHL IAHL IAHL TEW TEW TEW I

I I

PS SECONDARY SAMPLE PS SECONDARY SAMPLE PS SECONDARY LOCAL COOLER RACK COOLER RACK GRAB SAMPLE COOLER RACK.

3/4 3/4"X1/2" 1/2 3/4 1/2 3/4 FEEDWATER HEATER FEEDWATER HEATER 7B HI-HI LEVEL FEEDWATER HEATER 5B HI-HI LEVEL BELOW 6B HI-HI LEVEL TURBINE BELOW BELOW 10% TURBINE LOAD TURBINE 16" LOAD LOAD 10" 10" S S S DRAIN PIPE DRAIN PIPE DRAIN PIPE 10" 10" 10" 10" 10" 18" SHEET 6 "B" SHEET 6 "D" SHEET 6 "E" FC FC 10" 16" 10" BELOW TURBINE LOAD T/G CONTROL BELOW 10% SYSTEM S LO CD EMERGENCY DRAIN S LO CD EMERGENCY DRAIN BELOW TURBINE LOAD TO CONDENSER C WS TO CONDENSER B TURBINE LOAD LO WS WS LO WS S 12" 12" 12" 12" MS DRAIN TANK B HI LEVEL LO CD EMERGENCY DRAIN FO WS TO CONDENSER A LO WS 16" 16" FO Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (5 of 11) 10.4-137 Rev. 2

APR1400 DCD TIER 2 DRAIN 18" SHEET 4 "E" DRAIN SCAVENGING 10" SHEET 4 "D" STEAM 4"

SHEET 4 "A" SCAVENGING STEAM 3"

SHEET 4 "C" DRAIN 10" SHEET 4 "B" 12" 12" LCKIS HP FW HEATER 5A AHL LCKIS LCKIS HP FW HEATER 7A HP FW HEATER 6A DEAERATOR STORAGE 28" AHL AHL TANK HI-HI LEVEL 20" PS SENCONDARY LOCAL TEW 22" 22" GRAB SAMPLE COOLER RACK I 16" 3/4 S

CD DEAERATOR PS SENCONDARY LOCAL PS SENCONDARY LOCAL TEW 20" 20" 26" SHEET 3 "A" GRAB SAMPLE GRAB SAMPLE FC COOLER RACK COOLER RACK 28" 3/4 3/4 I HEATER 6A HEATER 5A HI-HI LEVEL HI-HI LEVEL S

20" CD DEAERATOR TEW S S 20" 20" SHEET 3 "B" FC I 16" 20" 16" 20" FC FC XE LO CD EMERGENCY DRAIN AH TO CONDENSER A LO WS WS 20" 20" FO XE XE CD EMERGENCY DRAIN CD EMERGENCY DRAIN XE AH LO LO TO CONDENSER C AH TO CONDENSER C LO WS WS LO WS WS 16" 16" 20" 20" LO CD EMERGENCY DRAIN AH WS TO CONDENSER A FO FO LO WS 20" 20" FO DRAIN DRAIN 10" 18" SHEET 5 "D" SHEET 5 "E" SCAVENGING STEAM 4" SCAVENGING SHEET 5 "A" STEAM 3"

SHEET 5 "C" DRAIN TEW 10" SHEET 5 "B" 5A HP FW HEATER 5B I

12" 12" DEAERATOR STORAGE 28" TANK HI-HI LEVEL LCIKIS LCKIS TEW PS SENCONDARY LOCAL HP FW HEATER 7B HP FW HEATER 6B GRAB SAMPLE AHL AHL COOLER RACK I 3/4 V2507 22" S

20" CD DEAERATOR TD 20" 20" 22" 26" SHEET 3 "C" FC 28" 16" PS SENCONDARY LOCAL PS SENCONDARY LOCAL TEW GRAB SAMPLE GRAB SAMPLE S COOLER RACK COOLER RACK I CD DEAERATOR 3/4 3/4 20" 20" HEATER 6B HEATER 5B SHEET 3 "D" V2505 HI-HI LEVEL HI-HI LEVEL FC V1066 20" TEW S S 16" 20" 20" I

FC FC XE LO CD EMERGENCY DRAIN 16" AH WS WS TO CONDENSER A LO 20" 20" V1077 FO XE XE XE LO CD EMERGENCY DRAIN LO CD EMERGENCY DRAIN AH AH TO CONDENSER A WS TO CONDENSER A WS WS CD EMERGENCY DRAIN LO WS 16" 16" LO LO 20" 20" AH WS TO CONDENSER A LO WS FO FO 20" 20" V1079 FO Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (6 of 11) 10.4-138 Rev. 2

APR1400 DCD TIER 2 LCIS LP FW HEATER 3A AHL CD EMERGENCY DRAIN LO LO TO CONDENSER C WS WS WS 6" 6" FO 6"

PS SECONDARY TEW LOCAL GRAB SAMPLE COOLER RACK M 3/4 I ZL S

WS WS WS FC CONDENSER A LCIS AHL LP FW HEATER 2A 10 ZL LO LO CD EMERGENCY DRAIN TO CONDENSER A WS WS WS 8" 8" V1086 FO V1087 10" TEW I

ZL S

WS WS WS FC LCIS AHL LP FW HEATER 1A 12" 12" CD EMERGENCY DRAIN LO LO TO CONDENSER A WS WS WS 8" 10" FO 10" TEW I

ZL CD CONDENSER A WS WS WS 8"

FO Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (7 of 11) 10.4-139 Rev. 2

APR1400 DCD TIER 2 LCIS LCIS L.P FEEDWATER L.P FEEDWATER HEATER 3B HEATER 3C AHL AHL ZL ZL CD EMERGENCY DRAIN LO LO CD EMERGENCY DRAIN LO LO TO CONDENSER C WS WS WS TO CONDENSER C WS WS WS 6" 6" 6" 6" FO FO 6" 6" PS SECONDARY PS SECONDARY LOCAL GRAB LOCAL GRAB SAMPLE COOLER RACK TEW TEW M SAMPLE COOLER RACK M ZL I V2514 ZL I S S WS WS WS WS WS WS FC FC CONDENSER B CONDENSER C

-CD02 -CD03 6" 6" LCIS L.P FEEDWATER LCIS L.P FEEDWATER HEATER 2B HEATER 2C AHL AHL 10" ZL 10 ZL CD EMERGENCY DRAIN LO LO CD EMERGENCY DRAIN LO LO TO CONDENSER B WS WS WS TO CONDENSER C WS WS WS 8" 8" 8" 8" FO FO 10" 10" TEW TEW ZL I ZL I S S WS WS WS WS WS WS FC FC 10" 10" LCIS L.P FEEDWATER LCIS L.P FEEDWATER HEATER 1B HEATER 1C AHL AHL 12" 12" ZL ZL 12" 12" CD EMERGENCY DRAIN LO LO CD EMERGENCY DRAIN LO LO TO CONDENSER B WS WS WS TO CONDENSER C WS WS WS 8" 10" 8" 10" FO 8"X10" FO 10" 10" TEW TEW I I ZL ZL CD CONDENSER B WS WS CD CONDENSER C WS WS 8" WS 8" WS FO FO Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (8 of 11) 10.4-140 Rev. 2

APR1400 DCD TIER 2 ZL FW PUMP MIN.

HS RECIR. DEAERATOR STORAGE TANK LO LO 12" DEAERATOR FEEDWATER PUMP SHEET 3 "E" STORAGE TANK TURBINE TA01 FO ESF-MSIS LEVEL LO-LO CONTROL SYSTEM 3" STOP HS V-TET PIT TEW PDAH TEW FIT PIT IAH ISAH I FW : FEED WATER A

T-PIT V-TET PDS PDIS I CIKSAL ISAL M PAHH HL ISAL IAH AH FL 8"

CD DEAERATOR STORAGE TANK B TURBINE-DRIVEN 30" 30" FEEDWATER PUMP A SHEET 3 "A" ST 105-D MOTOR DRIVEN 2" FEEDWATER BOOSTER PUMP A PS PS PS D ZL SHEET 10 "A" CD FW PUMP MIN.

HS RECIR. DEAERATOR LO LO STORAGE TANK FEEDWATER PUMP 12" DEAERATOR SHEET 3 "F" STORAGE TANK TURBINE TA02 FO ESF-MSIS CONTROL SYSTEM LEVEL LO-LO 3" STOP HS V-TET PIT TEW PDAH B FIT PIT IAH ISAH I TEW V-TET PDS M PDIS T-PIT I CIKSAL ISAL HL IAH AH ISAL FL 8"

CD DEAERATOR STORAGE TANK B TURBINE-DRIVEN 30" FEEDWATER PUMP B SHEET 3 "B" ST MOTOR DRIVEN 2" FEEDWATER BOOSTER PUMP B E ZL CD FW PUMP MIN.

RECIR. DEAERATOR HS STORAGE TANK LO 12" DEAERATOR FEEDWATER PUMP SHEET 3 "G" STORAGE TANK TURBINE TA03 FO ESF-MSIS CONTROL SYSTEM LEVEL LO-LO 3" STOP HS V-TET PIT TEW PDAH IAH ISAH I C TEW FIT PIT V-TET PDS PDIS T-PIT M I CIKSAL ISAL HL IAH AH ISAL FL 8"

CD DEAERATOR STORAGE TANK B TURBINE-DRIVEN 30" FEEDWATER PUMP C SHEET 3 "C" ST MOTOR DRIVEN FEEDWATER 2" BOOSTER PUMP C F

PAL 3"

PDAH HS D PS PS PIT HS ZT V-TET PDS LL LLL PDIS FIT IAH AH ISAH HL M M CIKSAL 8"

CD DEAERATOR 6"

V1026 FL FL STORAGE TANK B 1" SHEET 3 "D" 10" ST 4" MOTOR DRIVEN STARTUP FEEDWATER DEAERATOR PUMP STORAGE TANK LEVEL LO-LO ZL ESF-MSIS STOP CD MIN. RECIR.

DEAERATOR LO LO STROAGE TANK 4"

A B C D SHEET 3 "H" HS FO ZT HS M

WS CD CONDENSER 16" Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (9 of 11) 10.4-141 Rev. 2

APR1400 DCD TIER 2 32" TEW I

26" TGB AB PS FW 24" SHEET 11 "B" 1/2" 3/4 1/2" V2406 ZL TEW ZL 26" 26" I

1/2" M FL NT FW M FL NT N2 BLANKETING NT N2 BLANKETING 1" 1" V2620 V2622 V2624 V2621 V2623 V2625 PIT PS SECONDARY 32" 32" I

SAMPLE COOLER RACK HP F/W HEATER 7A HP F/W HEATER 7B TEW TEW I 24" SHEET 11 "C" I

TGB AB 32" 32" CLOSE TRAIN B CLOSE TRAIN A 1ST STAGE NORMAL 1ST STAGE NORMAL SCAVENGING VALVE SCAVENGING VALVE CLOSE TRAIN A CLOSE TRAIN B 2ND STAGE NORMAL 2ND STAGE NORMAL SCAVENGING VALVE HP F/W HEATER 6A HP F/W HEATER 6B SCAVENGING VALVE HS M FL TEW TEW I I 32" 32" HP F/W HEATER 5A HP F/W HEATER 5B 32" 32" TEW TEW 20" I I HS HS M FL M FL ZL ZL 26" 30" 26" SHEET 9 "A" Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (10 of 11) 10.4-142 Rev. 2

APR1400 DCD TIER 2 HS HS 031A 032B AF AUX FEEDWATER ESF-MSIS ZT CLOSE I IA HS MAIN FEEDWATER UA IA ISOLATION VALVES 053 AF : AUXILIARY FEEDWATER UA STEAM TGB: TURBINE GENERATOR BUILDING 131 132 GENERATOR 1 M E E 052 H H AB : AUX. BUILDING 10" 10" PC 10" 6" FL FL FC FC V1039 0 512 V1040 AB MSVH HS ZT ESF-MSIS V1050 V1051 D BI CLOSE FT I RI M HS 6" S 138A FL LT LT LT LT LT LT LT LT CF FW CHEMICAL IA FC 1111X 1114D 1114B 1115X 1114C 1115Y 1111Y 1114A INJECTION 1" 138 IRCUALH IRCUALH IUALH IUALH IUALH IUALH IRCUALH IRCUALH AB MSVH CF FW LT TT LT TT LT TT LT TT 1113D 1116 1113B 1114 1113C 1115 1113A 1113 FT IRCUALH IRCUALH IUALH IUALH IUALH IUALH IRCUALH IRCUALH HS HS D BI RICKU 121A 122B HS ZL ESF-MSIS CLOSE IA TEW ZT UA MAIN FEEDWATER 054 IA RISAL I ISOLATION VALVES 14" 121 122 UA V1037 M E E H H 055 24" 24" PC 24" 14" SHEET 10 "B" FL FL FC FC V1035 0 511 V1036 AB MSVH FT D BI RICKU 10" A

ZT TGB AB I HS HS 16" AF AUX FEEDWATER 133A 134B ESF-MSIS WS ZT CLOSE HS IA M FL I

HS MAIN FEEDWATER UA 107 IA ISOLATION VALVES 057 UA STEAM 133 134 GENERATOR 2 M E E 056 H H 10" 10" PC 10" 6' FL FL FC FC V1046 0 522 V1047 ZT AB MSVH HS ESF-MSIS CD CLEAN UP LINE V1052 V1053 I CLOSE FT D BI CONDENSER A M BE HS RI 6" S FL LT LT LT LT LT LT LT LT IA FC CF FW CHEMICAL 1121X 1124D 1124B 1125X 1124C 1125Y 1121Y 1124A INJECTION 1" 139 IRCUALH IRCUALH IUALH IUALH IUALH IUALH IRCUALH IRCUALH AB MSVH CF FW LT TT LT TT LT TT LT TT FT 1123D 1126 1123B 1124 1123C 1125 1123A 1123 IRCUALH IRCUALH IUALH IUALH IUALH IUALH IRCUALH IRCUALH RICKU HS HS D BI 123A 124B HS ZL ESF-MSIS CLOSE TEW ZT IA UA MAIN FEEDWATER IA RISAL I 058 ISOLATION VALVES 14" 123 124 UA V1044 M E E H H 059 24" 24" PC 24" 14" SHEET 10 "C" FL FL FC FC V1042 521 0521 V1043 AB MSVH FT D BI RICKU 10" A

TGB AB Figure 10.4.7-1 Condensate and Feedwater System Flow Diagram (11 of 11) 10.4-143 Rev. 2

APR1400 DCD TIER 2 HP HTR 5A LEVEL HI-HI V1204 ES SYSTEM HP HTR 5A TI HP HTR 5B 6" 015 LEVEL HI-HI 1125 V1201 PRE-FILTER S 087 DD INLET TEW LT 14" 14" SHEET 2-A 015 V1131 V1121 089 ES SYSTEM ATMOSPHERE FC M BI D D BI HP HTR 5B 2" DE 8" 6" 4"

LC LC LC LT 12" V1202 STEAM 4" PC GENERATOR 1 V1119 V1117 V1115 134 V1113 V1129 V1111 PROCESS S 088 PROCESS SAMPLING BI D 8" C M 090 SYSTEM POST FILTER V1151 FC WS WS MAIN CONDENSER A 14" SAMPLING SYSTEM SHEET 2-D V1123 14" V1203 11/2" V2965 V1205 V2967 AX AX 279 281 FT FE 019 019 LT DEMI. WATER ISAHL 028 B

HOT LEG COLD LEG VIA AFWST BACKUP V1001 1127 SUPPLY HEADER FORM CST ISAHH V1003 FI 1211 2" 011 2"

PT V1150 14" 1" V2040 6" 6" DE 087 6"

V2191 V1105 4" CIAH 2" LC PC LC 6" V1109 V2041 M 2"

V2909 V1133 V1135 V1107 FE CLEAN 003 OUT V1172 011 CHEMICAL FEED & 2" 001 WET LAY-UP 015 V1079 LC HANDLING SYSTEM IA M M RECIRC. PUMP A M

ESF-CIAS,MSIS ESF-CIAS,MSIS PP01 081 S V2187 S AFAS, DPS-AFAS CLOSE AFAS, DPS-AFAS CLOSE V1071 4" IA IA V1077 LC 761-RE/RT-104 CLEAN 028 V1011 FC DRAIN TO S OUT M CONDENSER A 007 LO LO M

005 PC 8" LO V1173 FO V1173 D CI 6"X8" 911 FC V1005 NITROGEN IA 017 SYSTEM BI D M 1"

V1163 V1161 V1007 083 S V1413 NITROGEN SUPPLY V1073 4" 11/2" D BI V1013 FC MAKEUP DEMIN.

SYSTEM 8" 2" HY-ZT V1208 V1207 CONTROL VALVE 085 531-V-0305 HCIK 085 S

FC 12" V2907 FT V1069 035 TEW CONTROL VALVE 037 V1009 ISAHL LT V-0050 CIAH 089 CIKSA TI V3009 PRE-FILTER LG 1126 016 6" PRE-FILTER 3024 SHEET 3-C INLET TEW LT SHEET 2-B 016 V3010 FE V1132 V1122 035 BI D D BI DE 2" 4" STEAM LC LC 4" PC LC LT GENERATOR 2 V1120 V1118 V1116 233 V1114 V1130 V1112 PROCESS BLOWDOWN PROCESS IA 016 M FLASH TANK SAMPLING BI D C 082 S TK01 SYSTEM POST FILTER 3509 V1072 V1022 SAMPLING SYSTEM 4"

SHEET 2-E V1124 CD SYSTEM V1012 FC V2966 DE V2968 AX AX 280 282 DEMI. WATER 018 SGBD REG. HX. HE01 B IA M 3507 HOT LEG COLD LEG VIA AFWST BACKUP 1128 V1002 SUPPLY HEADER FROM CST 084 V1004 S

FI V2908 V1074 012 4" V1014 FC DE DE 6" 6" V1106 4" LC LC HY-ZY CD SYSTEM PC 6" V1110 086 V1134 V1136 V1108 HCIK 086 S

FE 012 CHEMICAL FEED & FC 12" V1080 002 004 LC HANDLING SYSTEM WET LAY-UP 4" 11/2" RECIRC. PUMP B V1070 ESF-CIAS,MSIS ESF-CIAS,MSIS PP02 M M V1415 AFAS, DPS-AFAS CLOSE AFAS, DPS-AFAS CLOSE TI TEW IA 061 061 V1078 LC S 761-RE/RT-104 008 006 M PC 8" LO 6"X8" 921 V1006 V1010 BI D LC 1" TW V1162 V1164 V1008 033 NITROGEN SUPPLY 6"

BI D V1021 V1165 Figure 10.4.8-1 Steam Generator Blowdown System Flow Diagram (1 of 2) 10.4-144 Rev. 2

APR1400 DCD TIER 2 REG.HX 6" MAKEUP DEMIN.

SHEET 1-C SYSTEM 2" FI V1309 V1317 V1319 V1323 V1325 047 SERVICE AIR SYSTEM FI V1327 V1329 048 WET LAYUP RECIRC PUMP B 4" 6" SHEET 1-A FG 4"X6" V1333 SY55 WET LAYUP RECIRC PUMP A RESIN FILL DE 4" 1" V1049 SHEET 1-B V1030 LT V1321 V1305 3/4" PROCESS RADIATION MONITORING SYSEM 3/4" V2931 CONTROL VALVE PDI V0050 039 D SGBD 2" PROCESS MIXED BED SAMPLING SYSTEM PDI DEMINERALIZER A 3/4" DD01 043 2" PROCESS RADIATION MONITORING SYSEM TEW 3/4" 038 V2925 V2927 ISAHH V2929 IA FLASH TANK V1313 LEVEL CONTROL LY V1311 6"X4" 4" 6" PDI 050 F

V1047 V2964 V1048 049 PRE-FILTER INLET V1028 SGBD V1029 4"X6" A TEMP HI-HI PRE-FILTER A V1335 D FT01 6" AX 286 V1307 V2933 V2935 SOLID RADWASTE S SYSTEM V1050 V1031 MAIN 050 CONDENSER B 6" 4" F

V1036 V1037 6"X4" FC V1042 SGBD 3/4" POST-FILTER AX DIID FT03 283 6"

MAIN CONDENSER C AX PROCESS 284 SAMPLING SYSTEM V1043 V2963 AX WASTEWATER 285 PROCESS TREATMENT SYSTEM SAMPLING SYSTEM CHEMICAL WASTEWATER POND 4" LC 4" V2962 DEMI WATER V1044 V1520 V1045 V1524 LC 4"

V1320 V1337 V1338 FQI V1039 V1038 051 V1310 V1318 LIQUID RADWASTE SYSTEM 4" LT V1046 V1075 PDI V1032 V1033 040 4" S/G-1 WET LAYUP RECIRC.

6" LT 4" SHEET 1-D FG V1041 6"X4" V1137 V1334 SY56 RESIN FILL V2926 V2928 DE FE 1" 053 LT V1322 V1306 4"

V2932 F 6" 3/4" V1026 SGBD V1027 PRE-FILTER B FT02 S/G-2 WET LAYUP RECIRC.

LT 4" SGBD SHEET 1-E MIXED BED 4" V1138 6" DEMINERALIZER B PDI DD02 044 FE 054 V2930 V1314 V1312 V1336 AX A 287 V1308 SOLID RADWASTE SYSTEM V1035 V1034 4" LT Figure 10.4.8-1 Steam Generator Blowdown System Flow Diagram (2 of 2)

V1061 10.4-145 Rev. 2

APR1400 DCD TIER 2 Two(2)

Feedwater Nozzles Cold Side Tube sheet Two(2)

Blowdown Nozzles Hot Side Blowdown Pipe "A"

"A" Blowdown Pipe 13X 1.38 in Each Blowdown Pipe SECTION "A-A" Figure 10.4.8-2 Concept of Central Blowdown 10.4-146 Rev. 2

APR1400 DCD TIER 2 FT HS 020 015 QI 0

1 M

DEMINERALIZED WATER LT 6" TEWIS CI DII FL V1600 001 LO FE AHL V1605 TO AFWST B 6" LTI 003A IRSAHL CCW MAKEUP PIPE LTI (TRAIN A) 6" 006B AUXILIARY FEEDWATER V1607 I STORAGE TANK AFW RECIRCULATION (AFWST A) 6" SHEET 2 "E" TK01A LTI AFW RECIRCULATION 006C 6" 8" SHEET 2 "F" SHEET 2 "A" I

8" CI DI AB YARD 12" LTI 006D V2678A V2679A I

LO DII CI 12" ZS 8" SHEET 2 "B" V2642 LO LC V1623 DI CI V1628 ZS LO SHEET 1 "A" V2641 TGB AB ZS DIII DII DII CI LC RAW WATER LC 10" V1208 V2779A NC CI DII CI DI AB YARD HS 6" 016 V2778A V2780A 10" 10" 10" M FROM MAKEUP LT DEMINERALIZED WATER CI DII 6" FL TEWIS 002 6" LO AHL V1606 LTI 004B IRSAHL CCW MAKEUP (TRAIN B)

LTI 6" 005A AUXILIARY FEEDWATER V1608 I STORAGE TANK AFW RECIRCULATION (AFWST B) 6" SHEET 2 "G" TK01B LTI AFW RECIRCULATION 005C 6" 8" SHEET 2 "H" SHEET 2 "C" I

LTI 12" 005D I

LO DII CI ZS 8" SHEET 2 "D" 6"

V1624 CI DI AB YARD V2644 LO LC DII CI V2678B V2679B SHEET 1 "A" ZS SUMP LO V2643 TGB AB ZS DIII DII DII CI LC 10" V2779B CI DII CI DI AB YARD 6"

V2778B V2780B CT LC 10" SHEET 2 "A" V1627 Figure 10.4.9-1 Auxiliary Feedwater System Flow Diagram (1 of 3) 10.4-147 Rev. 2

APR1400 DCD TIER 2 AF PUMP TURBINE HS HS HS HS TA01A 037B01 037B02 045C01 045C02 FIT DPS-AFAS-1 LY ZT 037C CH.2 OPEN OUTSIDE INSIDE 037B01 037B I ESF-AFAS-1 CONTAINMENT CONTAINMENT V-TET TEWI LCIK I OPEN PIT PIT 3201 029 CI BI TEW TEW 007C 025C ISAH DPS-AFAS-1 CH.1 053A 053C SIAHL IVAH ISAL MODULATION MODE SIAH SIAH STEAM ESF-AFAS-1 037 045 GENERATROR 1 MODULATION MODE S M DOWNCOMER 6" LO DC PC 6" LO 8" FO FL 129 V1008A AUXILIARY V1004A 6" OR03A SHEET 1 "A" V2098A AFW MODULATING FE AFW ISOLATION VALVE V1002A FEEDWATER PUMP C 037 CI DI AB YARD VALVE (TURBINE DRIVEN) 1" PP01A DMA-AFAS-1 V2102A V1024A START ESF-AFAS-1 HS HS START V1023A 002A01 002A02 DPS-AFAS-1 HS LC HS DII CI HS HS DMA-AFAS-1 CH.1 START 035A01 035A02 043A01 043A02 OPEN DPS-AFAS-1 LY ZT FIT CH.2 OPEN CHEMICAL INJECTION 035A01 035A 035A ESF-AFAS-1 PIT V-TET DMA-AFAS-1 PIT LCIK I I OPEN 005A 3001 TEWI OPEN 023A 027 CI BI SIAHL IVAH DPS-AFAS-1 CH.1 ISAL ISAH MODULATION MODE M ESF-AFAS-1 035 043 S M MODULATION MODE 6" LO PC LO 8" V1003A FO FL 118 V1007A SHEET 1 "B" AUXILIARY AFW MODULATING FE AFW ISOLATION VALVE V1001A FEEDWATER PUMP A 035 VALVE (MOTOR DRIVEN) 1 PP02A OUTSIDE INSIDE CONTAINMENT CONTAINMENT FIT 6" 6" V1022A 015 I

3" V1021A LC DII CI ZS AF RECIRCULATING LO LC SHEET 1 "E" V1011A CHEMICAL INJECTION FE 015 FIT 3" 017 I

ZS AF RECIRCULATING LO LC SHEET 1 "F" V1013A DMA-AFAS-2 FE START 017 ESF-AFAS-2 HS HS HS HS HS HS DMA-AFAS-2 START 002B01 002B02 DPS-AFAS-2 036B01 036B02 044B01 044B02 OPEN CH.2 START OUTSIDE INSIDE LY ZT FIT DPS-AFAS-2 CONTAINMENT CONTAINMENT 036B01 036B 036B CH.2 OPEN PIT V-TET PIT TEWI DMA-AFAS-2 LCIK I I ESF-AFAS-2 008B 3002 024B 028 OPEN CI BI OPEN SIAHL IVAH ISAL ISAH DPS-AFAS-2 CH.1 MODULATION MODE M ESF-AFAS-2 036 044 S M MODULATION MODE 6" LO PC LO 8" FO FL 228 V1007B SHEET 1 "C" V1003B AFW MODULATING FE AFW ISOLATION VALVE V1001B AUXILIARY 036 VALVE 1" FEEDWATER PUMP B (MOTOR DRIVEN)

PP02B V1023B V1024B HS HS LC HS HS DII CI 6"

038A01 038A02 046D01 046D02 DPS-AFAS-2 LY ZT FIT CH.2 OPEN 038D CHEMICAL INJECTION 038A01 038A ESF-AFAS-2 PIT V-TET PIT I LCIK I OPEN 008D 3202 AF PUMP TEWI TEW TEW 026D CI BI TURBINE 030 054B 054D SIAHL IVAH ISAL DPS-AFAS-2 CH.1 TA01B ISAH MODULATION MODE SIAH SIAH STEAM ESF-AFAS-2 038 046 GENERATOR 2 S M MODULATION MODE DOWNCOMER 6" LO DC PC 6" LO 8" FO FL 119 V1008B AUXILIARY V1004B 6" OR03B SHEET 1 "D" V2098B FEEDWATER PUMP D AFW MODULATING FE AFW ISOLATION VALVE V1002B 038 (TURBINE DRIVEN) CI DI AB YARD VALVE PP01B 1" OUTSIDE INSIDE CONTAINMENT CONTAINMENT V1022B V2102B V1021B LC DII CI 6" 6" CHEMICAL INJECTION FIT 018 I

3" ZS AF RECIRCULATING LO LC SHEET 1 "G" V1013B V1014B FE 018 FIT 016 I

3" ZS AF RECIRCULATING LO LC SHEET 1 "H" V1011B V1012B FE 016 Figure 10.4.9-1 Auxiliary Feedwater System Flow Diagram (2 of 3) 10.4-148 Rev. 2

APR1400 DCD TIER 2 HS HS 009C01 009C02 DPS-AFAS-1 OPEN ESF-AFAS-1 OPEN PT 011C PIT 013C I I IA S

009 3007 TRIP AND M MS THROTTLE VALVE 8"

SHEET 1 E V1020A FO PRESSURE H AFW PUMP TURBINE REGULATING STEAM ISOLATION VALVE VALVE GOVERNOR 1/2" TO VALVE ATMOSPHERE DII CI AS 4" 8"

SHEET 1 "A" AFW PUMP STIS AFW PUMP TURBINE A 3035C01 TA01A PP01A HS I 007C LT 003C ISAHH DII CI CONDENSER A LO M 1" LO OR01A SI AFW PUMP TURBINE TA01A 3035C01 CONTROL PANEL 22" IA 1" 2" S 007 UA LT DII CI LO M M LO FO DII CI DRAIN HS HS 010D01 010D02 DPS-AFAS-2 OPEN ESF-AFAS-2 OPEN PT 012D PIT 014D I IA I

S 010 3008 TRIP AND M MS THROTTLE VALVE 8"

SHEET 1 E V1020B FO PRESSURE H

AFW PUMP TURBINE REGULATING STEAM ISOLATION VALVE VALVE 1/2" GOVERNOR TO 4" VALVE ATMOSPHERE DII CI AS 8"

SHEET 1 "A" AFW PUMP STIS AFW PUMP TURBINE B 3036D01 TA01B PP01B I

HS 008D LT 004D ISAHH DII CI CONDENSER A LO M LO 1"

OR01B SI 3036D01 AFW PUMP TURBINE TA01B CONTROL PANEL 22" 1"

IA 2" S 008 UA LT DII CI M LO M LO V1026B FO DII CI DRAIN Figure 10.4.9-1 Auxiliary Feedwater System Flow Diagram (3 of 3) 10.4-149 Rev. 2

APR1400 DCD TIER 2 SHEET 3 "A" ROOF LINE ROOF LINE ROOF LINE CONTAINMENT OUTSIDE INSIDE DII BI BI DII HS PTI LC PC LC CONNECTION FOR MSIV MANUAL STEAM FEIT V1016 0143 V1017 SERVICE CLOSE FAIL ICSAHL ZT ST LC V2150 M DE MS SHEET 2 FC CONDENSER V ST CONNECTION FOR MANUAL STEAM SERVICE @ FUEL HANDLING AREA DEAERATOR ST DE TURBINE STEAM SEAL SYSTEM FEEDWATER SHEET 1 "C" PUMP TURBINE CONCENTRATE TRANSFER VAPOUR SEPARATOR PRESSURE AB MAIN STEAM CONCENTRATE FTICR TGB ENCLOSURE PUMPS PI AF HS FY IA SHEET 3 "A" IP AF SHEET 3 "B" BORIC ACID CONCENTRATOR SHEET 2 "B" FC PACKAGE ROOF LINE ROOF LINE FE DIII DII PIC MSVH MAIN STEAM ANCHOR WALL ENCLOSURE SLEEVE ST ED TGB AB ST CONDENSER GAS STRIPPER SHEET 2 "C" PACKAGE ST DE DII DIII AB CB WX SHEET 2 Figure 10.4.10-1 Auxiliary Steam System Flow Diagram (1 of 3) 10.4-150 Rev. 2

APR1400 DCD TIER 2 SHEET 1 "B" IA DD HS AB MS PIPE TGB HS ENCLOSURE S

B SHEET 3 "D" FC S

FC IA DE A

IA DD AB MS PIPE TGB ST HS ENCLOSURE GLAND SEAL VENT CONDENSER S WATER COLLECTION TANK WX FC SHEET 2 SHEET 1 "C" D

PI B DD HS RAH AB CB WV SHEET 1 PR A

LGS SHEET 2 CONDENSATE SAHL RECEIVER TANK HS PR SHEET 2 S S FC IA FO IA TI DE PR HS SHEET 1 PI PR PI SHEET 1 A

PS CONDENSATE SHEET 2 RETURN PUMP A DE HS PI PI CONDENSATE RETURN PUMP B DE Figure 10.4.10-1 Auxiliary Steam System Flow Diagram (2 of 3) 10.4-151 Rev. 2

APR1400 DCD TIER 2 UNDERGROUND COMMON TUNNEL NOTE 2 NOTE 2 NOTE 2 NOTE 2 ST ST ST ST TP TP TP TP GROUND AUX. BOILER UCT BLDG UCT AREA SUMP M

SHEET 2 "D" -UA TGB UCT AUXILIARY BOILER PACKAGE AUX.

UCT BOILER BLDG.

D AUX. BOILER BLDG. SUMP TGB UCT CONDENSER CONDENSER ST ST TP TP SHEET 1 "A" Figure 10.4.10-1 Auxiliary Steam System Flow Diagram (3 of 3) 10.4-152 Rev. 2