ML18053A735
| ML18053A735 | |
| Person / Time | |
|---|---|
| Site: | Lee  |
| Issue date: | 12/19/2017 |
| From: | Donahue J Duke Energy Carolinas |
| To: | Office of New Reactors |
| Hughes B | |
| References | |
| DUKE, DUKE.SUBMISSION.15, LEE.NP, LEE.NP.1 | |
| Download: ML18053A735 (138) | |
Text
UFSAR Table of Contents 1 Introduction and General Description of the Plant 2 Site Characteristics 3 Design of Structures, Components, Equipment and Systems 4 Reactor 5 Reactor Coolant System and Connected Systems 6 Engineered Safety Features 7 Instrumentation and Controls 8 Electric Power 9 Auxiliary Systems 10 Steam and Power Conversion 11 Radioactive Waste Management 12 Radiation Protection 13 Conduct of Operation 14 Initial Test Program 15 Accident Analyses 16 Technical Specifications 17 Quality Assurance 18 Human Factors Engineering 19 Probabilistic Risk Assessment UFSAR Formatting Legend Description Original Westinghouse AP1000 DCD Revision 19 content Departures from AP1000 DCD Revision 19 content Standard FSAR content Site-specific FSAR content Linked cross-references (chapters, appendices, sections, subsections, tables, figures, and references)
10.1 Summary Description .................................................................................. 10.1-1 10.1.1 General Description .................................................................... 10.1-1 10.1.2 Protective Features .................................................................... 10.1-2 10.1.3 Combined License Information on Erosion-Corrosion Monitoring ................................................................................... 10.1-3 10.1.3.1 Erosion-Corrosion Monitoring ................................... 10.1-3 10.1.3.2 Procedures ................................................................ 10.1-4 10.1.3.3 Plant Chemistry ......................................................... 10.1-5 10.1.4 References ................................................................................. 10.1-5 10.2 Turbine-Generator ....................................................................................... 10.2-1 10.2.1 Design Basis ............................................................................... 10.2-1 10.2.1.1 Safety Design Basis .................................................. 10.2-1 10.2.1.2 Power Generation Design Basis ............................... 10.2-1 10.2.2 System Description ..................................................................... 10.2-1 10.2.2.1 Turbine-Generator Description ................................. 10.2-2 10.2.2.2 Turbine-Generator Cycle Description ....................... 10.2-2 10.2.2.3 Excitation System ..................................................... 10.2-3 10.2.2.4 Digital Electrohydraulic System Description ............. 10.2-3 10.2.2.5 Turbine Protective Trips ............................................ 10.2-6 10.2.2.6 Other Protective Systems ......................................... 10.2-9 10.2.2.7 Plant Loading and Load Following ............................ 10.2-9 10.2.2.8 Inspection and Testing Requirements ...................... 10.2-9 10.2.3 Turbine Rotor Integrity ................................................................ 10.2-9 10.2.3.1 Materials Selection .................................................... 10.2-9 10.2.3.2 Fracture Toughness ................................................ 10.2-10 10.2.3.3 High Temperature Properties .................................. 10.2-11 10.2.3.4 Turbine Rotor Design .............................................. 10.2-11 10.2.3.5 Preservice Tests and Inspections ........................... 10.2-12 10.2.3.6 Maintenance and Inspection Program Plan ............ 10.2-13 10.2.4 Evaluation ................................................................................. 10.2-14 10.2.5 Instrumentation Applications .................................................... 10.2-14 10.2.6 Combined License Information on Turbine Maintenance and Inspection ................................................................................. 10.2-15 10.2.7 References ............................................................................... 10.2-16 10.3 Main Steam Supply System ........................................................................ 10.3-1 10.3.1 Design Basis ............................................................................... 10.3-1 10.3.1.1 Safety Design Basis .................................................. 10.3-1 10.3.1.2 Power Generation Design Basis ............................... 10.3-3 10.3.2 System Description ..................................................................... 10.3-3 10.3.2.1 General Description .................................................. 10.3-3 10.3.2.2 Component Description ............................................ 10.3-4 10.3.2.3 System Operation ..................................................... 10.3-8 10.3.3 Safety Evaluation ........................................................................ 10.3-9 10.3.4 Inspection and Testing Requirements ...................................... 10.3-10 10.3.4.1 Preoperational Testing ............................................ 10.3-10 10.3.4.2 In-service Testing .................................................... 10.3-11 10-i Revision 1
10.3.5.1 Chemistry Control Basis ......................................... 10.3-11 10.3.5.2 Contaminant Ingress ............................................... 10.3-12 10.3.5.3 Condensate Polishing ............................................. 10.3-12 10.3.5.4 Chemical Addition ................................................... 10.3-12 10.3.5.5 Action Levels for Abnormal Conditions ................... 10.3-13 10.3.5.6 Layup and Heatup ................................................... 10.3-13 10.3.5.7 Chemical Analysis Basis ......................................... 10.3-13 10.3.5.8 Sampling ................................................................. 10.3-14 10.3.5.9 Condenser Inspection ............................................. 10.3-14 10.3.5.10 Conformance to Branch Technical Position MTEB 5-3 .................................................. 10.3-14 10.3.6 Steam and Feedwater System Materials .................................. 10.3-14 10.3.6.1 Fracture Toughness ................................................ 10.3-14 10.3.6.2 Material Selection and Fabrication .......................... 10.3-14 10.3.7 Combined License Information ................................................. 10.3-15 10.3.8 References ............................................................................... 10.3-15 10.4 Other Features of Steam and Power Conversion System .......................... 10.4-1 10.4.1 Main Condensers ....................................................................... 10.4-1 10.4.1.1 Design Basis ............................................................. 10.4-1 10.4.1.2 System Description ................................................... 10.4-1 10.4.1.3 Safety Evaluation ...................................................... 10.4-2 10.4.1.4 Tests and Inspections ............................................... 10.4-3 10.4.1.5 Instrumentation Applications ..................................... 10.4-3 10.4.2 Main Condenser Evacuation System ......................................... 10.4-3 10.4.2.1 Design Basis ............................................................. 10.4-3 10.4.2.2 System Description ................................................... 10.4-4 10.4.2.3 Safety Evaluation ...................................................... 10.4-5 10.4.2.4 Tests and Inspections ............................................... 10.4-5 10.4.2.5 Instrumentation Applications ..................................... 10.4-5 10.4.3 Gland Seal System ..................................................................... 10.4-5 10.4.3.1 Design Basis ............................................................. 10.4-5 10.4.3.2 System Description ................................................... 10.4-6 10.4.3.3 Safety Evaluation ...................................................... 10.4-7 10.4.3.4 Tests and Inspections ............................................... 10.4-7 10.4.3.5 Instrumentation Applications ..................................... 10.4-7 10.4.4 Turbine Bypass System ............................................................. 10.4-7 10.4.4.1 Design Basis ............................................................. 10.4-7 10.4.4.2 System Description ................................................... 10.4-8 10.4.4.3 System Operation ..................................................... 10.4-9 10.4.4.4 Safety Evaluation .................................................... 10.4-10 10.4.4.5 Inspection and Testing Requirements .................... 10.4-10 10.4.4.6 Instrumentation Applications ................................... 10.4-10 10.4.5 Circulating Water System ......................................................... 10.4-10 10.4.5.1 Design Basis ........................................................... 10.4-10 10.4.5.2 System Description ................................................. 10.4-10 10.4.5.3 Safety Evaluation .................................................... 10.4-13 10-ii Revision 1
10.4.5.5 Instrumentation Applications ................................... 10.4-14 10.4.6 Condensate Polishing System .................................................. 10.4-15 10.4.6.1 Design Basis ........................................................... 10.4-15 10.4.6.2 System Description ................................................. 10.4-15 10.4.6.3 System Operation ................................................... 10.4-16 10.4.6.4 Safety Evaluations .................................................. 10.4-16 10.4.6.5 Tests and Inspections ............................................. 10.4-16 10.4.6.6 Instrument Applications ........................................... 10.4-17 10.4.7 Condensate and Feedwater System ....................................... 10.4-17 10.4.7.1 Design Basis ........................................................... 10.4-17 10.4.7.2 System Description ................................................. 10.4-19 10.4.7.3 Safety Evaluation .................................................... 10.4-27 10.4.7.4 Tests and Inspections ............................................. 10.4-28 10.4.7.5 Instrumentation Applications ................................... 10.4-29 10.4.8 Steam Generator Blowdown System ........................................ 10.4-29 10.4.8.1 Design Basis ........................................................... 10.4-30 10.4.8.2 System Description ................................................. 10.4-31 10.4.8.3 Safety Evaluation .................................................... 10.4-35 10.4.8.4 Inspection and Testing Requirements .................... 10.4-36 10.4.9 Startup Feedwater System ....................................................... 10.4-37 10.4.9.1 Design Basis ........................................................... 10.4-37 10.4.9.2 System Description ................................................. 10.4-39 10.4.9.3 Safety Evaluation .................................................... 10.4-42 10.4.9.4 Tests and Inspections ............................................. 10.4-43 10.4.9.5 Instrumentation Applications ................................... 10.4-44 10.4.10 Auxiliary Steam System ............................................................ 10.4-44 10.4.10.1 Design Basis ........................................................... 10.4-44 10.4.10.2 System Description ................................................. 10.4-44 10.4.10.3 Safety Evaluation .................................................... 10.4-46 10.4.10.4 Tests and Inspections ............................................. 10.4-46 10.4.10.5 Instrumentation Applications ................................... 10.4-46 10.4.11 Turbine Island Chemical Feed .................................................. 10.4-46 10.4.11.1 Design Basis ........................................................... 10.4-46 10.4.11.2 System Description ................................................. 10.4-46 10.4.11.3 Safety Evaluation .................................................... 10.4-48 10.4.11.4 Tests and Inspections ............................................. 10.4-48 10.4.11.5 Instrumentation Applications ................................... 10.4-48 10.4.12 Combined License Information ................................................. 10.4-48 10.4.12.1 Circulating Water System ....................................... 10.4-48 10.4.12.2 Condensate, Feedwater and Auxiliary Steam System Chemistry Control ...................................... 10.4-48 10.4.12.3 Potable Water ......................................................... 10.4-49 10.4.13 References ............................................................................... 10.4-49 10-iii Revision 1
Steam and Power Conversion System Components .................................... 10.1-6 2-1 Turbine-Generator and Auxiliaries Design Parameters............................... 10.2-17 2-2 Turbine Overspeed Protection .................................................................... 10.2-18 2-3 Generator Protective Devices Furnished with the Voltage Regulator Package ...................................................................................................... 10.2-19 2-4 Turbine-Generator Valve Closure Times..................................................... 10.2-21 3.2-1 Main Steam Supply System Design Data .................................................. 10.3-16 3.2-2 Design Data for Main Steam Safety Valves ................................................ 10.3-17 3.2-3 Description of Main Steam and Main Feedwater Piping ............................. 10.3-18 3.2-4 Main Steam Branch Piping (2.5-Inch and Larger) Downstream of MSIV .... 10.3-19 3.3-1 Main Steam Supply System Failure Modes and Effects Analysis ............... 10.3-20 3.5-1 Guidelines for Secondary Side Water Chemistry During Power Operation..................................................................................................... 10.3-30 3.5-2 Guidelines for Steam Generator Water During Cold Shutdown/
Wet Layup ................................................................................................... 10.3-33 3.5-3 Guidelines for Steam Generator Blowdown During Heatup
(> 200°F to < 5% Power)............................................................................. 10.3-34 4.1-1 Main Condenser Design Data ..................................................................... 10.4-50 4.5-1 Design Parameters for Major Circulating Water System Components ....... 10.4-51 4.7-1 Condensate and Feedwater System Component Failure Analysis ............. 10.4-52 4.9-1 Startup Feedwater System Component Failure Analysis............................ 10.4-53 4.9-2 Nominal Component Design Data - Startup Feedwater System ................ 10.4-54 4-201 Not Used ................................................................................................... 10.4-55 4-202 Not Used ................................................................................................... 10.4-56 10-iv Revision 1
2-1 Turbine Generator Outline Drawing (Sheet 1 of 2)...................................... 10.2-22 2-1 Turbine Generator Outline Drawing (Sheet 2 of 2)...................................... 10.2-23 2-2 Emergency Trip System Functional Diagram.............................................. 10.2-24 3.2-1 Main Steam Piping and Instrumentation Diagram (Safety-Related System)
(Sheet 1 of 2) .............................................................................................. 10.3-35 3.2-1 Main Steam Piping and Instrumentation Diagram (Safety Related System)
(Sheet 2 of 2) .............................................................................................. 10.3-36 3.2-2 Main Steam System Diagram...................................................................... 10.3-37 4.3-1 Gland Seal System Piping and Instrumental Diagram ................................ 10.4-57 4.6-1 Condensate Polishing System Piping and Instrumentation Diagram (Typical) ...................................................................................................... 10.4-58 4.7-1 Condensate and Feedwater System Piping and Instrumentation Diagram (Sheet 1 of 4) .............................................................................................. 10.4-59 4.7-1 Condensate and Feedwater System Piping and Instrumentation Diagram (Sheet 2 of 4) .............................................................................................. 10.4-60 4.7-1 Condensate and Feedwater System Piping and Instrumentation Diagram (Sheet 3 of 4) .............................................................................................. 10.4-61 4.7-1 Condensate and Feedwater System Piping and Instrumentation Diagram (Sheet 4 of 4) .............................................................................................. 10.4-62 4.8-1 Steam Generator Blowdown System Piping and Instrumentation Diagram ...................................................................................................... 10.4-63 4-201 Piping and Instrumentation Drawing, Circulating Water System................. 10.4-64 10-v Revision 1
steam and power conversion system is designed to remove heat energy from the reactor coolant em via the two steam generators and to convert it to electrical power in the turbine-generator.
main condenser deaerates the condensate and transfers heat that is unusable in the cycle to the ulating water system. The regenerative turbine cycle heats the feedwater, and the main feedwater em returns it to the steam generators.
le 10.1-1 gives the significant design and performance data for the major system components.
re 10.1-1 shows the rated heat balance for the turbine cycle process.
1.1 General Description steam generated in the two steam generators is supplied to the high-pressure turbine by the n steam system. After expansion through the high-pressure turbine, the steam passes through two moisture separator/reheaters (MSRs) and is then admitted to the three low-pressure turbines.
ortion of the steam is extracted from the high- and low-pressure turbines for seven stages of water heating.
aust steam from the low-pressure turbines is condensed and deaerated in the main condenser.
heat rejected in the main condenser is removed by the circulating water system (CWS). The densate pumps take suction from the condenser hotwell and deliver the condensate through four es of low-pressure closed feedwater heaters to the fifth stage, open deaerating heater.
densate then flows to the suction of the steam generator feedwater booster pump and is harged to the suction of the main feedwater pump. The steam generator feedwater pumps harge the feedwater through two stages of high-pressure feedwater heating to the two steam erators.
turbine-generator has an output of approximately 1,199,500 kW for the Westinghouse nuclear m supply system (NSSS) thermal output of 3,415 MWt. The principal turbine-generator ditions for the turbine rating are listed in Table 10.1-1. The rated system conditions for the NSSS listed in Table 10.1-1. The systems of the turbine cycle have been designed to meet the imum expected turbine generator conditions.
rumentation systems are designed for the normal operating conditions of the steam and densate systems. The systems are designed for safe and reliable control and incorporate uirements for performance calculations and periodic heat balances. Instrumentation for the ondary cycle is also provided to meet recommendations by the turbine supplier and SI/ASME TDP-2-1985, "Recommended Practices for the Prevention of Water Damage to Steam bines Used for Electric Power Generation." Design features for prevention of water hammer in the m generator are described in Subsection 5.4.2.2. Continuous sampling instrumentation and grab ple points are provided so that water chemistry in the secondary cycle can be maintained within eptable limits, as required by the nuclear steam system and turbine suppliers (see sections 9.3.4 and 10.3.5). Condenser tube/tube sheet leakage can be identified and isolated by g condenser conductivity sampling provisions.
eria and bases for safety-related instrumentation for main steam isolation are discussed in tion 7.3.
10.1-1 Revision 1
e event of turbine trip, steam is bypassed to the condenser via the turbine bypass valves and, if uired, to the atmosphere via the atmospheric relief valves. Steam relief permits energy removal the reactor coolant system. Load rejection capability is discussed in Subsections 10.3.2.3.1 15.2.2.
rpressure Protection ng-loaded safety valves are provided on both main steam lines, in accordance with the ASME e,Section III. The pressure relief capacity of the safety valves is such that the energy generated e high-flux reactor trip setting can be dissipated through this system. The design capacity of the n steam safety valves equals or exceeds 105 percent of the NSSS design steam flow at an umulation pressure not exceeding 110 percent of the main steam system design pressure.
rpressure protection for the main steam lines is a safety-related function. The main steam safety es are described in Subsection 10.3.2.
ddition, the shell sides of the feedwater heaters and the moisture separator/reheaters are ided with overpressure protection in accordance with ASME Code,Section VIII, Division 1, or ivalent standards.
s of Main Feedwater Flow Protection startup feedwater pumps provide feedwater to the steam generators for the removal of sensible decay heat whenever main feedwater flow is interrupted, including loss of offsite electric power.
system is described in Subsection 10.4.9.
bine Overspeed Protection ing normal operations, turbine overspeed protection is provided by the action of the redundant troller of the electro-hydraulic control system. Additional protection is provided by an overspeed ection system, which continuously monitors critical turbine parameters on a three-channel basis.
h of the channels is independently testable under load with overspeed protection during testing ided by the channels not being tested. If turbine speed exceeds 110 percent of rated speed, the tronic trip system causes steam supply valves to close, tripping the unit. This system is described ubsection 10.2.2.5.
bine Missile Protection bine rotor integrity minimizes the probability of generating turbine missiles and is discussed in section 10.2.3. Turbine missiles are addressed in Subsection 3.5.1.3. The favorable orientation e turbine-generator directs potential missiles away from safety-related equipment and structures.
ioactivity Protection er normal operating conditions, there are no significant radioactive contaminants present in the m and power conversion system. However, it is possible for the system to become contaminated ugh steam generator tube leakage. In this event, radiological monitoring of the main condenser emoval system, the steam generator blowdown system, and the main steam lines will detect tamination and alarm high radioactivity concentrations. A discussion of the radiological aspects of ary-to-secondary system leakage and limiting conditions for operation is contained in pter 11. The steam generator blowdown system described in Subsection 10.4.8 and the densate polishing system described in Subsection 10.4.6 serve to limit the radioactivity level in secondary cycle.
10.1-2 Revision 1
sidered in the evaluation of erosion-corrosion include system piping and component configuration geometry, water chemistry, piping and component material, fluid temperature, and fluid velocity.
bon steel with only carbon and manganese alloying agents is not used for applications subject to ificant erosion-corrosion.
ddition to material selection, pipe size and layout may also be used to minimize the potential for ion-corrosion in systems containing water or two-phase flow. The secondary side water mistry (see Subsection 10.3.5) uses a volatile pH adjustment chemical to maintain a noncorrosive ironment. Steam and power conversion systems are designed to facilitate inspection and erosion-osion monitoring programs.
ndustry-sponsored computer program developed for nuclear and fossil power plant applications sed to evaluate the rate of wall thinning for components and piping potentially susceptible to ion-corrosion. The engineering models are the result of research and development in the fields aterial science, water chemistry, fluid mechanics, and corrosion engineering. The program ntifies the benefits of piping material, system layout, and sizing considerations used to reduce osion rates.
1.3 Combined License Information on Erosion-Corrosion Monitoring 1.3.1 Erosion-Corrosion Monitoring flow accelerated corrosion (FAC) monitoring program analyzes, inspects, monitors and trends e nuclear power plant components that are potentially susceptible to erosion-corrosion damage h as carbon steel components that carry wet steam. In addition, the FAC monitoring program siders the information of Generic Letter 89-08, EPRI NSAC-202L-R3, and industry operating erience. The program requires a grid layout for obtaining consistent pipe thickness surements when using Ultrasonic Test Techniques. The FAC program obtains actual thickness surements for highly susceptible FAC locations for new lines as defined in EPRI NSAC-202L-R3 ference 201). At a minimum, a CHECWORKS type Pass 1 analysis is used for low and highly ceptible FAC locations and a CHECWORKS type Pass 2 analysis is used for highly susceptible locations when Pass 1 analysis results warrant. To determine wear of piping and components re operating conditions are inconsistent or unknown, the guidance provided in EPRI NSAC-202L sed to determine wear rates.
1.3.1.1 Analysis ndustry-sponsored program is used to identify the most susceptible components and to evaluate rate of wall thinning for components and piping potentially susceptible to FAC. Each susceptible ponent is tracked in a database and is inspected, based on susceptibility. Analytical methods ze the results of plant-specific inspection data to develop plant-specific correction factors. This ection accounts for uncertainties in plant data, and for systematic discrepancies caused by plant ration. For each piping component, the analytical method predicts the wear rate, and the mated time until it must be re-inspected, repaired, or replaced. Carbon steel piping (ASME III and
.1) that is used for single or multi-phase high temperature flow is the most susceptible to erosion-osion damage and receives the most critical analysis.
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stry experience is used to update the program by identifying susceptible components or piping ures.
1.3.1.3 Inspections l thickness measurements establish the extent of wear in a given component, provide data to help luate trends, and provide data to refine the predictive model. Components are inspected for wear g ultrasonic techniques (UT), radiography techniques (RT), or by visual observation. The initial ections are used as a baseline for later inspections. Each subsequent inspection determines the r rate for the piping and components and the need for inspection frequency adjustment for those ponents.
1.3.1.4 Training and Engineering Judgement FAC program is administered by both trained and experienced personnel. Task specific training rovided for plant personnel that implement the monitoring program. Specific non-destructive mination (NDE) is carried out by personnel qualified in the given NDE method. Inspection data is lyzed by engineers or other experienced personnel to determine the overall effect on the system omponent.
1.3.1.5 Long-Term Strategy strategy focuses on reducing wear rates and performing inspections on the most susceptible tions.
1.3.2 Procedures 1.3.2.1 Generic Plant Procedure FAC monitoring program is governed by procedure. This procedure contains the following ments:
A requirement to monitor and control FAC.
Identification of the tasks to be performed and associated responsibilities.
Identification of the position that has overall responsibility for the FAC monitoring program at each plant.
Communication requirements between the coordinator and other departments that have responsibility for performing support tasks.
Quality Assurance requirements.
Identification of long-term goals and strategies for reducing high FAC wear rates.
A method for evaluating plant performance against long-term goals.
1.3.2.2 Implementing Procedures FAC implementing procedures provide guidelines for controlling the major tasks. The plant edures for major tasks are as follows:
10.1-4 Revision 1
Selecting and scheduling components for initial inspection.
Performing inspections.
Evaluating degraded components.
Repairing and replacing components when necessary.
Selecting and scheduling locations for the follow-on inspections.
Collection and storage of inspections records.
1.3.3 Plant Chemistry responsibility for system chemistry is under the purview of the plant chemistry section. The plant mistry section specifies chemical addition in accordance with plant procedures.
1.4 References
. EPRI NSAC-202L-R3, Recommendations for an Effective Flow-Accelerated Corrosion Program (NSAC-202L-R3), Electric Power Research Institute (EPRI) Technical Report 1011838, Palo Alto, CA, 2006.
10.1-5 Revision 1
Performance Characteristics for Major Steam and Power Conversion System Components clear Steam Supply System, Full Power Operation ed NSSS power (MWt) 3415 am generator outlet pressure (psig) 821 am generator inlet feedwater temperature (°F) 440 ximum steam generator separator outlet steam moisture (%) 0.25 am generator outlet steam temperature (°F) 523 antity of steam generators 2 w rate per steam generator (lb/hr) 7.49 x 106 bine minal output (kW) 1,199,500 bine type Tandem-compound 6-flow, 52 in. last-stage blade bine elements 1 high pressure 3 low pressure erating speed (rpm) 1800 10.1-6 Revision 1
WLS 1&2 - UFSAR Figure 10.1-1 Rated Heat Balance 10.1-7 Revision 1
2.1 Design Basis 2.1.1 Safety Design Basis turbine-generator serves no safety-related function and therefore has no nuclear safety design is.
2.1.2 Power Generation Design Basis following is a list of the principal design features:
The turbine-generator is designed for baseload operation and for load follow operation.
The main turbine system (MTS) is designed for electric power production consistent with the capability of the reactor and the reactor coolant system.
The turbine-generator is designed to trip automatically under abnormal conditions.
The system is designed to provide proper drainage of related piping and components to prevent water induction into the main turbine.
The main turbine system satisfies the recommendations of Nuclear Regulatory Commission Branch Technical Position ASB 3-1 as related to breaks in high-energy and moderate-energy piping systems outside containment. The main turbine system is considered a high-energy system.
The system provides extraction steam for seven stages of regenerative feedwater heating.
2.2 System Description turbine-generator is designated as a TC6F 52-inch last-stage blade unit consisting of turbines, a erator, external moisture separator/reheaters, controls, and auxiliary subsystems. (See re 10.2-1.) The major design parameters of the turbine-generator and auxiliaries are presented able 10.2-1. The piping and instrumentation diagram containing the stop, control, intercept, and eat valves is shown in Figure 10.3.2-2.
turbine-generator and associated piping, valves, and controls are located completely within the ine building. There are no safety-related systems or components located within the turbine ding. The probability of destructive overspeed condition and missile generation, assuming the mmended inspection and test frequencies, is less than 1 x 10-5 per year. In addition, orientation e turbine-generator is such that a high-energy missile would be directed at a 90 degree angle y from safety-related structures, systems, or components. Failure of turbine-generator equipment s not preclude safe shutdown of the reactor. The turbine-generator components and rumentation associated with turbine-generator overspeed protection are accessible under rating conditions. Subsection 3.5.1.3 addresses the probability of generation of a turbine missile AP1000 plants in a side-by-side configuration.
operational and startup tests provide guidance to operations personnel to ensure the proper rability of the turbine generator system.
10.2-1 Revision 1
6F 52-inch LSB). The high-pressure turbine element includes one double-flow, high-pressure ine. The low-pressure turbine elements include three double-flow, low-pressure turbines and two rnal moisture separator/reheaters (MSRs) with two stages of reheating. The single direct-driven erator is hydrogen gas and de-ionized water cooled and rated at 1375 MVA at 0.90 PF. Other ted system components include a complete turbine-generator bearing lubrication oil system, a al electrohydraulic (D-EHC) control system with supervisory instrumentation, a turbine steam ling system (refer to Subsection 10.4.3), overspeed protective devices, turning gear, a stator ling water system, a generator hydrogen and seal oil system, a generator CO2 system, a rectifier ion, an excitation transformer, and a voltage regulator.
turbine-generator foundation is a spring-mounted support system. A spring-mounted turbine-erator provides a low-tuned, turbine-pedestal foundation. The springs dynamically isolate the ine-generator deck from the remainder of the structure in the range of operating frequencies, thus wing for an integrated structure below the turbine deck. The condenser is supported on springs attached rigidly to the low-pressure turbine exhausts.
foundation design consists of a reinforced concrete deck mounted on springs and supported on ructural steel frame that forms an integral part of the turbine building structural system. The lateral ing under the turbine-generator deck also serves to brace the building frame. This "integrated" ign reduces the bracing and number of columns required in the building. Additionally, the spring-nted design allows for dynamic uncoupling of the turbine-generator foundation from the structure. The spring mounted support system is much less site dependent than other turbine estal designs, since the soil structure is decoupled from turbine dynamic effects. The turbine-erator foundation consists of a concrete table top while the substructure consists of supporting ms and columns. The structure below the springs is designed independent of vibration siderations. The turbine-generator foundation and equipment anchorage are designed to the e seismic design requirement as the turbine building. See Subsection 3.7.2.8 for additional rmation on seismic design requirements. See Subsection 10.4.1.2 for a description of the support e condenser.
2.2.2 Turbine-Generator Cycle Description am from each of two steam generators enters the high-pressure turbine through four stop valves four governing control valves; each stop valve is in series with one control valve. Crossties are ided upstream of the turbine stop valves to provide pressure equalization with one or more stop es closed. After expanding through the high-pressure turbine, exhaust steam flows through two rnal moisture separator/reheater vessels. The external moisture separators reduce the moisture tent of the high-pressure exhaust steam from approximately 10 to 13 percent at the rated load to percent moisture or less.
AP1000 employs a 2 stage reheater, of which the first stage reheater uses the extraction steam the high pressure turbine and the second reheater uses a portion of the main steam supply to eat the steam to superheated conditions. The reheated steam flows through separate reheat stop intercept valves in each of six reheat steam lines leading to the inlets of the three low-pressure ines. Turbine steam extraction connections are provided for seven stages of feedwater heating.
am from the extraction points of the high-pressure turbine is supplied to high-pressure feedwater ter No. 6 and No. 7. The high-pressure turbine exhaust also supplies steam to the deaerating water heater. The low-pressure turbine third, fourth, fifth, and sixth extraction points supply m to the low-pressure feedwater heaters No. 4, 3, 2, and 1, respectively.
10.2-2 Revision 1
ugh drainage holes drilled through the nozzle diaphragms. A few grooves are provided on the ting blades near the last stage of the low-pressure turbine to capture the large water droplets of wet steam and to enhance the moisture removal effectiveness.
external moisture separator/reheaters use multiple vane chevron banks (shell side) for moisture oval. The moisture removed by the external moisture separator/reheaters drain to a moisture arator drain tank and is pumped to the deaerator.
densed steam in the reheater (tube side) is drained to the reheater drain tank, flows into the shell of the No. 7 feedwater heater, and cascades to the No. 6 feedwater heater.
2.2.3 Excitation System excitation system is a static excitation system using the thyristor full bridge rectifier.
itation power used in this system is fed from the generator main lead through the excitation sformer. The excitation transformer is of outdoor use type, and it will be located adjacent to the ine building. After stepping down the voltage at the excitation transformer, ac current from the erator main lead will be rectified by the thyristor rectifier.
voltage control system uses the digital controller for major control function. The system has two ter controller configurations (i.e., one is for normal operation and the other is stand-by). The age setting range of the automatic voltage regulator is +/-10% of the generator rated voltage; ever, the operating range of the generator is +/-5% of the generator rated voltage. The excitation em will include a power system stabilizer. The standard type power system stabilizer is single t type, using the generator output power deviation as the input signal.
2.2.4 Digital Electrohydraulic System Description turbine-generator is equipped with a digital electrohydraulic (D-EHC) system that combines the abilities of redundant processors and high-pressure hydraulics to regulate steam flow through the ine. The control system provides the functions of speed control, load control, overspeed ection, and automatic turbine control (ATC), which may be used, either for control or for ervisory purposes, at the option of the plant operator.
D-EHC system employs three electric speed inputs whose signals are processed in redundant essors. Valve opening actuation is provided by a hydraulic system that is independent of the ring lubrication system. Valve closing actuation is provided by springs and steam forces upon uction or relief of fluid pressure. The system is designed so that loss of fluid pressure, for any on, leads to valve closing and consequent turbine trip.
am valves are provided in an in-line configuration. The stop valves are tripped by the overspeed system; the control valves are modulated by the control system and are also actuated by the trip em.
2.2.4.1 Speed Control (Normal Turbine Operation) ee active speed sensors provide signals for the turbine rotation rate. These are the obes A,B,C shown on Figure 10.2-2. The 3 signals are input to 3 separate speed detection ules each located on three separate I/O branches. Each of these modules has an onboard roprocessor which converts the sensor input to a turbine rpm value.
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ction module (receiving one branch of the signal) does not affect the function of the remaining speed detection modules from receiving their signals.
speed control function of the turbine control and protection systems redundant controller ides speed control and acceleration functions for normal turbine operation. The speed error al is derived by comparing the desired setpoint speed with the actual speed of the turbine. This r drives an algorithm that positions the control valves at the desired setpoint. Acceleration rates also be entered by the operator or calculated by the control system in the auto start-up mode. A re of one speed input generates an alarm. Failure of two or more speed inputs also generates an m and trips the turbine. In addition, if both of the Ovation controllers fail or power to them is lost, turbine will trip. The design is fail safe; the system is designed to deenergize to trip.
speed control function exists in triplicate channels, which include the load (frequency) control tion if the main generator breaker is closed. If one channel fails, the lower signal of the remaining channels is selected by the median value gate (MVG) and fed into the valve positioning control tion.
control systems operator automatic (OA) controller provides the speed control function. At 101%
ated speed, the control valves and intercept valves begin to close, but do not trip the turbine.
speed control function is designed to prevent the operator from holding the turbine speed at a ring critical or blade resonance point.
2.2.4.2 Load Control load control function of the turbine control and protection systems OA controller develops als that are used to regulate unit load. Signal outputs are based on a proper combination of the ed error and megawatt setpoints to generate a flow demand to the control valves.
en the first-stage pressure and megawatt control loops are out of service, steam flow is not trolled by feedback, but rather by a characterization of maximum nozzle flow (at rated pressure temperature) per valve versus control valve position. Under this condition, the turbine operator uests a certain megawatt load target. The control system calculates the required flow demand to st the steam flow from the steam generators supplied to the turbine.
2.2.4.3 Valve Control flow of the main steam entering the high-pressure turbine is controlled by four stop valves and control valves. The function of the stop valves is to shut off the steam flow to the turbine when uired. The stop valves are closed by actuation of the overspeed trip system. This system is pendent of the control system. Stop valves No. 1 and No. 3 are controlled by a hydraulic actuator hat the stop valve is either fully open or fully closed. The No. 2 and No. 4 stop valves each has a ass valve, which is controlled by an electro-hydraulic servo actuator for control valve warming.
turbine control valves are positioned by electrohydraulic servo actuators in response to signals their respective servo modules. The servo module signal positions the control valves for wide-ge speed control through the normal turbine operating range, and for load control after the ine-generator unit is synchronized.
reheat stop and intercept valves, located in the hot reheat lines at the inlet to the low-pressure ines, control steam flow to the low-pressure turbines. During normal operation of the turbine, the 10.2-4 Revision 1
eat stop and intercept valves close completely on a turbine trip.
control, stop, reheat stop, and intercept valves have fast-acting valves connected to the raulic portion of their respective valve actuators. Opening a fast-acting valve causes the nected control or stop valve to rapidly close. The fast-acting valve actuators are connected to trip ders and open in response to loss of pressure in the connected trip header. The control and rcept fast-acting valves are connected to the relay trip header, and reheat stop dump valves are nected to the auto stop emergency trip header. Valve closure times are provided in Table 10.2-4.
2.2.4.4 Power/Load Unbalance (Main Breaker Closed) ower/load unbalance circuit initiates fast closing intercept valve action under load rejection ditions that might lead to rapid rotor acceleration and consequent overspeed.
d unbalance operates when load is equal to or greater than 40% of full load and reheat pressure eeds the corresponding expected megawatts. Cold reheat pressure is used as a measure of er. Generator current is used as a measure of load to provide discrimination between loss of load dents and occurrences of electric system faults. This causes all intercept valves to close quickly er fast-acting solenoid valve action.
en the circuitry detects a power/load unbalance condition, an intercept valve trigger function is ided, which initiates closure of the intercept valves by energizing fast-acting solenoid valves on intercept valve actuators. One-half of the intercept valves are controlling and are equipped with rvo valve. The controlling intercept valves allow recovery from a partial load rejection by ing down the bypass system. Simultaneously, the load reference signal is set to zero. Should the dition disappear quickly, the power/load unbalance circuitry resets automatically and the load rence signal is recalculated based on the new calculation of flow demand.
2.2.4.5 Overspeed Protection turbine control and protection system has four functions to protect the turbine against overspeed.
first is the overspeed protection system (OSP), which at 101% of rated speed, begins to close control and intercept valves as discussed in Subsection 10.2.2.4.1. The second and third are the
% and 111% overspeed trip functions also discussed in Subsection 10.2.2.5. The fourth function e partial load unbalance discussed in Subsection 10.2.2.4.4.
undancy is built into the overspeed protection system. The failure of a single valve will not ble the trip functions. The overspeed protection components are designed to fail in a safe ition. Loss of the hydraulic pressure in the emergency trip system causes a turbine trip.
refore, damage to the overspeed protection components, results in the closure of the valves and interruption of steam flow to the turbine.
ck closure of the steam valves prevents turbine overspeed. Valve closing times are given in le 10.2-4.
2.2.4.6 Automatic Turbine Control omatic turbine control provides safe and proper startup and loading of the turbine generator. The licable limits and precautions are monitored by the automatic turbine control programs even if the matic turbine control mode has not been selected by the operator. When the operator selects matic turbine control, the programs both monitor and control the turbine. The D-EHC controller 10.2-5 Revision 1
automatic turbine control is capable of automatically:
Changing speed reference Changing acceleration rates Generating speed holds Changing load rates Generating load holds thermal stresses in the rotor are calculated by the automatic turbine controls programs based on al turbine steam and metal temperatures as measured by thermocouples or other temperature suring devices. Once the thermal stress (or strain) is calculated, it is compared with the allowable e, and the difference is used as the index of the permissible first stage temperature variation.
permissible temperature variation is translated in the computer program as an allowable speed ad or rate of change of speed or load.
es of some parameters are stored for use in the prediction of their future values or rates of nge, which are used to initiate corrective measures before alarm or trip points are reached.
rotor stress (or strain) calculations used in the program, and its decision-making counterpart are main controlling sections. They allow the unit to roll with relatively high acceleration until the cipated value of stress predicts that limiting values are about to be reached. Then a lower eleration value is selected and, if the condition persists, a speed hold is generated. The same osophy is used on load control in order to maintain positive control of the loading rates.
automatic turbine controls programs are stored and executed in redundant distributed essing units, which contain the rotor stress programs and the automatic turbine controls logic grams. Once the turbine is reset, the automatic turbine controls programs are capable of rolling turbine from turning gear to synchronous speed.
e the turbine-generator reaches synchronous speed, the startup or speed control phase of matic turbine control is completed and no further action is taken by the programs. Upon closing main generator breaker, the D-EHC automatically picks up approximately 5 percent of rated load revent motoring of the generator. At this time, the D-EHC is in load control logic and automatically rts control to the operator mode.
operator can also select the automatic turbine control mode. The automatic turbine control cts the loading rate (based on turbine temperature) and allows load changes until an alarm dition occurs. If the operating parameters being monitored (including rotor stress) exceed their ociated alarm limit, a load hold is generated in conjunction with the appropriate alarm message.
D-EHC generates the load hold by ignoring any further load increase or decrease until the alarm dition is cleared or until the operator overrides the alarm condition.
operator may remove the turbine-generator from automatic turbine control. This action places turbine control in operator auto mode and the automatic turbine control in a supervisory capacity.
2.2.5 Turbine Protective Trips bine protective trips, when initiated, cause tripping of the main stop, control, intercept, and reheat valves. The protective trips are:
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Turbine overspeed Thrust bearing wear Remote trip that accepts external trips escription of the trip system for turbine overspeed is provided below.
2.2.5.1 Overspeed Trip System purpose of the electrical overspeed trip system is to detect undesirable operating conditions of turbine-generator, take appropriate trip actions, and provide information to the operator about the cted conditions and the corrective actions. In addition, means are provided for testing emergency equipment and circuits.
system hydraulic manifold configuration permits on line testing with continuous protection rded during the test sequence.
trip system includes an online testable hydraulic manifold, speed sensors, trip relays, pendent power supplies, and a test graphic. These items and the function of the overspeed trips described in the following three subsystems.
2.2.5.2 Emergency Trip Block/Master Trip Device emergency trip supply pressure is established when the master trip solenoid valves are closed.
valves are arranged in two channels for testing purposes. Both valves in a channel will open to that channel. Both channels must trip before the emergency trip supply pressure collapses to e the turbine steam inlet valves. Each tripping function of the electrical emergency trip system be individually tested from the operator/test graphic without tripping the turbine by separately ing each channel of the appropriate trip function. The solenoid valves may be individually tested.
emergency trip system opens a drain path for the hydraulic fluid in the emergency trip supply.
loss of fluid pressure in the trip header will cause the main stop and reheat stop valves to close.
, a relay trip valve in the connection to the emergency trip supply opens to drop the pressure in relay emergency trip supply and cause the control and intercept valves to close. The control and rcept valves are redundant to the main stop and reheat stop valves respectively.
2.2.5.3 Overspeed Trip Functions and Mechanisms overspeed trips for the AP1000 turbine consist of a diverse 110% trip in the emergency trip em (ETS) and a 111% backup trip using three Ovation speed detection modules independent of OA controller described in Subsection 10.2.2.4.1 (see also Figure 10.2-2). The overspeed trip oints are identified in Table 10.2-2. The overspeed protection system will function for all ormal conditions, including a single failure of any component or subsystem.
110% trip is implemented electronically rather than mechanically as indicated in the review edure in SRP 10.2, Part III-2-C. An independent and redundant backup electrical overspeed trip uit senses the turbine speed by magnetic pickup and closes all valves associated with speed trol at approximately 111% of rated speed.
diverse 110% ETS trip system has triplicated passive speed sensors separate from the icated active speed sensors used in the backup 111% trip. Both trip functions use solenoid valves rain the emergency trip hydraulic supply. The hydraulic fluid in the trip and overspeed protection 10.2-7 Revision 1
diverse 110% ETS overspeed trip system, combined with the 111% overspeed protection tion of the turbine control system, provide a level of redundancy and diversity at least equivalent e recommendations for turbine overspeed protection found in III.2 of Standard Review Plan REG-0800) Section 10.2. The control signals from the two turbine-generator overspeed trip ems are isolated from, and independent of, each other. Each trip is initiated electrically in arate systems. The 110% and 111% trip systems have diverse hardware and software/firmware to inate common cause failures (CCFs) from rendering the trip functions inoperable. Additionally, issues and problems with overspeed protection systems identified in NUREG-1275 (Reference 3) e been addressed.
turbine rpm signals discussed in Subsection 10.2.2.4.1 are also used by redundant Ovation trollers for normal speed and load control functions (SRP 10.2 Part III.2.B). The rpm signals are monitored by a setpoint on each of the speed detection modules to support the backup rspeed trip at 111% overspeed (Part III.2.D). When the rpm speed reaches the backup turbine rspeed trip setpoint, the microprocessor on each speed detection module issues a trip command e onboard relay. When at least two out of three channels indicate a trip, a trip signal is sent to the ine.
pendence of the electrohydraulic control system of SRP 10.2 Part III.2.B and the backup trical overspeed trip circuit of Part III.2.D is assured in that failure of the Ovation controllers does affect the ability of the speed detection module to trip the turbine at the backup turbine overspeed setpoint. Although the electrohydraulic control system and the backup electrical overspeed trip uit are located in the same cabinet, common failure modes have been addressed to ensure the
% overspeed trip function in SRP 10.2 Part III.2.D cannot be rendered inoperable or affected by failure of the Ovation controllers. The control system also has diagnostic capabilities to provide rmation to the operator in the main control room in case of other failures or problems in the em or its components.
2.2.5.4 Trip Instrumentation bearing oil pressure, low electrohydraulic fluid pressure, and high condenser back pressure are h sensed by separate instrumentation. Each assembly consists of triplicate pressure transmitters instrument valves. Each assembly is arranged into three channels.
o of the three signals (pressure or vacuum) reach a trip setpoint, then the pressure sensors se the master trip device to operate.
trip function can be checked by a test device that simulates pressure to activate the trip outputs the modules.
2.2.5.5 Thrust Bearing Trip Device position pickups, which are part of the turbine supervisory instrument package, monitor ement of a disc mounted on the rotor near the thrust bearing collar. Axial movement of this collar flected in movement of the disc. Excessive movement of the disc is an indication of thrust ring wear. Should excessive movement occur, relay contacts from the supervisory instrument ules close to initiate a turbine trip.
thrust bearing trip function can be checked by a test device that simulates movement of the rotor ctivate the trip outputs from the modules.
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t control system or plant safety and monitoring system.
2.2.6 Other Protective Systems itional protective features of the turbine and steam system are:
Moisture separator reheater safety relief valves Rupture diaphragms located on each of the low-pressure turbine cylinder covers Turbine water induction protection systems on the extraction steam lines 2.2.7 Plant Loading and Load Following AP1000 turbine-generator control system and control strategy has the same loading and load wing characteristics as the control system described in Section 7.7. In addition, the turbine-erator has the following capabilities:
Daily load change between 100 and 30 percent of rated power Transition between baseload and load follow operation Extended weekend reduced power operation Rapid return to up to 90 percent of rated power the AP1000, this load following capability is maintained for most of cycle life.
2.2.8 Inspection and Testing Requirements or system components are readily accessible for inspection and are available for testing during mal plant operation. Turbine trip circuitry is tested prior to unit startup.
2.3 Turbine Rotor Integrity bine rotor integrity is provided by the integrated combination of material selection, rotor design, ture toughness requirements, tests, and inspections. This combination results in a very low bability of a condition that could result in a rotor failure.
rations and maintenance procedures mitigate the following potential degradation mechanisms in turbine rotor and buckets/blades: pitting, stress corrosion cracking, corrosion fatigue, low-cycle ue, erosion, and erosion-corrosion.
2.3.1 Materials Selection y integral turbine rotors are made from ladle refined, vacuum deoxidized, Ni-Cr-Mo-V alloy steel rocesses which maximize steel cleanliness and provide high toughness. Residual elements are trolled to the lowest practical concentrations consistent with melting practices. The chemical perty limits of ASTM A470, Classes 5, 6, and 7 are the basis for the material requirements for the ine rotors. The specification for rotor steel used in the AP1000 has lower limitations than cated in the ASTM standard for phosphorous, sulphur, aluminum, antimony, tin, argon, and per. This material has the lowest fracture appearance transitions temperatures (FATT) and the est Charpy V-notch energies obtainable on a consistent basis from water-quenched Ni-Cr-Mo-V erial at the sizes and strength levels used. Charpy tests and tensile tests in accordance with erican Society of Testing and Materials (ASTM) specification A370 are required from the forging plier.
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her degassed using a process whereby steel is poured into a mold under vacuum to produce an t with the desired material properties. This process minimizes the degree of chemical regation since silicon is not used to deoxidize the steel.
2.3.2 Fracture Toughness able material toughness is obtained through the use of materials described in section 10.2.3.1 to produce a balance of material strength and toughness to provide safety while ultaneously providing high reliability, availability, and efficiency during operation. The restrictions hosphorous, sulphur, aluminum, antimony, tin, argon, and copper in the specification for the rotor l provides for the appropriate balance of material strength and toughness. The impact energy transition temperature requirements are more rigorous than those given in ASTM 470 Class 6 e stress calculations include components due to centrifugal loads and thermal gradients where licable. Fracture toughness will be at least 220 MPa
- m = 200 ksi
- in and the ratio of fracture hness to the maximum applied stress intensity factor for rotors at speeds from normal to design rspeed will be at least 2. Material fracture toughness needed to maintain this ratio is verified by hanical property tests on material taken from the rotor.
rotor is evaluated for fracture toughness by criteria that include the design duty cycle stresses, ber of cycles, ultrasonic examination capability and growth rate of potential flaws. Conservative ors of safety are included for the size uncertainty of potential or reported ultrasonic indications, of flaw growth (da/dN versus dK) and the duty cycle stresses and number.
orted rotor forging indications are adjusted for size uncertainty and interaction. A rotor forging a reported indication that would grow to critical size in the applicable duty cycles is not accepted.
combined rotation and maximum transient thermal stresses used in the applicable duty cycles based on the brittle fracture and rotor fatigue analyses described below.
imum transient thermal stresses are determined from historical maximum loading rates for lear service rotors.
2.3.2.1 Brittle Fracture Analysis ittle fracture analysis is performed on the turbine rotor to provide confidence that small flaws in rotor, especially near the centerline, do not grow to a critical size with unstable growth resulting in tor burst. The brittle fracture analysis process includes determining the stresses in the rotor lting from rotation, steady-state thermal loads, and transient thermal loads from startup and load nge. These stresses are combined to generate the maximum stresses and locations of maximum ss for the startup and load change transients. A fracture mechanics analysis is performed at the tion(s) of maximum stress to verify that an initial flaw, equal to the minimum reportable size, will grow to critical crack size over the life of the rotor under the cumulative effects of startup and load nge transients.
acture mechanics analysis is done at the location(s) of maximum stress to determine the critical k size and the initial flaw area that would just grow to the critical size when subjected to the ber of startup and load change cycles determined to represent the lifetime of the rotor. This initial area is divided by a factor of safety to generate an allowable initial flaw area. The minimum ortable flaw size is multiplied by a conservative factor to correct for the imperfect nature of a flaw n ultrasonic reflector, as compared to the calibration reflector. The resulting area is the corrected 10.2-10 Revision 1
w is assumed to be an internal elliptical crack on the centerline for rotors without bores. For rotor tour or for flaws near the rotor bore (for bored rotors), a surface connected elliptical crack is umed. Flaw analysis is done assuming various flaw aspect ratios and the most conservative lts are used. The flaw is assumed to be orientated normal to the maximum principle stress ction.
beginning-of-life fracture appearance transition temperature for the high pressure and low sure rotor is specified in the material specification for the specific material alloy selected. Both high pressure and low pressure turbines operate at a temperature at which temperature rittlement is insignificant. The beginning-of-life fracture appearance transition temperature is not ected to shift during the life of the rotor due to temperature embrittlement.
imum material toughness is provided in the turbine rotors by specification of maximum fracture earance transition temperature and minimum upper shelf impact energy for the specific material y selected. There is not a separate material toughness (KIC) requirement for AP1000 rotors.
2.3.2.2 Rotor Fatigue Analysis tigue analysis is performed for the turbine rotors to show that the cumulative usage is acceptable expected transient conditions including normal plant startups, load following cycling, and other changes. The fatigue design curves are based on mean values of fatigue test data. Margin is ided by assuming a conservatively high number of turbine start and stop cycles. The Toshiba-igned turbine rotors in operating nuclear power plants were designed using this methodology and e had no history of fatigue crack initiation due to duty cycles.
ddition to the low cycle fatigue analysis for transient events, an evaluation for high cycle fatigue is ormed. This analysis considers loads due to gravity bending, bearing elevation misalignment, trol stage partial arc admission bearing reactions, and steady-state unbalance stress. The local rnating stress is calculated at critical rotor locations considering the bending moments due to the s described above. The maximum alternating stress is less than the smooth bar endurance ngth modified by a size factor.
AP1000 turbine generator is supported by a spring-mounted system to isolate the dynamic avior of the turbine-generator equipment from the foundation structure. The support system udes a reinforced concrete deck on which the turbine generator is mounted. The deck is sized to ntain the gravity load and misalignment load bending stresses within allowable limits. The luation of the loads includes a dynamic analysis of the combined turbine-generator and dation structure.
2.3.3 High Temperature Properties operating temperatures of the high-pressure rotors are below the creep rupture range. Creep ure is, therefore, not considered to be a significant factor in providing rotor integrity over the me of the turbine. Basic data are obtained from laboratory creep rupture tests.
2.3.4 Turbine Rotor Design turbine assembly is designed to withstand normal conditions and anticipated transients, uding those resulting in turbine trip, without loss of structural integrity. The design of the turbine embly meets the more restrictive of the following criteria:
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The tangential stresses will not cause a flaw, which is twice the corrected ultrasonic examination reportable size, to grow to critical size in the design life of the rotor. This will result in the ratio of fracture toughness to the maximum applied stress intensity factor for the rotor at speeds from normal to design overspeed being at least 2.
high-pressure turbine has fully integral rotors forged from a single ingot of low alloy steel. This ign is inherently less likely to have a failure resulting in a turbine missile than previous designs shrunk-on discs. A major advantage of the fully integral rotor is the elimination of disc bores and ways. In the fully integral rotor design, the location of peak stresses is in the lower stress blade ening areas. This difference results in a substantial reduction of the rotor peak stresses, which in reduces the potential for crack initiation. The reduction in peak stress also permits selection of a erial with improved ductility, toughness, and resistance to stress corrosion cracking.
non-bored design of the high-pressure turbine element provides the necessary design margin by e of its inherently lower centerline stress. Metallurgical processes permit fabrication of the rotors out a center borehole. The use of solid rotor forgings was qualified by evaluation of the material oved from center-bored rotors for fossil power plants. This evaluation demonstrated that the erial at the center of the rotors satisfied the rotor material specification requirements. Forgings for bore rotors are provided by suppliers who have been qualified based on bore material ormance.
low-pressure turbine element is a fully integral rotor fabricated from a single forging. There are eyways, which can be potential locations for stress risers and corrosive contaminate centration, exposed to a steam environment. The integral disc profiles are carefully designed to the surface stress in areas vulnerable to stress corrosion. Surface stress in less than ideal steam ironments is limited to less than 50 percent of the yield strength to reduce the chances of stress osion as far as practicable.
2.3.5 Preservice Tests and Inspections service inspections for turbine rotors include the following:
Rotor forgings are rough machined with a minimum stock allowance prior to heat treatment.
Each rotor forging is subjected to a 100-percent volumetric (ultrasonic) examination. Each finish-machined rotor is subjected to a surface magnetic particle and visual examination.
Results of the above examination are evaluated by use of criteria that are more restrictive than those specified for Class 1 components in ASME Code,Section III and V. These criteria include the requirement that subsurface sonic indications are either removed or evaluated to verify that they do not grow to a size which compromises the integrity of the unit during the service life of the unit.
Finish-machined surfaces are subjected to a magnetic particle examination. No magnetic particle flaw indications are permissible in bores (if present) or other highly stressed regions.
Each fully bladed turbine rotor assembly is spin tested at 20 percent overspeed, the maximum speed following a load rejection from full load.
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2.3.6 Maintenance and Inspection Program Plan maintenance and inspection program plan for the turbine assembly and valves is based on ine missile probability calculations, operating experience of similar equipment, and inspection lts. The methodology for analysis of the probability of generation of missiles for fully integral rs was submitted in WCAP-16650-P (Reference 1). The methodology used for analysis of the sile generation probability calculations was used to determine turbine valve test frequency as cribed in WCAP-16651-P (Reference 2). The maintenance and inspection program includes the vities outlined below:
Disassembly of the turbine is conducted during plant shutdown. Inspection of parts that are normally inaccessible when the turbine is assembled for operation (couplings, coupling bolts, turbine rotors, and low-pressure turbine blades) is conducted.
This inspection consists of visual, surface, and volumetric examinations as indicated below:
- Each rotor and stationary and rotating blade path component is inspected visually and by magnetic particle testing on accessible surfaces. Ultrasonic inspection of the outer dovetail and the bucket pin is conducted. These inspections are conducted at intervals of about 10 years for low-pressure turbines and about 8 years for high-pressure turbines.
- A 100 percent surface examination of couplings and coupling bolts is performed.
- Fluorescent penetrant examination is conducted on nonmagnetic components.
At least one main steam stop valve, one main steam control valve, one reheat stop valve, and one intercept valve are dismantled approximately every 3 years during scheduled refueling or maintenance shutdowns. A visual and surface examination of valve internals is conducted. If unacceptable flaws or excessive corrosion are found in a valve, the other valves of its type are inspected. Valve bushings are inspected and cleaned, and bore diameters are checked for proper clearance.
Main stop valves, control valves, reheat stop and intercept valves may be tested with the turbine online. The D-EHC control test panel is used to stroke or partially stroke the valves.
Extraction nonreturn valves are tested prior to each startup.
Turbine valve testing is performed at six-month intervals. The semi-annual testing frequency is based on nuclear industry experience that turbine-related tests are the most common cause of plant trips at power. Plant trips at power may lead to challenges of the safety-related systems. Evaluations show that the probability of turbine missile generation with a semi-annual valve test is less than the evaluation criteria.
Extraction nonreturn valves are tested locally by stroking the valve full open with air, then equalizing air pressure, allowing the spring closure mechanism to close the valve. Closure of each valve is verified by direct observation of the valve arm movement.
valve inspection frequency of three years noted above is consistent with an 18-month fuel cycle AP1000 and is based on evaluations performed to support this valve inspection interval at rating plants with 18-month fuel cycles. A monitoring program is in place at operating nuclear 10.2-13 Revision 1
ulations.
inservice inspection (ISI) program for the turbine assembly provides assurance that rotor flaws lead to brittle fracture of a rotor are detected. The ISI program also coincides with the ISI edule during shutdown, as required by the ASME Boiler and Pressure Vessel Code,Section XI, includes complete inspection of all significant turbine components, such as couplings, coupling s, turbine shafts, low-pressure turbine blades, low-pressure rotors, and high-pressure rotors. This ection consists of visual, surface, and volumetric examinations required by the code.
2.4 Evaluation ponents of the turbine-generator are conventional and typical of those which have been nsively used in other nuclear power plants. Instruments, controls, and protective devices are ided to confirm reliable and safe operation. Redundant, fast actuating controls are installed to ent damage resulting from overspeed and/or full-load rejection. The control system initiates a ine trip upon reactor trip. Automatic low-pressure exhaust hood water sprays are provided to ent excessive hood temperatures. Exhaust casing rupture diaphragms are provided to prevent pressure cylinder overpressure in the event of loss of condenser vacuum. The diaphragms are ge mounted and designed to maintain atmospheric pressure within the condenser and turbine aust housing while passing full flow.
e the steam generated in the steam generators is not normally radioactive, no radiation shielding ovided for the turbine-generator and associated components. Radiological considerations do not ct access to system components during normal conditions. In the event of a primary-to-secondary em leak due to a steam generator tube leak, it is possible for the steam to become contaminated.
ussions of the radiological aspects of primary-to-secondary leakage are presented in pters 11 and 12.
2.5 Instrumentation Applications turbine-generator is provided with turbine supervisory instrumentation including monitors for the wing:
Speed Stop valve position Control valve position Reheat intercept and stop valve positions Temperatures as required for controlled starting, including:
- External valve chest inner surface
- External valve chest outer surface
- First-stage shell lower inner surface
- Crossover pipe downstream of reheat stop valve No. 1
- Crossover pipe downstream of reheat stop valve No. 2
- Crossover pipe downstream of reheat stop valve No. 3
- Crossover pipe downstream of reheat stop valve No. 4
- Crossover pipe downstream of reheat stop valve No. 5
- Crossover pipe downstream of reheat stop valve No. 6 Casing and shaft differential expansion Vibration of each bearing Shaft eccentricity Bearing metal temperatures 10.2-14 Revision 1
Turbine supervisory instruments common alarm ddition to the turbine protective trips listed in Subsection 10.2.2.5, the following trips are provided:
High exhaust hood temperature Low emergency trip system pressure Low shaft-driven lube oil pump discharge pressure High or low level in moisture separator drain tank cations of the following miscellaneous parameters are provided:
Main steam throttle pressure Steam seal supply header pressure Steam seal condenser vacuum Bearing oil header pressure Bearing oil coolers coolant temperature D-EHC control fluid header pressure D-EHC control fluid temperature Crossover pressure Moisture separator drain tank level First-stage pressure High-pressure turbine exhaust pressure Extraction steam pressure, each extraction point Low-pressure turbine exhaust hood pressure Exhaust hood temperature for each exhaust erator supervisory instruments are provided, with sensors and/or transmitters mounted on the ociated equipment. These indicate or record the following:
Multiple generator stator winding temperatures; the detectors are built into the generator, protected from the cooling medium, and distributed around the circumference in positions having the highest expected temperature Stator coil cooling water temperature (one detector per coil)
Hydrogen cooler inlet gas temperature (two detectors at each point)
Hydrogen gas pressure Hydrogen gas purity Generator ampere, voltage, and power itional generator protective devices are listed in Table 10.2-3.
2.6 Combined License Information on Turbine Maintenance and Inspection rbine maintenance and inspection program will be submitted to the NRC staff for review prior to load. The program will be consistent with the maintenance and inspection program plan activities 10.2-15 Revision 1
2.7 References WCAP-16650-P, Proprietary and WCAP-16650-NP, Nonproprietary, "Analysis of the Probability of the Generation of Missiles from Fully Integral Nuclear Low Pressure Turbines," Revision 0, February 2007.
WCAP-16651-P, Proprietary and WCAP-16651-NP, Nonproprietary, "Probabilistic Evaluation of Turbine Valve Test Frequency," Revision 1, May 2009.
NUREG-1275, Vol. 11, Operating Experience Feedback Report - Turbine-Generator Overspeed Protection Systems, Commercial Power Reactors, H. L. Ornstein, Nuclear Regulatory Commission, April 1995.
10.2-16 Revision 1
Manufacturer Toshiba Turbine Type TC6F 52-in. LSB No. of elements 1 high pressure; 3 low pressure Last-stage blade length (in.) 52 Operating speed (rpm) 1800 Condensing pressure (in. HgA) 2.9 Generator Generator rated output (kW) 1,237,500 Power factor 0.90 Generator rating (kVA) 1,375,000 Hydrogen pressure (psig) 75 Moisture separator/reheater Moisture separator Chevron vanes Reheater U-tube Number 2 shell Stages of reheating 2 10.2-17 Revision 1
Percent of Rated Speed (Approximate) Event 100 Turbine is initially at valves wide open. Full load is lost. Speed begins to rise. When the breaker opens, the load drop anticipator immediately closes the control and intercept valves if the load at time of separation is greater than 30 percent.
101 Control and intercept valves begin to close.
108 Peak transient speed with normally operating speed control system.
If the power/load unbalance and speed control systems had failed prior to loss of load, then:
110 A trip signal is sent by the overspeed trip system to actuate closure of the main stop, control, intercept, and reheat stop valves by releasing the hydraulic fluid pressure in the valve actuators using a two-out-of-three logic system.
111 The emergency electrical overspeed trip system closes the main stop, control, intercept, and reheat stop valves by releasing the hydraulic fluid pressure in the valve actuators using a two-out-of-three trip logic system.
wing the above sequence of events, the turbine may approach but not exceed 120 percent of rated speed.
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with the Voltage Regulator Package Device Action Generator Minimum Excitation Limiter - maintains generator reactive power imiter output above certain level (normally steady-state stability limit level)
Alarm - when limiter is limiting Generator Maximum Excitation Limiter - maintains generator field voltage below imiter certain voltage inverse time characteristics Alarm - when limiter is timing Alarm - when limiter is limiting Generator Overexcitation Protection Alarm - changes the standby controller when overexcitation protection pickup level is exceeded
- the system has two master controller configurations; i.e., one is for normal operations and the other is standby nverse Timer Alarm - when timing commences Regulator trip - when timed out ixed Timer Alarm - when timing Unit trip - when timed out Generator Volts/Hertz Limiter Limiter - maintains machine terminal volts/Hertz ratio below certain level Alarm - when limiter is limiting Generator Dual Level Volts/Hertz Alarm - when above either preset volts/Hertz Protection level Unit trip - if timed out at either alarm level Generator Automatic Field Ground Alarm - ground Detection Regulator Firing Circuit - Loss of Alarm - loss of one firing circuit hyristor Firing Pulse Protection Unit Trip - loss of both firing circuits hyristor Blown Fuse Detection Alarm - When one or more thyristor fuses in power drawers open 10.2-19 Revision 1
Device Action Regulator Forcing Indication Alarm - online forcing Alarm - offline forcing (blocks "Raise" controls of dc regulator and ac regulator adjusters)
Regulator Loss of Power Supply (s) Alarm - loss of one power supply Protection Unit trip - loss of both power supplies Regulator Loss of Sensing Protection Alarm and - when regulator voltage transformer ac regulator trip changes the standby controller. The system has two master controller configurations; i.e., one is for normal operation and the other is for standby Excitation Supply Breaker Alarm Excitation trip Power System Stabilizer (PSS) Alarm - When PSS output exceeds specified Excessive Output Protection Power System level for specified time Stabilizer trip Power System Stabilizer Inservice Indicator - lamps and contacts nstrumentation Indication Generator - Overvoltage Protection Alarm - Phase-back thyristor firing pulses if overvoltage condition persists for a specified time 10.2-20 Revision 1
Closing Time Valve (seconds) in Stop Valves 0.3 ntrol Valves 0.3 rcept Valves 0.3 heat Stop Valves 0.3 raction Nonreturn Valves <1.0 10.2-21 Revision 1
WLS 1&2 - UFSAR Figure 10.2-1 (Sheet 1 of 2)
Turbine Generator Outline Drawing 10.2-22 Revision 1
WLS 1&2 - UFSAR Figure 10.2-1 (Sheet 2 of 2)
Turbine Generator Outline Drawing 10.2-23 Revision 1
WLS 1&2 - UFSAR Figure 10.2-2 Emergency Trip System Functional Diagram 10.2-24 Revision 1
m generator system (SGS), main steam system (MSS), and main turbine system (MTS).
function of the main steam supply system is to supply steam from the steam generators to the
-pressure turbine over a range of flows and pressures covering the entire operating range from em warmup to maximum calculated turbine conditions.
system provides steam to the moisture separator/reheaters and the gland seal system for the n turbine. The system dissipates heat generated by the nuclear steam supply system (NSSS) by ns of steam dump valves to the condenser or to the atmosphere through power-operated ospheric relief valves or spring-loaded main steam safety valves when either the turbine-erator or condenser is unavailable.
3.1 Design Basis 3.1.1 Safety Design Basis main steam supply system safety design bases are as follows:
The system is provided with a main steam isolation valve (MSIV) and associated MSIV bypass valve on each main steam line from its respective steam generator. These valves isolate the secondary side of each of the steam generators to prevent the uncontrolled blowdown of more than one steam generator and isolate nonsafety-related portions of the system.
Codes and standards utilized in the design of the main steam supply system are identified in Section 3.2, according to the AP1000 equipment class of the component. The main steam supply system contains class B and class C safety-related components.
Table 3.2-3 identifies the safety-related mechanical equipment in the main steam supply system, and lists the associated ASME code class. (Since all the safety-related components of the main steam supply system are in the AP1000 steam generator system [SGS], they appear in that table with an SGS prefix. For example, the main steam isolation valves [MSIVs] are listed there as SGS-PL-V040A and B).
The following main steam supply system components are classified as equipment class B and are safety-related:
- The main steam line piping from the steam generator up to, and including, the main steam isolation valves
- The main steam isolation valve bypass piping up to, and including, the main steam isolation bypass valve
- The inlet piping from the main steam line up to, and including, the main steam safety valves
- The inlet piping from the main steam line up to, and including, the power operated relief valve block valve
- The instrumentation piping up to, and including, the main steam line pressure instrument root valves 10.3-1 Revision 1
- The main steam drain condensate pot located upstream of the main steam isolation valves, and the drain piping up to, and including, the first isolation valve The following main steam supply system components are classified as equipment class C and are safety-related:
- The main steam line piping from the main steam isolation valves outlet to the pipe restraint located on the wall between the auxiliary building and the turbine building
- The main steam safety valve discharge piping and vent stacks
- The piping from the outlet of the power operated relief block valve up to, and including, the power operated relief valve
- The condensate drain piping from the outlet of the class B isolation valve to the restraint on the wall between the auxiliary building and the turbine building (The remainder of the main steam supply system is nonsafety-related. Except for the power operated relief valve discharge piping from the power operated relief valve outlet to the power operated relief valve silencer, which is class D, the remainder of the main steam supply system is class E).
The system provides suitable overpressure protection of the steam generator secondary side and class 2 main steam piping in accordance with ASME Code,Section III.
The safety-related portion of the system is designed to withstand the effects of a safe shutdown earthquake and to perform its intended function following postulated events.
The safety-related portions of the system are protected from wind and tornado effects, as described in Section 3.3; flood protection is described in Section 3.4; missile protection is described in Section 3.5; protection against dynamic effects associated with the postulated rupture of piping is described in Section 3.6; seismic protection is described in Section 3.7; environmental design is described in Section 3.11; and fire protection is described in Section 9.5.
The safety-related portion of the system is designed so that a single, active failure in the main steam supply system will not result in:
- A loss-of-coolant accident
- Loss of integrity of other steam lines
- Loss of the capability of the engineered safety features system to effect a safe reactor shutdown
- Transmission of excessive loading to the containment pressure boundary Component or functional redundancy is provided so that safety functions can be performed assuming a single, active failure coincident with loss of offsite power. Consistent with NUREG 0138 and Standard Review Plan Section 10.3, the nonsafety-related valves downstream of the main steam isolation valves are assumed functional to effect this capability.
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Subsection 10.3.4.4.)
The main steam supply system is designed to function in the normal and accident environments identified in Section 3.11.
The main steam supply system is qualified to leak-before-break criteria as described in Section 3.6.
The main steam supply system design complies with containment isolation criteria as discussed in Subsection 6.2.3.
The nonsafety-related turbine stop, turbine control, turbine bypass, and moisture separator reheater 2nd stage steam isolation valves are credited in a single failure analysis to mitigate the event for those cases in which the rupture of the main steam or feedwater piping inside containment is the postulated initiating event.
3.1.2 Power Generation Design Basis following is a list of the principal power generation design bases:
The main steam supply system delivers steam from the steam generators to the turbine-generator for the range of flowrates, temperatures, and pressures existing from warmup to rated power conditions.
Each main steam line is sized and routed to provide balanced steam pressures to the turbine stop valves.
The main steam supply system provides the capacity to dump 40 percent of full plant load steam flow to the condenser during plant step-load reductions.
The system provides the means of dissipating residual and sensible heat generated from the nuclear steam supply system during hot shutdown and cooldown even when the main condenser is not available. Power-operated atmospheric relief valves are provided to allow controlled cooldown of the steam generator and the reactor coolant system when the condenser is not available.
Piping system components located downstream of the auxiliary building wall anchor assemblies are designed in accordance with the Power Piping Code, ANSI B31.1.
3.2 System Description 3.2.1 General Description main steam supply system shown in Figures 10.3.2-1 and 10.3.2-2 include the following major ponents:
Main steam piping from the steam generator outlet steam nozzles to the main turbine stop valves One main steam isolation valve and one main steam isolation valve bypass valve per main steam line 10.3-3 Revision 1
le 10.3.2-1 lists the design data for the major components of the main steam supply system.
le 10.3.2-2 lists the design data for the main steam safety valve.
3.2.2 Component Description 3.2.2.1 Main Steam Piping escription of the main steam piping from the steam generators to the turbine stop valves is ented in Table 10.3.2-3.
main steam lines deliver a steamflow from the secondary side of the two steam generators. A ion of the main steamflow is directed to the reheater and steam seals, with the turbine receiving remaining steamflow. Table 10.3.2-1 lists the performance data for the main steam supply em. Each of the main steam lines from the steam generators is anchored at the auxiliary building and has sufficient flexibility to accommodate thermal expansion.
ign of seismic Category I piping and supports takes into consideration the loads discussed in section 3.9.3.
main steam lines between the steam generator and the containment penetration are designed to t the leak-before-break criteria. The portion of the main steam lines between the containment etration and the anchor downstream of the main steam isolation valves is part of the break usion zone. Section 3.6 addresses the applicability of leak-before-break and break exclusion e to the main steam line.
layout of the steam piping provides for the collection and drainage of condensate to avoid water ainment, by the proper sloping of lines and the use of condensate drain pots.
sizing and layout of the main steam piping hydraulically balances the steam line pressure drops the respective steam generator to the inlet of each turbine stop valve. Two main steam lines are s-connected into a common header just before branching into each turbine stop valve. This ngement equalizes flow and pressure to the inlet of the turbine stop valves. This also permits ne testing of each turbine stop valve without exceeding the allowable limit on steam generator sure differential. Each steam generator outlet nozzle contains an internal flow restrictor ngement to limit flow in the event of a main steam line break. A further description of the flow rictor is provided in Subsection 5.4.4.
pling connections are installed in the nonsafety-related portion of each main steam line, nstream of the main steam isolation valves. These nozzles are used for the sampling of steam.
sampling is monitored and analyzed through the secondary sampling system (SSS). Refer to section 9.3.4 for further discussion of the secondary sampling system.
tainment penetrations are described in Subsection 6.2.3.
bine bypass valves are provided between the main steam isolation valves and turbine-generator valves, as discussed under the turbine bypass system (refer to Subsection 10.4.4).
n steam piping is designed to consider the effects of erosion/corrosion. Piping is constructed of ion/corrosion resistant low alloy steel. Velocities in the main steam piping to the high pressure ine are limited to reduce the potential for pipe erosion. Low point drains are provided for 10.3-4 Revision 1
nch connections are provided from the main steam system to perform various functions.
tream of the main steam isolation valves, there are connections for the power-operated ospheric relief valves, main steam safety valves, low point drains, high point vents, and nitrogen keting. Branch piping downstream of the main steam line isolation valves includes connections he two stage reheaters, turbine bypass system, auxiliary steam/gland seal system, and low point ns. Table 10.3.2-4 further describes branch piping, 2.5 inches and larger, that is downstream of main steam isolation valves.
rations and maintenance procedures include precautions, when appropriate, to minimize the ntial for steam and water hammer, including:
Prevention of rapid valve motion Process for avoiding introduction of voids into water-filled lines and components Proper filling and venting of water-filled lines and components Process for avoiding introduction of steam or heated water that can flash into water-filled lines and components Cautions for introduction of water into steam-filled lines or components Proper warmup of steam-filled lines Proper drainage of steam-filled lines The effects of valve alignments on line conditions 3.2.2.2 Main Steam Safety Valves n steam safety valves with sufficient rated capacity are provided to prevent the steam pressure exceeding 110 percent of the main steam system design pressure:
Following a turbine trip without a reactor trip and with main feedwater flow maintained Following a turbine trip with a delayed reactor trip and with the loss of main feedwater flow tal main steam safety valve rated capacity as indicated in Table 10.3.2-2 meets this requirement.
he same time, the individual safety valves are limited to the maximum allowable steam relief valve acity as indicated in Table 10.3.2-2 for a system pressure equal to main steam design pressure 10 percent overpressure. This value sufficiently limits potential uncontrolled blowdown flow and ensuing reactor transient should a single safety valve inadvertently fail or stick in the open ition.
safety valves are provided per main steam line for the plant. Table 10.3.2-2 lists the performance and set pressures for the main steam safety valves.
main steam supply system safety valves are located in the safety-related portion of the main m piping upstream of the main steam isolation valves and outside the containment in the iliary building. Adequate provision is made in the steam piping for the installation and support of 10.3-5 Revision 1
piping and valve arrangement minimizes the loads on the attachment, and analysis confirms the ign by use of guidelines in ASME Section III, Nonmandatory Appendix O, "Rules for Design of ety Valve Installations."
h safety valve is connected to vent stacks by an open umbrella-type transition piece ematically depicted in detail A of Figure 10.3.2-1.
vent stacks are designed to:
Direct the relieved steam away from adjoining structures Prevent backflow of relieved steam through the umbrella-type transition section Draw a small quantity of ambient air through the umbrella-type transition section and mix with the total steam flow which leaves the vent stack outlet Minimize the backpressure on the valve outlet so that it does not restrict the valve's rated capacity vent stacks are not required for safety, but are structurally designed to withstand safe-shutdown hquake loads in order to not jeopardize the performance of safety-related components.
3.2.2.3 Power-Operated Atmospheric Relief Valves wer-operated atmospheric relief valve is installed on the outlet piping from each steam generator rovide for controlled removal of reactor decay heat during normal reactor cooldown when the n steam isolation valves are closed or the turbine bypass system is not available. The valves are d to provide a flow as indicated in Table 10.3.2-1. The maximum capacity of the relief valve at ign pressure is limited to reduce the magnitude of a reactor transient if one valve would vertently open and remain open.
h power-operated relief valve is located outside the containment in the auxiliary building tream of the main steam isolation valves, in the safety-related portion of the main steam line ociated with each steam generator. This location permits valve operation following transient ditions, including those which could result in closure of the main steam isolation valves.
operation of the power-operated relief valves is automatically controlled by steam line pressure ng plant operations. The power-operated relief valves automatically modulate open and exhaust tmosphere whenever the steam line pressure exceeds a predetermined setpoint. As steam line sure decreases, the relief valves modulate closed, reseating at a pressure at least 10 psi below opening pressure. The setpoint is selected between no-load steam pressure and the set pressure e lowest set safety valves.
steam generator power-operated atmospheric relief valves provide a nonsafety-related means plant cooldown by discharging steam to the atmosphere when the turbine bypass system is not ilable. Under such circumstances, the relief valves (in conjunction with the startup feedwater em) allow the plant to be cooled down at a controlled cooldown rate from the pressure setpoint of lowest set of safety valves down to the point where the normal residual heat removal (RNS) em can remove the reactor heat.
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sts the pressure setpoint downward in a step-wise fashion. The maximum cooldown rate ievable is limited by the flow-passing capability of the relief valves, the number of steam erators (and hence the number of relief valves) in service, the available startup feedwater ping capacity and by the desire to either maintain or recover steam generator water levels during cooldown.
power-operated atmospheric relief valves also help to avoid actuation of the safety valves during ain transients and, following safety valve actuation, act to assist the safety valves to positively at by automatically reducing and regulating steam pressure to a value below the safety valve ating pressure. The operation of each power-operated atmospheric relief valve is controlled in onse to measurements of steam line pressure provided by four separate pressure taps on the ociated steam line.
valve operator is an air-operated modulating type, providing throttling capability over a range of m pressures.
atmospheric relief valves are controlled by nonsafety-related control systems for the modulating m relief function. The capability for remote manual valve operation is provided in the main control m and at the remote shutdown workstation. A safety-related solenoid is provided to vent the air the valve operator to terminate a steam line depressurization transient.
solation valve with remote controls is provided upstream of each power operated relief valve iding isolation of a leaking or stuck-open valve. The upstream location allows for maintenance on power-operated relief valve operator at power. The motor-operated isolation valve employs a ty-related operator and closes automatically on low steam line pressure to terminate steam line ressurization transients. The isolation valve is a containment isolation boundary and therefore is cified as safety-related, active, ASME Code,Section III, Safety Class 2.
3.2.2.4 Main Steam Isolation Valves function of the main steam isolation is to limit blowdown to one steam generator in the event of a m line break to:
Limit the effect upon the reactor core to within specified fuel design limits Limit containment pressure to a value less than design pressure n steam isolation consists of one quick-acting gate valve in each main steam line and one ociated globe main steam isolation bypass valve with associated actuators and instrumentation.
se valves are located outside the containment, downstream of the steam generator safety valves the atmospheric relief valve, in the auxiliary building. The isolation valves provide positive shutoff minimum leakage during postulated line severance conditions either upstream or downstream of valves.
main steam isolation valves close fully upon receipt of a manual or automatic signal and remain closed. Upon receipt of the closing signal, the main steam isolation valves complete the closing e despite loss of normally required utility services for actuator and/or instrumentation. On loss of ating hydraulic power, the valves fail to the closed position. On loss of electrical power the valves ain in their current position. Position indication and remote manual operation of the isolation es are provided in the control room and remote shutdown workstation. Additionally, provisions made for in-service inspection of the isolation valves.
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Low steam line pressure in one of two loops High containment pressure High negative steam pressure rate in one of two loops Low Tcold in either reactor coolant loop Manual actuation: There are four controls for main steam line actuation. Two of the controls provide system level actuation, that is, isolate both steam lines, and two of the controls, one per loop, provide isolation of a single steam line.
Manual reset: In addition to the controls for manual isolation actuation, there are two controls for manual reset of the steam line isolation signal, one for each of the logic divisions associated with steam line controls, which can be used to manually reset that divisions steam line isolation signal.
h main steam isolation valve is a bidirectional wedge type gate valve composed of a valve body is welded into the system pipeline. The main steam isolation gate valve is provided with a raulic/pneumatic actuator. The valve actuator is supported by the yoke, which is attached to the of the body. The valve actuator consists of a hydraulic cylinder with a stored energy system to ide emergency closure of the isolation valve. The energy to operate the valve is stored in the of compressed nitrogen contained in one end of the actuator cylinder. The main steam isolation e is maintained in a normally open position by high-pressure hydraulic fluid. For emergency ure, redundant solenoids are energized resulting in the high-pressure hydraulic fluid being ped to a fluid reservoir.
main steam isolation bypass valves are used to permit warming of the main steam lines prior to tup when the main steam isolation valves are closed. The bypass valves are modulating, air-rated globe valves. For emergency closure, redundant 1E solenoids are provided. Each solenoid nergized from a separate safety-related division.
3.2.3 System Operation 3.2.3.1 Normal Operation ing normal power operation, the main steam supply system supplies steam to meet the demand e main turbine system. The main steam supply system also supplies steam as required to the iliary steam system, and reheating steam to the moisture separator reheater. The main steam ply system also provides steam to the turbine gland seal system.
main steam supply system is capable of accepting a +/-10-percent step change in load followed
+/-5-percent/min ramp change without discharging steam to the atmosphere through the main m safety valves or to the main condenser through the turbine bypass system. For large step nge load reductions, steam is bypassed (up to 40 percent of full load flow) directly to the denser via the turbine bypass system. As discussed in Subsection 10.4.4, the main steam supply em, in conjunction with the turbine bypass system, is capable of accepting a 100-percent net load ction without reactor trip (in conjunction with a reactor rapid power reduction) and without lifting ty valves. If the turbine bypass system is not available, steam is vented to the atmosphere via the er-operated atmospheric relief valves and the main steam safety valves, as required.
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m isolation bypass valves and other valves associated with the main steam lines can be closed.
power-operated atmospheric relief valves are then used to remove reactor decay and primary em sensible heat to cooldown to conditions at which the normal residual heat removal system perform the remaining cooldown function. If the power-operated atmospheric relief valve for an vidual main steam line is unavailable because of the loss of its control or power supply, the ective safety valves will provide overpressure protection. The remaining power-operated ospheric relief valve is sufficient to cooldown the plant.
e event that a design basis accident occurs, which results in a large steam line break, the main m isolation valves with associated main steam isolation bypass valves automatically close. The ure of the main steam isolation valves and associated main steam isolation bypass valves result o more than one steam generator supplying a postulated break.
passive residual heat removal system (Section 6.3) provides safety-related decay heat removal ability should steam relief and feedwater be unavailable.
3.3 Safety Evaluation Each main steam line is provided with safety valves that limit the pressure in the line to limit over-pressurization and remove stored energy. Each line is provided with a power-operated atmospheric relief valve to permit reduction of the main steam line pressure and remove stored energy to achieve an orderly shutdown. The startup feedwater system, described in Subsection 10.4.9, provides makeup to the steam generators consistent with the steaming rate.
Redundant power supplies and power divisions operate the main steam isolation valves and main steam isolation bypass valves to isolate safety and nonsafety-related portions of the system. Branch lines upstream of the main steam isolation valves contain normally closed, power-operated atmospheric relief valves which modulate open and closed on steam line pressure. In the event the atmospheric relief valves fail closed, the safety valves provide overpressure protection.
Releases of radioactivity from the main steam system are minimized because there are no significant amounts of radioactivity in the system under normal operating conditions. Additionally, the main steam isolation system provides controls for reducing releases, as described in Chapter 15, following a steam generator tube rupture.
Detection of radioactive leakage into the system, which is characteristic of a steam generator tube leak or rupture, is facilitated by adjacent-to-line radiation monitors on each steam line, the radiation monitor in the turbine vent and drain system which monitors condenser air removal, and the steam generator blowdown line radiation monitor.
Section 3.2 provides the quality group classification, the required design and fabrication codes, and seismic category applicable to the safety-related portion of this system and supporting systems. The power supplies and controls necessary for safety-related functions of the main steam supply system are safety-related, as described in Chapters 7 and 8.
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Sections 3.3, 3.4, 3.5, 3.7, and 3.8 describe the bases of the structural design of these buildings.
The safety-related portion of the main steam supply system is designed to remain functional after a safe shutdown earthquake. Sections 3.7 and 3.9 provide the design loading conditions that were considered. Sections 3.5, 3.6, and 9.5 describe the analyses to provide confidence that a safe shutdown, as outlined in Section 7.4, is achieved and maintained.
As indicated by the failure mode and effects analysis in Table 10.3.3-1, no single failure coincident with loss of offsite power compromises the system safety functions.
The main steam supply system is initially tested with the program given in Chapter 14.
Periodic in-service functional testing is done in accordance with Subsection 10.3.4.
Section 6.6 provides the ASME Code,Section XI requirements that are appropriate for the safety-related portions of the main steam supply system.
The safety-related components of the main steam supply system are qualified to function in normal, test, and accident environmental conditions. The environmental qualification program is described in Section 3.11.
A discussion of high energy pipe break locations and evaluation of effects are provided in Subsections 3.6.1 and 3.6.2.
A discussion of the leak-before-break application and criteria is presented in Subsection 3.6.3.
3.4 Inspection and Testing Requirements 3.4.1 Preoperational Testing 3.4.1.1 Valve Testing and Inspection operability and relief setpoints of the main steam safety valves will be verified at operating perature using steam as the pressurization fluid. The advantage of this approach is that the ing at temperature will reduce the probability of having to adjust the valve setpoints during hot tional testing heatup. The valves may be either bench tested or in-situ tested. The valves will be sted to lift at their set pressure defined in Table 10.3.2-2.
sum of the rated capacities of the valves shall exceed the capacity specified in Table 10.3.2-1.
relieving capacity of the valve is certified in accordance with the ASME Code,Section III 7000.
lift-point of each power-operated atmospheric relief valve is checked against pressure gauges nted in the main steam piping.
power operated relief valves will be verified to have a relief capacity of at least 300,000 lbs/hour 106 psia in order to satisfy their non-safety related function of decay heat removal.
main steam isolation valves are tested to verify the closing time prior to initial startup.
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rgency operating modes. This includes operation of applicable portions of the protection system.
safety-related components of the system are designed and located to permit pre-service and ervice inspections.
3.4.1.3 Pipe Testing main steam lines within the containment and the auxiliary building are visually and volumetrically ected at installation as required by ASME Code,Section XI pre-service inspection requirements.
3.4.2 In-service Testing performance and structural leaktight integrity of system components are demonstrated by ration.
itional description of in-service inspection and in-service testing of ASME Code,Section III, ss 2 and 3 components is contained in Section 6.6 and Subsection 3.9.6. The nonsafety-related ine stop, turbine control, and moisture separator reheater 2nd stage steam isolation valves are uded in the inservice test program discussed in Subsection 3.9.6.
3.5 Water Chemistry objectives of the secondary side water chemistry program are as follows:
Minimizing general corrosion in the steam generators, turbine, and feedwater system by maintaining proper pH control and by minimizing oxygen ingress (coupled with oxygen scavenging)
Minimizing localized corrosion in the steam generators, turbine, and feedwater system by minimizing chemical contaminant ingress and by controlling contaminant levels through condensate polishing and steam generator blowdown.
3.5.1 Chemistry Control Basis am Generator Owners Group recommendations are considered in the secondary side water mistry program.
ondary side water chemistry control basis for AP1000 is shown below:
tem Design Selection of secondary side materials to minimize corrosive species such as copper oxides Capability of deaeration in the demineralized water supply path, condenser, and deaerator Capability of continuous blowdown of the steam generator bulk water Capability of post-construction cleaning of the feedwater system followed by wet layup of the feedwater system and steam generators 10.3-11 Revision 1
Capability to filter and demineralize condensate by passage of part of the condensate flow through a condensate polisher system prior to and during plant startup and shutdown and during power operation with abnormal secondary cycle chemistry.
Chemical addition to establish and maintain an environment that minimizes system corrosion Identification of action levels based on chemistry conditions, as determined by high sensitivity continuous monitoring or by grab sampling 3.5.2 Contaminant Ingress taminants may be introduced into the secondary side water system through three major hanisms: makeup water; condenser tube leaks; atmospheric leaks at the condenser or pump ls. The following methods are used to detect the ingress of contaminants in the secondary water em:
Demineralized water is continuously monitored as it is being produced in the water treatment plant.
Ionic contaminants are detected by monitoring (either continuous process monitors or sample analysis) the condensate pump discharge, feedwater downstream of addition of heater and moisture separator drains, and steam generator bulk flow as blowdown.
Atmospheric ingress is detected by monitoring the condensate pump discharge for excessive dissolved oxygen and by monitoring condenser air removal rate.
3.5.3 Condensate Polishing ndensate polishing system with a capacity of one third design condensate flow is provided to ove corrosion products and ionic contaminants. This polishing system will not normally be loyed during all phases of plant operation.
secondary side water system has provisions for recirculating feedwater to the condenser prior to during startup. The polisher may be used during this phase to remove corrosion products from feedwater and thus prevent their ingress into the steam generators. Full flow or near full flow densate polishing is possible at the lower condensate flows that exist during startup and low-er operation. See Subsection 10.4.6 for additional information.
3.5.4 Chemical Addition 000 employs an all-volatile treatment (AVT) method to minimize general corrosion in the water system, steam generators, and main steam piping. A pH adjustment chemical and an gen scavenger are the two chemicals to be injected into the condensate pump discharge header, nstream of the condensate polishers.
educe the general corrosion rate of ferrous alloys, a volatile pH adjustment chemical is injected to ntain a noncorrosive environment. Although the pH adjustment chemical is volatile and will not centrate in the steam generator, it will reach an equilibrium level which will help establish corrosive conditions.
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biting general corrosion.
line chemistry supports maintaining iodine compounds in their nonvolatile form. When iodine is in lemental form, it is volatile and free to react with organic compounds to create organic iodine pounds, which are not assumed to remain in solution. It is noted that no significant level of anic compounds is expected in the secondary system. The secondary water chemistry, thus, does directly impact the radioactive iodine partition coefficients.
3.5.5 Action Levels for Abnormal Conditions ropriate responses to abnormal chemistry conditions provide for the long-term integrity of ondary cycle components. Action taken when chemistry parameters are outside normal operating ges will, in general, be consistent with action levels described in Reference 1.
ondary side water chemistry guidelines are provided in Table 10.3.5-1.
3.5.6 Layup and Heatup 000 anticipates no long-term steam generator layup under dry conditions. When maintenance or ection is required on the secondary side of the steam generators, the steam generators are ned hot under nitrogen atmosphere. After cooling, the nitrogen purge is lifted and the ntenance/inspection begun.
layup conditions are established for corrosion protection during outages. Guidelines are given in le 10.3.5-2.
ore heatup to full power, the bulk water in the steam generators is normally brought into power ration specifications by draining and refilling or by feeding and bleeding. Guidelines for heatup provided in Table 10.3.5-3.
3.5.7 Chemical Analysis Basis delines for chemical control and diagnostic parameters are listed in Table 10.3.5-1. Each ameter will be addressed as indicated below.
gen in the presence of moisture rapidly corrodes carbon steel. These corrosion products may be ied through the feedwater system and form sludge in the steam generator. This sludge forms an ironment for localized corrosion mechanisms on steam generator tubes. Thus, concentrations of gen are kept as low as practical in the feedwater system, and dissolved oxygen is controlled at condenser and deaerator to prevent oxygen transport to the feedwater system.
idual concentration of the oxygen scavenger is also measured in the feedwater sample and is d as input for injection of the oxygen scavenger.
e absence of significant impurities, the pH is controlled by the concentration of the volatile pH stment chemical and the oxygen scavenger. Maintaining the pH within the recommended band lts in minimal corrosion rates of ferrous materials.
ductivity is also a measure of the presence of ionic contamination and provision is made for itoring conductivity in samples of condensate, feedwater, and steam generator blowdown.
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3.5.8 Sampling ddition to the sampling locations listed in Table 10.3.5-1, other sampling points are provided in the ondary side water system. These sampling points are identified in Table 9.3.4-1 (continuous ple points) and Table 9.3.4-2 (grab sample points).
3.5.9 Condenser Inspection secondary side water chemistry program includes an inspection program of the condenser to fy condenser integrity. This program includes a visual inspection of the condenser during outages component inspection for air leaks during plant operation.
3.5.10 Conformance to Branch Technical Position MTEB 5-3 000 conformance to Branch Technical Position MTEB 5-3 is discussed in Section 1.9.
3.6 Steam and Feedwater System Materials 3.6.1 Fracture Toughness material specifications for pressure-retaining materials in safety-related portions of the main m and feedwater systems meet the fracture toughness requirements of ASME Code,Section III, cles NC-2300 and ND-2300 for Quality Group B and Quality Group C components.
3.6.2 Material Selection and Fabrication e, flanges, fittings, valves, and other piping material conform to the referenced ASME, ASTM, SI, or Manufacturer Standardization Society-Standard Practice code.
copper or copper-bearing materials are used in the steam and feedwater systems.
following requirements apply to the nonsafety-related portion of the main steam system.
mponent .................................................................................................. Alloy/Carbon Steel e............................................................................................................ ANSI/ASME B36.10M ngs ...............................................................................................ANSI/ASME B16.9, B16.11 nges ........................................................................................................... ANSI/ASME B16.5 erial selection and fabrication requirements for ASME Code,Section III, Class 2 and 3 ponents in the safety-related portions of the main steam and feedwater systems are consistent the requirements for ASME Class 2 and 3 systems and components outlined in sections 6.1.1.1 and 6.1.1.2. Material specifications for the main steam and feedwater systems listed in Table 10.3.2-3.
formance with the applicable regulatory guides is described in Subsection 1.9.1.
destructive inspection of ASME Code,Section III, Class 2 and 3 components in the safety-ted portions of the main steam and feedwater systems is addressed in Subsection 6.6.5.
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ponents.
3.7 Combined License Information section contained no requirement for information.
3.8 References "PWR Secondary Water Chemistry Guidelines," EPRI TR-102134-R5, March 2000.
10.3-15 Revision 1
Steam Flow Maximum (lb/hr) Calculated steam generator 7.49x106 l 14.97x106 ign Conditions ign pressure (psia) 1200 ign temperature (°F) 600°F rating Conditions plant load pressure (psia) 836 plant load temperature (°F) 523.3 oad (hot standby) pressure (psia) 1106 oad (hot standby) temperature (°F) 557 n Steam Piping: See Table 10.3.2-3.
am Generator Flow Restrictor ber per steam generator outlet nozzle 7 oat size (ft2) 0.2 l area (ft2) 1.4 er-Operated Relief Valve ber per main steam line 1 mal set pressure 1138 psig ign capacity inimum: 70,000 lb/hr at 100 psia steam generator pressure aximum: 1,020,000 lb/hr at 1200 psia steam generator pressure e ASME Code,Section III, Class 3, seismic Category I ator Air-operated modulating 10.3-16 Revision 1
ber per main steam line 6 l number of valves required per steam line for full power operation 6 eving capacity per valve at 110% of design pressure 1,370,000 lb/hr eving capacity per steam line at 110% of design pressure 8,240,000 lb/hr l relieving capacity, 2 lines at 110% of design pressure 16,480,000 lb/hr e size 8 x 10 (Dual Discharge) ign code ASME Code,Section III, Class 2, seismic Category I Set Pressure Relieving Capacity(a)
Valve Number (psig) (lb/hr)
S PL V030A(B) 1185 1,320,000 S PL V031A(B) 1197 1,340,000 S PL V032A(B) 1209 1,350,000 S PL V033A(B) 1221 1,360,000 S PL V034A(B) 1232 1,370,000 S PL V035A(B) 1232 1,370,000 l capacity, at 103% valve setpoint pressures, 2 lines 16,220,000 Based on system accumulation pressure of 3%, per Subsection NC-7512 of ASME Code,Section III, Division 1, 1989 Edition, Subsection NC, Class 2 components.
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Segment Material Specification n Steam Line am generator outlet to containment penetration SA-335 Gr. P11 seamless pipe tainment penetration to MSIV SA-335 Gr. P11 seamless pipe V to auxiliary/turbine building wall SA-335 Gr. P11 seamless pipe (a) ASTM A-335 Gr. P11 seamless pipe iliary/turbine building wall to equalization header (a) ASTM A-335 Gr. P11 seamless pipe nch lines to turbine stop valves n Feedwater Line dwater pump outlet to individual steam generator ASTM A-335 Gr. P-11 and ASTM A-106 Gr. B dwater lines(a) dwater heater bypass line(a) ASTM A-335 Gr. P-11 and ASTM A-106 Gr. B rt of individual steam generator feedwater lines to auxiliary/ ASTM A-335 Gr. P-11 ine building wall(a) iliary/turbine building wall to MFIV SA-335 Gr. P-11 V to containment penetration SA-335 Gr. P-11 tainment penetration to steam generator nozzle SA-335 Gr. P-11 Piping is beyond the ASME Section III piping boundary.
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(2.5-Inch and Larger)
Downstream of MSIV Maximum Valve Closure escription Steam Flow Shutoff Valve Time Actuator Comments (a) Air operator; fail Bypass valve is tripped ine bypass 998,000 lb/hr 16-in. globe 5 sec or less to each line (turbine bypass when tripped close closed on main steam enser; valve) closed isolation signal es total eating steam 242,000 lb/hr, 10-in. globe 5 sec or less(a) Air operators, fail Main steam flow to oisture each MSR (MSR reheat 2nd close reheater ceases rator stage steam (thermodynamically) ater (MSR), isolation valve, following turbine trip es total 2 each) flow ceases following valve closure on a main steam isolation signal steam 123,000 lb/hr 10-in. globe 10 sec or less Air operator; fail Main steam flow to ly to (isolation valve) close auxiliary steam system iary steam terminates following em isolation valve closure on a main steam isolation signal pressure 3,744,000 lb/hr 27.5-in. stop valve 5 sec or less(a) Hydraulically Main steam flow to high ne steam each line in each line operated from pressure turbine ly lines; electro-hydraulic ceases following stop es total turbine control valve closure on a system turbine trip steam 37,000 lb/hr 6-in. gate 60 sec or less Motor operator; Main steam flow to ly to turbine (isolation valve) manually operated turbine seals continues ds following a turbine trip; however, this steam flow is relatively small and has been considered in the steam line break analysis (Section 3.6)
Specified closure times are for safety analysis purposes; other system performance requirements may dictate more rapid closure.
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Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks MSIVs V040A(B) Isolates SG A(B) in the a. All but a. Fails closed or a. Position a. None; Plant goes to One MSIV is provided for normally open, fail event of a MSLB to DBA fails to open indication on or remains in a safe each steam line. Each MSIV closed with self prevent blowdown of on command main control shutdown condition redundantly activated from contained hydraulic more than one SG; room & remote separate safety-related operator Isolates containment in shutdown power divisions. Redundant conjunction with SG work-station backup provided by and main steam line downstream isolation valves.
inside containment Redundant containment isolation provided by SG and main steam line inside containment.
- b. DBA b. Fails to close b. Position indica- b. None; closure of Except upon ESF tion on main either MSIV or SGTR isolation control room & downstream valves signal remote prevent blowdown of shutdown more than one SG; workstation containment integrity is maintained by MSIV and either SG and steam line integrity inside containment or downstream valves.
- c. DBA- c. Fails to close c. Same as 1b c. None; limiting failure Redundant isolation provided SGTR on ESF is PORV failed open by downstream isolation isolation discharging to atmo- valves signal sphere. Termination of break flow occurs on automatic block valve closure plus PRHR actuation.
Continued break flow past MSIV precluded by redundant downstream isolation valves.
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Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks Main steam power Isolates SG A(B) in the a. All but a1. Fails to open a1. Position indica- a1. None; heat removal Redundant isolation provided operated relief valve event of a MSLB to DBA upon open tion on main available via steam by PORV and block valve via V233A(B) normally prevent blowdown from signal control room & dump or PRHR; separate safety-related closed fail closed, more than one SG in remote safety valves provide power divisions.
air- operated control conjunction with block shutdown over-pressure valve valve workstation; protection steam line high pressure a2. Fails open or a2. Position indica- a2. None; maximum flow fails to close tion on main less than DBA limit; on command control room & shutdown effected including remote with 1 PORV, PRHR, spurious shutdown or steam dump operation workstation; low SG level or SG pressure
- b. DBA b. Fails to close b. Position indica- b. None, redundant Dose analysis based on except tion on main isolation provided by failed open PORV with SGTR control room & PORV block valve subsequent block valve remote closure shutdown workstation; steam line low pressure alarm
- c. DBA - c. Fail to close c. Position indica- c. None; automatic SGTR tion on main redundant isolation control room & provided by PORV remote block valve.
shutdown Releases based on workstation; signal generation streamline low and closure time pressure alarm delay 10.3-21 Revision 1
Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks Main steam line Isolates SG A(B) in the a. All but a1. Same as 2.a1 a1. Same as 2.a1 a1. Same as 2.a1 Redundant steam line PORV block valve event of a MSLB to DBA isolation provided by PORV V027A(B), normally prevent blowdown from a2. Same as 2.a2 a2. Same as 2.a2 a2. Same as 2.a2 and block valve via separate open fail as is motor- more than 1 SG in safety-related power operated gate valve conjunction with PORV divisions. Redundant and provides containment isolation containment integrity in provided by SG and main conjunction with SG steam line inside and main steam line containment.
inside containment b. DBA b. Same as 2b b. Position b. Same as 2b; except indication on containment integrity SGTR main control is maintained by SG room & remote and main steam line shutdown inside containment workstation
- c. DBA c. Same as 2b c. Position c. None, automatic Dose analysis based on SGTR indication on redundant isolation failed open PORV isolated by main control of the PORV on low block valve. Releases room & remote steam line pressure equivalent.
shutdown workstation 10.3-22 Revision 1
Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks Main steam isolation Isolates SG A(B) in the a. All but a. Fails closed or a. Position a. Plant continues One MSIV bypass is provided bypass valve event of a MSLB to DBA fails to open indication on operation or goes to for each steam line. Each V240A(B) normally prevent blowdown of on command main control or remains at a safe bypass valve redundantly closed, fail closed more than one SG; room and shutdown condition activated from separate 1E air-operated valve isolates containment in remote power divisions. Redundant conjunction with SG shutdown backup provided by and main steam line workstation downstream isolation valves.
inside containment Redundant containment isolation provided by SG and main steam line inside containment.
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Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks
- b. DBA b. Fails to close b. Position b. None, closure of except upon ESF indication on either bypass valve SGTR isolation main control or down-stream signal room & remote isolation valves shutdown prevents blowdown workstation of more than 1 SG; containment integrity maintained by either MSIV bypass valve or SG/steam line integrity inside containment
- c. DBA- c. Fails to close c. Position c. None, limiting failure Redundant isolation provided SGTR on ESF indication on is PORV failed open by downstream isolation isolation main control discharging to valves signal room & remote atmosphere.
shutdown Termination of break workstation flow occurs on automatic block valve closure plus passive RHR actuation. Continued break flow past MSIV bypass precluded by redundant downstream isolation valves 10.3-24 Revision 1
Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks Main steam line Isolates containment in a. All but a. Fails closed or a. Position a. None; local drains drain isolation valve conjunction with SG DBA fails to open indication on provided to limit V036A(B), normally and main steam line on command main control moisture carry to open fail closed, air- inside containment. room & high turbine operated valve Isolates SG No. 1(2) in level alarm in the event of a MSLB to condensate prevent blowdown from drain pot more than one SG. b. DBA b. Fails to close b. Position b. None; closure of includi upon ESF indication on either series ng isolation main control isolation valves SGTR signal room provides steam line isolation; containment integrity is maintained by either condensate isolation or SG and main steam line inside containment 10.3-25 Revision 1
Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks Main steam line Isolates SG A(B) in the a. All but a. Fails closed or a. Position a. None; local drains drain control valve event of a main steam DBA fails to open indication on provided to limit V086A(B) normally line break to prevent on command main control moisture carryover closed, fail closed, blowdown to more than room and high to turbine air-operated valve one SG level alarm in condensate drain pot
- b. DBA b. Fails to close b. Position b. None, closure of includi upon ESF indication either series ng isolation provided on isolation valves SGTR signal main control provides steam line room isolation 10.3-26 Revision 1
Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks Main steam safety Protect SG A(B) and All a. Fails to open a. Higher a. None, 5 out of 6 valves V030A, associated steam line when required pressure and/ safety valves for SG V031A, V032A, up to MSIV from or water level A(B) still available V033A, V034A, overpressurization in SG A(B) with PORV available V035A (V030B, to supplement relief V031B, V032B, capacity; also, plant V033B, V034B, trip occurs on high V035B), normally steam generator closed level
- b. Spurious b. Low steam line b. None, maximum flow opening or pressure from one safety failure to reset valve less than DBA after opening analysis assumptions, Shutdown effected by other SG or PRHR 10.3-27 Revision 1
Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks Steam Generator Isolates blowdown from All a. Fails closed or a. Position a. None, blowdown is blowdown isolation SG A(B) upon PRHR fails to open indication on terminated but has V074A(B), normally actuation; isolates upon the main no safety impact open, fail closed air- containment in command control room operated valve conjunction with SG and zero flow and blowdown lines measured in inside containment blowdown system
- b. Fails open or b. Position b. None, redundant Redundant isolation is fails to close indication on isolation of provided for SG volume for on command main control blowdown via series PRHR operation via series room isolation valve valves; containment isolation V075A(B), via blowdown isolation or SG Containment and blowdown lines inside integrity is containment maintained by blowdown isolation or SG and blowdown lines inside containment 10.3-28 Revision 1
Plant Failure Effect on Description of Operating Method of Failure System Safety m Component Safety Function Mode Failure Mode(s) Detection Function Capability General Remarks Steam Generator Isolates blowdown from All a. Fails closed or a. Position a. None, blowdown is blowdown isolation SG A(B) upon PRHR fails to open indication on terminated but has V075A(B), normally actuation upon main control no safety impact open, fail closed air- command room and zero operated valve flow in blowdown system
- b. Fails open or b. Position b. None, redundant Redundant isolation is fails to close indication on isolation of provided for SG volume for on command main control blowdown via series PRHR operation via series room isolation valve valves V074A(B) 10.3-29 Revision 1
During Power Operation Condensate Parameters Normal Value ntrol tion conductivity due to strong acid anions at 25°C, S/cm 0.15 al cation conductivity at 25°C, S/cm 0.3 solved oxygen, ppb(a) 10 gnostic al organic carbon, ppb 100 dium, ppb <1 at 25°C > 9.0 ecific conductivity at 25°C, S/cm 2-6 atile pH adjustment chemical, ppb (b) es:
Air leakage should be reduced until total air ejected flow rate is less than 6 scfm.
pH, volatile pH adjustment chemical concentration and specific conductivity should correlate.
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During Power Operation Feedwater Parameters Normal Value ntrol at 25°C(a) > 9.5 drazine, ppb(c) 100 al iron, ppb 20 gnostic solved oxygen, ppb 2 tion conductivity due to strong acid anions at 25°C, S/cm 0.2 ecific conductivity at 25°C, S/cm 4.0 - 12.0 atile pH adjustment chemical, ppb (a) es:
pH, volatile pH adjustment chemical concentration and specific conductivity should correlate.
When operating with condensate polishers, the pH of an all-ferrous system can be controlled to a lower value of 9.2, with action required when pH < 9.2.
Values apply if hydrazine is used for oxygen scavenging. An alternate oxygen scavenger may be used with appropriate concentration limits.
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During Power Operation Steam Generator Blowdown Parameters Normal Value ntrol at 25°C(a) 9.0 - 9.5(b) al cation conductivity 0.8(c) dium, ppb 20 loride, ppb 20 fate, ppb 20 ca, ppb 300 gnostic tion conductivity due to strong acid anions at 25°C, S/cm 0.5 spended solids, ppb < 1000 ecific conductivity at 25°C, S/cm < 3.0 atile pH adjustment chemical, ppb (a) es:
pH, volatile pH adjustment chemical concentration and specific conductivity should correlate.
When operating with condensate polishers, the pH of an all-ferrous system can be controlled to a value of > 8.8.
Based on concentrations of total anionic species present, any inconsistencies between theoretical and measured values should be investigated.
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Cold Shutdown/Wet Layup Prior to Heatup Parameters Normal Value ( 200°F) ntrol at 25°C 9.8 - 10.5 9.3(a) drazine, ppm(b) 75 - 200 dium, ppb 1000 100 loride, ppb 1000 100 fate, ppb 1000 100 gnostic atile pH adjustment chemical - as uired to achieve pH range al organic carbon, ppb 100 s:
Conformance with pH guideline may be waived prior to achieving no load temperature and passing steam forward to turbine.
Values apply if hydrazine is used for oxygen scavenging. An alternate oxygen scavenger may be used with appropriate concentration limits.
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Value Power Value Prior to Power Escalation Prior to Parameters Normal Value Escalation Above 5% Above 30%(b) ntrol at 25°C(a) 9.0 -- 9.0 al cation conductivity at 25°C, 2.0 2.0 0.8
/cm solved oxygen, ppb 5 5 5 dium, ppb 100 100 20 loride, ppb 100 100 20 fate, ppb 100 100 20 ca, ppb -- -- 300 gnostic ecific conductivity at 25°C, 10
/cm(a) atile pH adjustment chemical(a) (a) ca, ppb 1000 s:
pH, volatile pH adjustment chemical concentration and specific conductivity should correlate.
This column is presented here for startup chemistry continuity with Table 10.3.5-1 since > 5% power denotes power operation. If escalation > 5% power is accomplished prior to meeting the values in this column, Action Level 1 requirements take effect.
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WLS 1&2 - UFSAR Figure 10.3.2-1 (Sheet 1 of 2)
Main Steam Piping and Instrumentation Diagram (Safety-Related System)
(REF) SGS 001 10.3-35 Revision 1
WLS 1&2 - UFSAR Figure 10.3.2-1 (Sheet 2 of 2)
Main Steam Piping and Instrumentation Diagram (Safety Related System)
(REF) SGS 002 10.3-36 Revision 1
WLS 1&2 - UFSAR Inside Turbine Building Figure 10.3.2-2 Main Steam System Diagram (REF) MSS 001 10.3-37 Revision 1
version system not in Sections 10.2 and 10.3.
4.1 Main Condensers main condenser functions as the steam cycle heat sink, receiving and condensing exhaust m from the main turbine and the turbine bypass system.
4.1.1 Design Basis 4.1.1.1 Safety Design Basis main condenser serves no safety-related function and therefore has no nuclear safety design is.
4.1.1.2 Power Generation Design Basis main condenser is designed to receive and condense the full-load main steamflow exhausted the main turbine and serves as a collection point for vents and drains from various components e steam cycle system.
main condenser is designed to receive and condense steam bypass flows up to 40 percent of t full load steam flow while condensing the remaining low-pressure turbine steam flow. This densing action is accomplished without exceeding the maximum allowable condenser kpressure for main turbine operation.
condenser hotwell is designed to store at the normal operating water level an amount of densate equivalent to at least three minutes of full load condensate system operating flow.
main condenser is designed to deaerate the condensate so that the dissolved oxygen content of condensate remains under 10 ppb during normal full power operation.
4.1.2 System Description main condenser is part of the AP1000 condensate system (CDS). The condensate system is cribed in Subsection 10.4.7 and shown in Figure 10.4.7-1. Classification of equipment and ponents is given in Section 3.2. Table 10.4.1-1 provides main condenser design data.
main condenser is a three-shell, single-pass, multipressure, spring-supported unit. Each shell is ted beneath its respective low-pressure turbine. The condenser is equipped with titanium or nless steel tubes. The titanium material provides good corrosion and erosion resisting properties.
shwater cooled plants do not require the high level corrosion and erosion resistance provided by ium; therefore, 304L, 316L, 904L, or AL-6X may be substituted if desired.
multipressure condenser, the condenser shells operate at slightly different pressures and peratures. Condensate that is condensed in the low pressure condenser shell drains through rnal piping to the high pressure (hottest) shell where it is slightly heated and mixed with densate of the high pressure shell. Condensate then flows through a single outlet to the suction of condensate pumps.
condenser shells are located below the turbine building operating floor and are supported on a ng-mounted foundation from the turbine building basemat. A rigid connection is provided between 10.4-1 Revision 1
4.1.2.1 System Operation ing normal power operation, exhaust steam from the low-pressure turbines is directed into the n condenser shells. The condenser also receives auxiliary system flows, such as feedwater ter vents and drains and gland sealing steam spillover and drains.
hotwell level controller provides automatic makeup or rejection of condensate to maintain a mal level in the condenser hotwells. On low level, the makeup control valves open and admit densate by vacuum draw to the hotwell from the condensate storage tank. On high-water level condensate reject control valves open to divert water from the condensate pump discharge to the densate storage tank. This rejection automatically stops when the hotwell level falls to within mal operating range. Rejection to the storage tank can be manually overridden upon an indication igh-hotwell conductivity to prevent transfer of contaminants into the condensate storage tank in event of a condenser tube failure.
nleakage and noncondensable gases contained in the turbine exhaust steam are collected in the denser and removed by the main condenser air removal system. The condenser air removal em is discussed further in Subsection 10.4.2.
rotect the condenser shells and turbine exhaust hoods from overpressurization, steam relief out diaphragms are provided in the low-pressure turbine exhaust hoods.
main condenser is capable of accepting up to 40 percent of full load main steam flow from the ine bypass system. Operation of the turbine bypass system is discussed in Subsection 10.4.4. In event of high condenser pressure or trip of the circulating water pumps, the turbine bypass valves prohibited from opening.
ribution headers are incorporated to protect the condenser tubes, feedwater heaters located in condenser neck, and other condenser components from turbine bypass or high-temperature ns entering the condenser shell.
main condenser interfaces with secondary sampling system (SSS) to permit sampling of the densate in the condenser hotwell. Also, grab sampling capability is provided for each condenser sheet. Should circulating water in-leakage occur, these provisions permit determination of which bundle has sustained the leakage. Steps may be taken to repair or plug the leaking tubes. This erformed by isolating the circulating water system from the affected water box. Plant power is uced as necessary. This will temporarily reduce condenser capacity by approximately 50 percent.
water box is then drained and the affected tubes are either repaired or plugged. Refer to section 10.3.5.5 for a discussion regarding action levels for abnormal secondary cycle chemistry ditions.
ndenser tube cleaning system performs mechanical cleaning of the circulating water side of the
- s. This cleaning, along with chemical treatment of the circulating water, reduces fouling and s to maintain the thermal performance of the condenser.
4.1.3 Safety Evaluation main condenser has no safety-related function and therefore requires no nuclear safety luation.
10.4-2 Revision 1
rating concentrations of radioactive contaminants, is included in Chapter 11. No hydrogen buildup e main condenser is anticipated. The failure of the main condenser and any resultant flooding will preclude operation of any essential system since no safety-related equipment is located in the ine building and the water cannot reach safety-related equipment located in Category I plant ctures.
4.1.4 Tests and Inspections condenser water boxes are hydrostatically tested after erection. Condenser shells are tested by pletely filling them with water and then testing by the fluorescent tracer method in accordance Reference 1. Tube joints are leak tested during construction.
4.1.5 Instrumentation Applications main condenser hotwell is equipped with level control devices for control of automatic makeup rejection of condensate. Condensate level in the condenser hotwell is indicated in the main trol room and alarms on high or low level.
denser pressure for each condenser shell is indicated in the main control room and alarms on level. Also, pressure instrumentation is provided to alarm prior to reaching the maximum turbine rating backpressure limit. Pressure devices are provided to trip the main turbine on high turbine aust pressure.
perature indication for monitoring condenser performance is provided.
4.2 Main Condenser Evacuation System n condenser evacuation is performed by the condenser air removal system (CMS). The system oves noncondensable gases and air from the main condenser during plant startup, cooldown, normal operation. This action is provided by liquid ring vacuum pumps.
4.2.1 Design Basis 4.2.1.1 Safety Design Basis condenser air removal system serves no safety-related function and therefore has no nuclear ty design basis.
4.2.1.2 Power Generation Design Basis The condenser air removal system removes air and noncondensable gases from the condenser during plant startup, cooldown, and normal operation from the steam side of the three main condenser shells and exhausts them into the atmosphere.
The system establishes and maintains a vacuum in the condenser during startup and normal operation by the use of liquid ring vacuum pumps.
10.4-3 Revision 1
ssification of equipment and components is given in Section 3.2.
air removal system consists of four liquid ring vacuum pumps that remove air and condensable gases from the three condenser shells during normal operation and provide denser hogging during startup. One vacuum pump is provided for each condenser shell, and one p is provided as a standby. The noncondensable gases, together with a quantity of vapor, are wn through the air cooler sections of condenser shells to the suction of the vacuum pumps. These condensables consist mainly of air, nitrogen, and ammonia. No hydrogen buildup is anticipated in system (see Subsection 10.4.1.3). Dissolved oxygen is present in the condensate and condenser well inventory. Only trace amounts of this oxygen are released in the condenser, and the amounts negligible compared to the amount of gas and vapor being evacuated by the system. Therefore, potential for explosive mixtures within the condenser air removal system does not exist.
circulating water system (CWS) provides the cooling water for the vacuum pump seal water heat hangers. The seal water is kept cooler than the saturation temperature in the condenser to ntain satisfactory vacuum pump performance.
noncondensable gases and vapor mixture discharged to the atmosphere are not normally oactive. However, it is possible for the mixture to become contaminated in the event of ary-to-secondary system leakage. Air inleakage and noncondensable gases removed from the denser and discharged by the vacuum pumps are routed to the turbine island vents, drains, and f system (TDS) and monitored for radioactivity. Upon detection of unacceptable levels of ation, operating procedures are implemented. A discussion of the radiological aspects of ary-to-secondary leakage, including anticipated release from the system, is included in pter 11.
discharge from the condenser air removal system has a connection for taking local grab ples. Connections also allow the installation of portable, continuous sampling equipment.
uld the condenser air removal system become inoperable, a gradual increase in condenser back sure would result from the buildup of noncondensable gases. This increase in backpressure ld cause a decrease in the turbine cycle efficiency. If the condenser air removal system remains erable, condenser backpressure increases to the turbine trip setpoint, and a turbine trip is ated. Loss of the main condenser vacuum causes a turbine trip but does not close the main steam ation valves. A loss of condenser vacuum incident is described in Subsection 15.2.5.
4.2.2.2 Component Description liquid ring vacuum pumps are supplied as packaged units. Major components in each package ude a vacuum pump, seal water heat exchanger, seal water pump, air/water separator, and aust silencer. Seal water is supplied to seal the clearances in the pump and also to condense or at the inlet to the pump. Seal water flows through the shell side of the seal water heat hanger and circulating water flows through the tube side. Seal water make up is provided by the densate system (CDS).
ng and valves are carbon steel. The piping is designed to ANSI B31.1.
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ps. The fourth pump is on standby.
ing normal plant operation, noncondensable gases are removed from the condenser by three uum pumps. If one pump trips, the condition is alarmed in the main control room, and the standby p is started.
4.2.3 Safety Evaluation condenser air removal system has no safety-related function and therefore requires no nuclear ty evaluation.
4.2.4 Tests and Inspections ing and inspection of the system is performed prior to plant operation. A performance test is ducted on each pump in accordance with Reference 2. In addition, the pumps are hydrostatically ed.
4.2.5 Instrumentation Applications effectiveness of the air removal system is indicated by monitoring condenser pressure, using rumentation described in Subsection 10.4.1.5. Vacuum pump status (on/off) is indicated in the n control room, and pump trips are alarmed.
metric flow indication is provided to monitor the quantity of exhausted noncondensable gases.
diation detector monitors the discharge of the condenser vacuum pumps through the turbine nd vents, drains, and relief system (TDS). The radiation detector is indicated and alarmed. For ess and effluent radiological monitoring and sampling systems, refer to Section 11.5.
4.3 Gland Seal System 4.3.1 Design Basis 4.3.1.1 Safety Design Basis gland seal system (GSS) serves no safety-related function and therefore has no nuclear safety ign basis.
4.3.1.2 Power Generation Design Basis The gland seal system prevents air leakage into and steam leakage out of the casings of the turbine-generator.
The system returns condensed steam to the condenser and exhausts noncondensable gases into the atmosphere via the turbine island vents, drains, and relief system.
The presence of radioactive contamination in the noncondensable gas exhausted from the gland seal condenser, is detected by a radiation monitor in the turbine island vents, drains, and relief system.
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gland seal system consists of the following items and assemblies:
Steam supply header Steam drains/noncondensable gas exhaust header Two motor driven gland seal condenser exhaust blowers Associated piping, valves, and controls Gland seal condenser Vent and drain lines quality group standards for the gland seal system are provided in Section 3.2. The gland seal em is shown in Figure 10.4.3-1.
4.3.2.2 System Operation annular space through which the turbine shaft penetrates the turbine casing is sealed by steam plied to the rotor glands. Where the packing seals against positive pressure, the sealing steam nection acts as a leakoff. Where the packing seals against vacuum, the sealing steam either is wn into the casing or leaks outward to a vent annulus maintained at a slight vacuum. The vent ulus receives air leakage from the outside. The air-steam mixture is drawn to the gland seal denser.
ling steam is distributed to the turbine shaft seals through the steam-seal header. This sealing m is supplied from either the auxiliary steam system (ASS), or from main steam (MSS), extracted ad of the high-pressure turbine control valves. Steam flow to the header is controlled by the m-seal feed valve which responds to maintain the steam-seal supply header pressure. The low high pressure turbine gland steam pressures are maintained by pressure regulating valves ided in both main steam and auxiliary steam system piping. Excess steam is returned to the 1 feedwater heaters via the spillover control valve which automatically opens to bypass excess m from the GSS.
ing the initial startup phase of turbine-generator operation, steam is supplied to the gland seal em from the auxiliary steam header which is supplied from the auxiliary boiler. At times other than al startup, turbine-generator sealing steam is supplied from the MSV and CV gland steam leak-the auxiliary steam system, or from main steam.
he outer ends of the glands, collection piping routes the mixture of air and excess seal steam to gland seal condenser. The gland seal condenser is a shell and tube type heat exchanger where steam-air mixture from the turbine seals is discharged into the shell side and condensate flows ugh the tube side as a cooling medium. The gland seal condenser internal pressure is maintained slight vacuum by a motor-operated blower. There are two 100-percent blowers mounted in allel. Condensate from the steam-air mixture drains to the main condenser while condensables are exhausted to the turbine island vents, drains, and relief system through a mon discharge line shared by the vapor extractor blowers.
mixture of noncondensable gases discharged from the gland seal condenser blower is not mally radioactive; however, in the event of significant primary-to-secondary system leakage due steam generator tube leak, it is possible to discharge radioactively contaminated gases. The dered discharge line vents to the turbine vents, drains, and relief system which contains a ation monitor for detection of radioactivity. Upon detection of unacceptable levels of radiation, 10.4-6 Revision 1
ure of the gland seal system normally results in no release of radioactivity to the atmosphere.
4.3.3 Safety Evaluation gland seal system has no safety-related function and therefore requires no nuclear safety luation.
4.3.4 Tests and Inspections system is tested in accordance with written procedures during the initial testing and operation gram. Since the gland seal system is in use and essential parameters are monitored during mal plant operation, the satisfactory operation of the system components demonstrates system rability.
4.3.5 Instrumentation Applications essure controller is provided to maintain the steam-seal supply header pressure by providing als to the steam-seal feed valve. Excess steam flow is handled by the gland spillover control e which discharges to the No. 1 feedwater heaters.
gland seal condenser is monitored for shell side pressure and internal liquid level.
ssure indication with appropriate alarm is provided for monitoring the operation of the system. A ation detector with an alarm is provided in the turbine island vents, drains, and relief system to ct radiation associated with primary-to-secondary side leakage in the steam generators.
4.4 Turbine Bypass System turbine bypass system provides the capability to bypass main steam from the steam generators e main condenser in a controlled manner to dissipate heat and to minimize transient effects on reactor coolant system during startup, hot shutdown, cooldown, and step-load reductions in erator load. The turbine bypass system is also called the steam dump system, and is part of the n steam system (MSS).
4.4.1 Design Basis 4.4.1.1 Safety Design Basis turbine bypass system serves no safety-related function and therefore has no nuclear safety ign basis. The nonsafety-related turbine bypass valves are credited in a single failure analysis to gate the event for those cases in which the rupture of the main steam or feedwater piping inside tainment is the postulated initiating event.
4.4.1.2 Power Generation Design Basis turbine bypass system has the capacity to bypass 40 percent of the full load main steam flow to main condenser.
turbine bypass system bypasses steam to the main condenser during plant startup and permits a ually controlled cooldown of the reactor coolant system to the point where the normal residual t removal system can be placed in service.
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surizer safety valves during: reactor trip from 100-percent power; and 100-percent load rejection urbine trip from 100-percent power without reactor trip.
4.4.2 System Description 4.4.2.1 General Description turbine bypass system is part of the main steam system and is shown on Figure 10.3.2-2. The em consists of a manifold connected to the main steam lines upstream of the turbine stop valves of lines from the manifold with regulating valves to each condenser shell.
capacity of the system, along with the NSSS control systems, provides the capability to meet the ign requirement bases specified in Subsection 10.4.4.1.2. For power changes less than or equal 10 percent change in electrical load, the turbine bypass system is not actuated; the total power nge is handled by the reactor power control, pressurizer level control, pressurizer pressure trol, and the steam generator level control systems described in Section 7.7. For load rejections ater than 10 percent but less than 50 percent, or a turbine trip from 50 percent power or less, the ine bypass system operates in conjunction with the same control systems used for the 10 percent ss load change to meet the design basis requirements specified in Subsection 10.4.4.1.2. For rejections greater than 50 percent power, the rapid power reduction system (described in tion 7.7) operates in conjunction with the previously mentioned control systems to meet the ign basis requirements. The rapid power reduction system is designed to rapidly reduce the lear power to a value that can be handled by the turbine bypass system. Certain transient ditions or system degradations beyond those of Subsection 10.4.4.1.2 may result in a reactor trip may result in the operation of the main steam power operated relief and safety valves.
4.4.2.2 Component Description turbine bypass valves are globe valves and are electropneumatically operated. The valves fail to osed position upon loss of air or electric signal. A modulating positioner responds to the electric al from the control system and provides an appropriate air pressure to the valve actuator for ulating the valve open.
enoid valves located in the air line to each bypass valve actuator serve as protective interlocks for ass valve actuation and for tripping the valve open or closed. One of the solenoid valves is rgized, when required, to bypass the modulating positioner and provide full air pressure to the ator diaphragm to quickly trip open the bypass valve. Other solenoid valves, when deenergized, k the air supply to the actuator and vent the actuator diaphragm; this action blocks the bypass e from opening, or closes the valve if opened.
of the blocking solenoid valves for each turbine bypass valve are redundant and block bypass e actuation upon low reactor coolant system Tavg. This minimizes the possibility of excessive tor coolant system cooldown. However, the low Tavg block can be manually bypassed for the ass valves that are designated as cooldown valves to allow operation during plant cooldown.
ther blocking solenoid valve prevents actuation of the bypass valve when the condenser is not ilable. This solenoid valve also prevents unblocking the steam dump valve when the condenser is ilable unless one of the following signals exist:
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4.4.3 System Operation turbine bypass system has two modes of operation:
Tavg control mode Pressure control mode Tavg control mode is the normal at-power control mode. The turbine bypass system is regulated he difference between the measured reactor coolant system average coolant temperature (Tavg) a Tavg setpoint derived from turbine first-stage impulse pressure. Two operational modes of the control mode are possible. The first mode is the load rejection steam dump controller, which ents a large increase in reactor coolant temperature following a large, sudden load decrease.
bine bypass valve control in conjunction with reactor power control results in a match between tor power and turbine load. The second mode is the plant trip steam dump controller, which matically defeats the load rejection steam dump controller following a reactor trip and provides a trolled rate of removal of decay heat, which in turn decreases reactor coolant system Tavg.
pressure control mode is manually selected and is used to remove decay heat during plant tup and cooldown. The difference between steam header pressure and a pressure setpoint is d to control the turbine bypass flow. The pressure setpoint is manually adjustable and is based on desired reactor coolant system temperature. The turbine bypass system is operated in the sure control mode when the plant is at no-load and there is no turbine load reference. There are e pressure control operational modes as follows:
Header pressure - control derived from the difference between header pressure and pressure setpoint Cooldown - control derived from the manually selected desired reactor coolant system cooldown rate and the target reactor coolant system temperature Manual - control derived from direct use of valve loading signals.
bypass valves are divided into two banks. The banks are opened sequentially; the second bank ts to open only after a demand signal that is greater than the full-open demand of the first bank is erated.
turbine bypass valves have two stroke control modes, modulate and trip open/close. If the and signal is greater than the full open demand for the particular bank of valves, a trip open and signal is generated. When the demand signal decreases below the full-open demand, the open demand clears and the valves return to the modulating mode. Additional description of m dump logic is given in Section 7.7.
pter 15 addresses credible single failures of the turbine bypass system. If the bypass valves fail-n, additional heat load is placed on the condenser. If this load is great enough, the turbine is ed on high condenser pressure. Ultimate overpressure protection for the condenser is provided urbine rupture discs. If the bypass valves fail-closed, the power operated relief valves (reference section 10.3.2.2.3) permit controlled cooldown of the reactor.
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s of the turbine bypass system are located in the turbine building.
failure of a turbine bypass high-energy line will not disable the turbine speed control system. The ine speed control system is designed in such a manner that its failure will cause a turbine trip.
itional information concerning speed control can be found in Subsection 10.2.2.3.
4.4.5 Inspection and Testing Requirements ore the system is placed in service, turbine bypass valves are tested to verify they function perly. The steam lines are hydrostatically tested to confirm leaktightness. System piping and es are accessible for inspection. No inservice inspection and testing is required except for the ine bypass valves which are included in the inservice program as discussed in Subsection 3.9.6.
4.4.6 Instrumentation Applications bine bypass controls are described in Section 7.7. Controls in the main control room are provided election of the system operating mode. Pressure indication and valve position indication are also ided in the main control room.
4.5 Circulating Water System 4.5.1 Design Basis 4.5.1.1 Safety Design Basis circulating water system (CWS) serves no safety-related function and therefore has no lear safety design basis.
4.5.1.2 Power Generation Design Basis circulating water system supplies cooling water to remove heat from the main condensers. The ulating water system and/or makeup water from the raw water system (RWS) supplies cooling er to the turbine building closed cooling water system (TCS) heat exchangers and the condenser uum pump seal water heat exchangers under varying conditions of power plant loading and ign weather conditions.
4.5.2 System Description 4.5.2.1 General Description ssification of components and equipment in the circulating water system is given in Section 3.2.
circulating water system and the cooling towers provide a heat sink for the waste heat exhausted the steam turbine. Additional cooling is supplied from the CWS through a tap in the main supply der for the TCS heat exchangers and the condenser vacuum pump seal water heat exchangers.
S design parameters are provided in Table 10.4.5-1.
circulating water system consists of four 33-1/3-percent-capacity circulating water pumps, two hanical draft cooling towers, and associated piping, valves, and instrumentation.
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4.5.2.2 Component Description culating Water Pumps four circulating water pumps are vertical volute, dry pit, single-stage, mixed-flow pumps driven by tric motors. Three pumps are normally operating with one pump on standby. The pumps are nted in a pump house with each pump in an individual pump bay. The pumps are connected to cooling towers by discharge flumes. The four pump discharge lines combine in a single main der, at the pump house, with two discharge lines to the turbine building which connect to the two water boxes of the condenser and supplies cooling water to the TCS and condenser vacuum p seal water heat exchangers. Each pump has a discharge motor operated butterfly valve and logs for suction isolation. This permits isolation of each pump for maintenance.
oling Towers two mechanical draft cooling towers are round counter-flow type cooling towers with an ingement-type drift eliminator system, and a bypass system capable of passing approximately half of the design circulating water flow to each tower directly to the cooling tower basin. Each ling tower has 16 induced draft fans located on the top deck of the cooling tower. The cooling er hot water distribution system has the capability to isolate each tower cell.
h cooling tower has a diameter of approximately 360 feet and a height of approximately 85 feet.
cooling towers are located on plant grade. The cooling towers are designed to cool the water to F with a hot water inlet temperature of 113°F.
cooling tower basins serve as storage for the circulating water inventory and allow bypassing of cooling tower during cold weather operations. The cooling tower nearest to the Unit 1 safety-ted structures, systems and components (SSCs) is located over 700 ft. west of the Unit 1 auxiliary ding. The cooling tower nearest to the Unit 2 safety-related SSCs is located over 600 ft. east of Unit 2 containment building. The cooling tower basins are below grade such that a basin failure not result in migration of water across the site. The site is graded to direct surface water flow y from the nuclear islands. A break in the cooling tower basin or the associated CWS piping will have an adverse effect on safety-related SSCs resulting from external plant flooding. The grading e site combined with the location and below-grade elevation of the cooling tower basins and the ociated CWS piping will preclude adverse interactions with safety-related SSCs.
ling Tower Makeup and Blowdown circulating water system makeup is provided by the raw water system. Makeup to and blowdown the CWS is controlled by the makeup and blowdown control valves. These valves, along with a l chemical feed system, provide chemistry control in the circulating water in order to maintain a scale-forming condition and limit biological growth in CWS components.
ing and Valves underground portions of the CWS piping are constructed of prestressed concrete piping. The ainder of the piping is carbon steel. Condenser water box drains allow the condenser to be ned to the turbine building sumps. Motor-operated butterfly valves are provided in each of the ulating water lines at their inlet to and exit from the condenser shell to allow isolation of portions of condenser. Control valves provide regulation of cooling tower blowdown and makeup.
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culating Water Chemical Injection ulating water chemistry is maintained by a local chemical feed skid at the CWS cooling tower.
ulating water system chemical feed equipment injects the required chemicals into the circulating er at the CWS cooling tower basin area. This maintains a noncorrosive, nonscale-forming dition and limits the biological film formation that reduces the heat transfer rate in the condenser the heat exchangers supplied by the circulating water system.
specific chemicals used within the system are determined by the site water conditions and are itored by plant chemistry personnel. The chemicals can be divided into six categories based n function: biocide, algaecide, pH adjuster, corrosion inhibitor, scale inhibitor, and a silt ersant. The pH adjuster, corrosion inhibitor, scale inhibitor, and dispersant are metered into the em continuously or as required to maintain proper concentrations. The biocide application uency may vary with seasons. Raw water treatment requirements are highly dependent on the er quality of the raw water supply which also experiences seasonal variations. The Broad River ides the source of make-up water for the CWS. The Lee Nuclear Station utilizes oxidizing mistry (e.g., sodium hypochlorite, sodium bromide, etc.) for the control of bio-fouling and the wth of algae. Sulfuric acid is added, as necessary, to adjust the pH of the CWS. During periods of river water turbidity or other conditions when deposition may lead to an increase in microfouling, dispersants such as polyacrylate may be used to minimize deposition within the CWS. Based on materials of construction for the CWS, Lee Nuclear Station has not identified a need for a osion inhibitor. Based on an effective pH control program and the constituency of the dissolved suspended solids found in the Broad River no need for a scale inhibitor has been identified.
e Energy operates the Catawba Nuclear Station which draws its intake water from Lake Wylie on Catawba River. The Catawba River drains the water shed immediately to the East of the Broad er Basin. Based on a similarity of the water chemistry produced by the two water sheds and the larity in construction of the cooling towers for these plants, Catawba Nuclear Station was used as odel for the design of the chemical treatment program for the CWS at Lee Nuclear Station.
ition of biocide and water treatment chemicals is performed by local chemical feed injection ering pumps and is adjusted as required. Chemical concentrations are measured through lysis of grab samples from the CWS. Cooling tower blowdown and pH control are utilized to ntain chemistry conditions that will minimize scaling and corrosion. Residual chlorine is measured onitor the effectiveness of the biocide treatment.
mical injections are interlocked with each circulating water pump to prevent chemical injection n the circulating water pumps are not running.
4.5.2.3 System Operation three normally operating circulating water pumps take suction from the cooling tower basin and ulate the water through the tube side of the main condenser with smaller flows to the TCS, the denser vacuum pump seal water heat exchangers, and back through the piping discharge work to the cooling towers. See Figure 10.4-201. The mechanical draft cooling towers cool the ulating water by discharging the water over a network of baffles in each tower. The water then through fill material to the basin beneath the tower and, in the process, rejects heat to the osphere.
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S temperature above 40°F while operating at partial load during periods of cold weather.
raw water system supplies makeup water to the basins of the cooling towers to replace water es due to evaporation, wind drift, and blowdown. A separate connection is provided between the S and CWS to initially fill the CWS piping. This line connects to the CWS downstream of the CWS p isolation valves.
ndenser tube cleaning system is installed to clean the circulating water side of the main denser tubes. Blowdown from the CWS is taken from the discharge of the CWS pumps and is harged to the blowdown sump and then to the Broad River.
circulating water system is used to supply cooling water to the main condenser to condense the m exhausted from the main turbine. If the circulating water pumps, the cooling towers, or the ulating water piping malfunction such that condenser backpressure rises above the maximum wable value, the main condenser will no longer be able to adequately support unit operation.
ldown of the reactor may be accomplished by using the power-operated atmospheric steam relief es or safety valves rather than the turbine bypass system when the condenser is not available.
sage of condensate from the main condenser into the circulating water system through a denser tube leak is not possible during power generation operation, since the circulating water em operates at a greater pressure than the condenser.
bine building closed cooling water in the TCS heat exchangers is maintained at a higher pressure the circulating water to prevent leakage of the circulating water into the TCS.
ling water to the condenser vacuum pump seal water heat exchangers is supplied from the CWS.
ling water flow from the CWS is normally maintained through all four heat exchangers to facilitate ing the spare condenser vacuum pump in service. Isolation valves are provided for the denser vacuum pump seal water heat exchanger cooling water supply lines to facilitate ntenance.
all circulating water system leaks in the turbine building will drain into the waste water system.
ge circulating water system leaks due to pipe failures will be indicated in the control room by a of vacuum in the condenser shell. The effects of flooding due to a circulating water system re, such as the rupture of an expansion joint, will not result in detrimental effects on safety-related ipment since there is no safety-related equipment in the turbine building and the base slab of the ine building is located at grade elevation. Water from a system rupture will run out of the building ugh a relief panel in the turbine building west wall before the level could rise high enough to se damage. Site grading will carry the water away from safety-related buildings.
cooling towers are located so that collapse of the towers have no potential to damage ipment, components, or structures required for safe shutdown of the plant.
4.5.3 Safety Evaluation circulating water system has no safety-related function and therefore requires no nuclear safety luation.
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t power generation. Performance, hydrostatic, and leakage tests associated with nstallation and preoperational testing are performed on the circulating water system. The tem performance and structural and leaktight integrity of system components are onstrated by continuous operation.
4.5.5 Instrumentation Applications rumentation provided indicates the open and closed positions of motor-operated butterfly valves e circulating water piping. The motor-operated valve at each pump discharge is interlocked with pump so that the pump trips if the discharge valve fails to reach the open position shortly after ting the pump.
al grab samples are used to periodically test the circulating water quality to limit harmful effects to system piping and valves due to improper water chemistry.
ssure indication is provided on the circulating water pump discharge lines. A differential pressure smitter is provided between one inlet and outlet branch to the condenser. This differential sure transmitter is used to determine the frequency of operating the condenser tube cleaning em (CES).
perature indication is supplied on the individual branch CWS inlet headers to the TCS heat hanger trains. This temperature is also representative of the inlet cooling water temperature to the n condenser.
w element is provided on the common discharge line from the TCS heat exchangers to allow itoring of the total flow through the TCS heat exchangers. Flow measurement for the raw water eup to the cooling towers and for the blowdown for the cooling towers is also provided.
el instrumentation provided in the circulating water cooling tower basins activates makeup flow the RWS to the basins of the cooling towers when required. Level instrumentation also unciates a low-water level in the pump structure and a high-water level in the basins of the ling towers.
circulating water chemistry is controlled by the cooling tower blowdown and chemical addition, to ntain the circulating water with an acceptable Stability Index range of approximately 6 to 7. The em accomplishes this by regulating the blowdown valve.
control approach is to allow the makeup water to concentrate naturally to its upper limit.
visions are made to add chemicals for pH control.
cycles of concentration at which the cooling towers are operated is dependent on the quality of cooling tower makeup water. The blowdown of the cooling towers is discharged to the blowdown p and ultimately to the Broad River.
itoring of the circulating water system is performed through the data display and processing em. Control functions are performed by the plant control system. Appropriate alarms and lays are available in the control room. See Chapter 7.
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urities from the condensate system during plant startup, hot standby, power operation with ormal secondary cycle chemistry, safe shutdown, and cold shutdown operations.
4.6.1 Design Basis 4.6.1.1 Safety Design Basis condensate polishing system serves no safety-related function and therefore has no nuclear ty-related design basis.
4.6.1.2 Power Generation Design Basis power generation design bases are to:
Remove corrosion products, dissolved solids and other impurities from the condensate system and maintain a noncorrosive environment within the condensate, feedwater and steam generator systems Provide polishing capacity for processing one-third of the maximum condensate flow in a sidestream arrangement Provide polishing capability during normal startup and shutdown operations of the plant Provide for plant operation with a continuous condenser tube leak of .001 gpm or a faulted leak of 0.1 gpm until repairs can be completed or until an orderly shutdown is achieved 4.6.2 System Description condensate polishing system is used during operating modes of startup, hot standby, power ration with abnormal secondary cycle chemistry, safe shutdown, and cold shutdown.
ssification of components in the CPS is identified in Section 3.2. The major components for the densate polishing system are described below. The condensate polishing system is shown in re 10.4.6-1.
p Bed Mixed Resin Polisher polisher vessel is constructed of carbon steel with a protective rubber lining on the inside of the sel. Leachable sulphur of the rubber lining is less than 20 ppb. Level indication (site glass) is ided.
in Trap resin trap is located in the effluent piping of the vessel. Differential pressure across the trap is itored.
nt Resin Tank spent resin tank is constructed of carbon steel with an interior protective rubber lining. It is used torage of exhausted or spent resin prior to shipping offsite for regeneration or disposal.
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ansfer the resin to the vessel.
4.6.3 System Operation condensate polishing system cleans up the condensate during startup to meet condensate and water system water chemistry specifications as described in Subsection 10.3.5. The condensate em is recirculated to the hotwell during startup until the desired water quality is attained.
densate system startup operation is described in Subsection 10.4.7. Utilization of the condensate shing system during startup assists in minimizing the startup duration of the plant.
ing power operation, the condensate polishers are used only when abnormal secondary cycle ditions exist. This allows for continued operation of the plant with a continuous condenser tube of 0.001 gpm or a faulted leak of 0.1 gpm until repairs can be made or until an orderly tdown is achieved. The condensate polisher flow is controlled by the condensate polisher bypass e.
austed or spent resin is removed from the vessel and replaced with new or regenerated resin.
in replacement requires the polisher vessel to be out of service. Spent resin is transferred directly the polisher vessel to a truck or to the spent resin tank until it can be removed offsite. Spent densate polishing resin will normally be nonradioactive and not require any special packaging r to disposal. In the event of radioactive contamination of the resin in a vessel, temporary lding is installed (if required). Radioactive resin is transferred directly from the condensate shing vessel or from the spent resin tank to a temporary processing unit. Radiation monitors ociated with the steam generator blowdown system, the steam generator system (main steam),
the turbine island vents, drains and relief system provide the means to determine if the ondary side is radioactively contaminated. Subsection 11.4.2 describes waste management of oactively contaminated resin. A spill containment barrier is provided to contain spent resin tank or densate polisher vessel contents in the event of a tank failure. The spill containment barrier is a surrounding the area containing the spent resin tank and condensate polisher vessel with cient height to contain the contents of a full tank or vessel.
procedures for radiation protection and the handling and processing of radwaste are addressed hapters 11 and 12. Shielding design is described in Section 12.3.
n removal of the exhausted resin from the polisher vessel, the vessel is rinsed and the new resin aced in the vessel using the resin addition hopper and eductor. After the new cation and anion ns are placed in the vessel, demineralized water is added until the water level is just above the n bed. Compressed air from the plant service air system is injected up through the resin bed to ize and thoroughly mix the resins. Prior to plant startup, a new resin bed is rinsed and resin ormance is verified, with flow through the vessel discharged to the waste water system. The sher vessel is then placed in operation or on standby.
4.6.4 Safety Evaluations condensate polishing system has no safety-related function and therefore requires no nuclear ty evaluation.
4.6.5 Tests and Inspections condensate polishing system is operationally checked prior to plant startup to verify proper tioning of the polisher vessels and associated instrumentation and controls.
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rumentation provides a control signal to the condensate bypass valve which maintains sufficient through the polisher vessel for optimum performance. The polisher is removed from service n: 1) a high differential pressure exists across the polisher vessel, 2) the ion exchange resin acity becomes exhausted as evidenced by a high effluent conductivity, or 3) at the completion of a determined volume through-put. The resin trap is monitored for high differential pressure and an m indicates the need to backwash the trap.
4.7 Condensate and Feedwater System condensate and feedwater system provides feedwater at the required temperature, pressure, flow rate to the steam generators. Condensate is pumped from the main condenser hotwell by condensate pumps, passes through the low-pressure feedwater heaters to the feedwater pumps, is then pumped through the high-pressure feedwater heaters to the steam generators.
condensate and feedwater system is composed of components from the condensate system S), main and startup feedwater system (FWS), and steam generator system (SGS). The startup water system is described in Subsection 10.4.9.
4.7.1 Design Basis 4.7.1.1 Safety Design Basis safety-related portion of the system is required to function following a design basis accident A) to provide containment and feedwater isolation, as discussed below, for the main lines routed containment.
portion of the feedwater system from the steam generator inlets outward through the tainment up to and including the main feedwater isolation valves (MFIVs) is constructed in ordance with the requirements of ASME Code,Section III for Class 2 components and is igned to seismic Category I requirements. The portion of the feedwater system from the main water isolation valve (MFIV) inlets to the piping restraints at the interface between the auxiliary ding and the turbine building is constructed in accordance with the requirements of ASME Code, tion III for Class 3 components and is designed to seismic Category I requirements.
system provides redundant isolation valves, as described below, for the main feedwater lines ed into containment. The isolation valves close after receipt of an isolation signal in sufficient time mit the mass and energy release to containment consistent with the containment analysis ented in Chapter 6.
The safety-related portions of the feedwater system are designed to remain functional after a safe shutdown earthquake (SSE) and to perform their intended function of isolating feedwater flow following postulated events.
The safety-related portions of the feedwater system are protected from wind and tornado effects, as described in Section 3.3; flood protection is described in Section 3.4; missile protection is described in Section 3.5; protection against dynamic effects associated with the postulated rupture of piping is described in Section 3.6; seismic protection is described in Section 3.7; environmental design is described in Section 3.11; and fire protection is described in Section 9.5.
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feedwater system to be constructed in accordance with ASME Code,Section III, Class 3 requirements is also designed and configured to accommodate inservice inspection in accordance with ASME Code,Section XI.
The condensate and feedwater system classification is described in Section 3.2. The control functions and power supplies are described in Chapters 7 and 8.
For a main feedwater or main steam line break (MSLB) inside the containment, the condensate and feedwater system is designed to limit high energy fluid to the broken loop.
High energy line break for piping not qualified for leak before break (LBB) criteria is discussed in Subsection 3.6.3.
Double valve main feedwater isolation is provided via the main feedwater control valve (MFCV) and main feedwater isolation valve (MFIV). Valves fail closed on loss of actuating fluid. Both valves are designed to close automatically on main feedwater isolation signals, an appropriate engineered safety features (ESF) isolation signal, within the time established within the Technical Specification, Section 16.1.
The MFCVs provide backup isolation to their respective containment isolation valves in order to terminate feedwater flow. The MFCVs are located in the auxiliary building in piping designed to ASME Code,Section III, Class 3 seismic Category I requirements. These valves are components of the steam generator system (SGS).
For a steam generator tube rupture event, positive and redundant isolation is provided for the main feedwater system (MFIV and MFCV) with ESF isolation signals generated by the protection and safety monitoring system.
4.7.1.2 Power Generation Design Basis The condensate and feedwater system provides a continuous feedwater supply to the two steam generators at the required pressures and temperatures for steady-state and anticipated transient conditions.
Plant operation is possible at 100-percent power with one condensate pump out of service, and approximately 70-percent power with one booster/main feedwater pump assembly out of service.
Plant operation is possible at greater than 70-percent power with one feedwater heater string out of service.
The feedwater and condensate pumps and pump control system are designed so that loss of one booster/main feedwater pump assembly or one condensate pump does not result in trip of the turbine-generator or reactor.
The pumps and other system components are designed so that the condensate, feedwater booster and feedwater pumps are protected from running with very low net positive suction heads without tripping on short transient low levels in a hotwell or deaerator tank.
The condenser hotwell is designed to store, at the normal operating water level, an amount of condensate equivalent to at least three minutes of full-load condensate system operating flow.
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The system has the capability of accommodating the necessary changes in feedwater flow to the steam generators with the steam pressure increase resulting from a 100-percent load rejection.
The booster/main feedwater pumps are tripped simultaneously with the feedwater isolation signal to close the main feedwater isolation valves. In addition, the same isolation signal closes the isolation valve in the cross connect line between the main feedwater pump discharge header and the startup feedwater pump discharge header.
A check valve, which acts on reverse pressure differential, is provided in the main feedwater line to each steam generator between the MFIV and the containment penetration. The check valve is designed to withstand the forces encountered when closing after a main feedwater line rupture. The valves perform no safety-related function but will serve to prevent blowdown from more than one steam generator during feedline break while the appropriate engineered safety features signal is generated to isolate using the MFIV and MFCV. During normal or upset conditions, the function of these check valves is to prevent reverse flow from the steam generators whenever the feedwater system is not in operation.
4.7.2 System Description 4.7.2.1 General Description condensate and feedwater system is shown schematically in Figure 10.4.7-1, and in re 10.3.2-1. Classification of equipment and components is given in Section 3.2.
condensate and feedwater system supplies the steam generators with heated feedwater in a ed steam cycle using regenerative feedwater heating. The condensate and feedwater system is posed of the condensate system, the main feedwater system, and portions of the steam erator system. The condensate system collects condensed steam from the condenser and ps condensate forward to the deaerator. The feedwater system takes suction from the deaerator pumps feedwater forward to the steam generator system utilizing high-pressure main feedwater ps. The steam generator system contains the safety-related piping and valves that deliver water to the steam generators. The condensate and feedwater systems are located within the ine building, and the steam generator system is located within the auxiliary building and tainment.
main portion of the feedwater flow originates from condensate pumped from the main condenser well by the condensate pumps. The main condenser hotwell receives makeup from the densate storage tank. (Refer to Subsection 9.2.4 for a description of the condensate storage em.) The condensate passes in sequence through: the condensate polishing system or densate polishing bypass (described in Subsection 10.4.6); the gland steam condenser; three gs of low-pressure heaters, each string consisting of a No. 1 and No. 2 low-pressure heater; two gs of low-pressure heaters No. 3 and No. 4; the No. 5 open low pressure heater (deaerator); the e parallel booster/main feedwater pumps; and two strings of high-pressure heaters, No. 6 and
- 7. Feedwater is pumped to the plants two steam generators through each generators respective element, control valve, feedwater isolation valve, and check valve. The balance of the plants water flow is provided by drains from the main steam system moisture separator reheater, drains the No. 6 and No. 7 feedwater heaters, and steam condensed in the deaerator. These flows are ected in the deaerator and pumped forward in the feedwater cycle. A portion of the condensate 10.4-19 Revision 1
ing plant startup, three recirculation paths facilitate system cleanup and adjustment of water lity prior to initiating feed to the steam generators. These cleanup loops are designed for roximately 33 percent of design condensate flow and include a hotwell recirculation loop, a erator recirculation loop, and a third recirculation loop from downstream of the No. 7 feedwater ters. Steam is provided to the deaerating feedwater heater from the auxiliary steam supply em to preheat the feedwater to over 200°F during the initial cleanup and startup recirculation rations. This preheating action, along with chemical addition, minimizes formation of iron oxides e condensate system.
condensate polishing system is described in Subsection 10.4.6 and may be in service or assed. Each of the two main feedwater lines to the two steam generators contains a feedwater element, a main feedwater control valve, a main feedwater isolation valve, and a check valve.
turbine island chemical feed system (CFS) described in Subsection 10.4.11 is provided to inject xygen scavenging agent and a pH control agent into the condensate pump discharge nstream of the condensate polishers and an oxygen scavenging agent and pH control agent tream of the feedwater booster pump suction. Injection points are shown in Figure 10.4.7-1.
ing normal power operation, the addition of an oxygen scavenging agent and pH control agent to condensate system downstream of the condensate demineralizers is in automatic control, with ual control available. The added chemicals control pH according to the condensate and water system chemistry requirements and establish an oxygen scavenging agent residual in the water system. The oxygen scavenger agents are hydrazine and carbohydrazide. The pH control nts are dimethylamine and methoxypropylamine gen scavenging and ammoniating agents are selected and utilized for plant secondary water mistry optimization following the guidance of NEI 97-06, Steam Generator Program Guidelines ference 201). The EPRI Pressurized Water Reactor Secondary Water Chemistry Guidelines are wed as described in NEI 97-06.
oss connection from the main feedwater pump discharge header to the startup feedwater header ws any booster/main feedwater pump to supply feedwater to the startup feedwater control valves.
startup feedwater system is described in Subsection 10.4.9. Thus, feedwater from the deaerator age tank can be supplied by the booster/main feedwater pumps through the startup feedwater nections to the steam generators during hot standby, plant startup and low power operation. A ck valve in the cross connection piping prevents the startup feedwater pumps from supplying the n feedwater header, and a nonsafety-related isolation valve in the cross connection piping matically closes upon the feedwater isolation signal that trips the main feedwater pumps.
ndensate and feedwater failure analysis for safety-related components is presented in le 10.4.7-1. Occurrences which produce an increase in feedwater flow or decrease in feedwater perature result in increased heat removal from the reactor coolant system which is compensated y control system action, as described in Subsection 10.4.7.5. Events which produce the opposite ct (i.e., decreased feedwater flow or increased feedwater temperature) result in reduced heat sfer in the steam generators. Normally, automatic control system action is available to adjust water flow to prevent excess energy accumulation in the reactor coolant system, and the easing reactor coolant temperature provides a negative reactivity feedback, reducing reactor er. In the absence of normal control action, either the high-outlet temperature or the high-sure trips of the reactor protection system are available to provide reactor safety. Loss of all water is examined in Section 15.3.
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could trap steam and lead to water hammer. The horizontal pipe length from the main nozzle to downward turning elbow of each steam generator is minimized.
rations and maintenance procedures include precautions, when appropriate, to minimize the ntial for steam and water hammer, including:
Prevention of rapid valve motion Process for avoiding introduction of voids into water-filled lines and components Proper filling and venting of water-filled lines and components Process for avoiding introduction of steam or heated water that can flash into water-filled lines and components Cautions for introduction of water into steam-filled lines or components Proper warmup of steam-filled lines Proper drainage of steam-filled lines The effects of valve alignments on line conditions 4.7.2.2 Component Description feedwater system is constructed in accordance with the requirements of ASME Code,Section III Class 2 components and seismic Category I requirements from the steam generator out through MFIVs. From upstream of the MFIV to the restraint at the interface between the auxiliary building turbine building, the system is constructed in accordance with ASME Code,Section III for ss 3 components and seismic Category I requirements. The remaining piping of the condensate feedwater system meets ANSI B31.1 requirements. Safety-related feedwater piping materials described in Subsection 10.3.6.
dwater Piping dwater is supplied to each of the two steam generators by a main feedwater line during normal ration. Each of the lines is anchored at the auxiliary building/turbine building interface, and has cient flexibility to provide for relative movement of the steam generators resulting from thermal ansion.
feedwater system and steam generator design minimize the potential for waterhammer and sequent effects. Details are provided in Subsection 5.4.2.2. Feedwater piping analysis considers following factors and events in the evaluation:
Steam generators with top feed ring design (BTP ASB 10-2)
Main feedwater check valves due to line breaks (BTP MEB 3-1)
Spurious isolation or feedwater control valve trips Pump trips Deaerator regulating flow control valve trip Local feedwater piping, anchors, supports, and snubbers, as applicable 10.4-21 Revision 1
down from the steam generators in the event of a feedwater pipe rupture. The main feedwater ck valve provides backup isolation. In the event of a secondary side pipe rupture inside the tainment, the MFIVs limit the quantity of high energy fluid that enters the containment through the en loop and limit cooldown. The MFCV provides backup isolation to limit cooldown and high rgy fluid addition.
h MFIV is a bidirectional wedge type gate valve composed of a valve body that is welded into the em pipeline. The MFIV gate valve is provided with a hydraulic/pneumatic actuator. The valve ator is supported by the yoke, which is attached to the top of the body. The valve actuator sists of a hydraulic cylinder with a stored energy system to provide emergency closure of the ation valve. The energy to operate the valve is stored in the form of compressed nitrogen tained in one end of the actuator cylinder. The MFIV is maintained in a normally open position by
-pressure hydraulic fluid. For emergency closure, redundant solenoids are energized resulting in high-pressure hydraulic fluid being dumped to a fluid reservoir.
feedwater isolation functional diagram is shown in Figure 7.2-1. To provide safety function ation, the redundant actuation solenoid valves are powered from separate Class 1E power sions. Redundant control and indication channels are provided for each of the isolation valves.
visions are made for inservice inspection of the isolation valves.
dwater Control Valves MFCVs are air-operated control valves with the dual purpose of controlling feedwater flow rate ell as providing backup isolation of the feedwater system. The valve body is a globe design.
ts and trim are of an erosion resistant material. The design allows for removal and replacement of ts and other wearing parts.
feedwater control valves (MFCVs) automatically maintain the water level in the steam generators ng operational modes. Positioning of the main feedwater control valve during normal operation is function of an automatic feedwater level control system using a refinement of a standard three ment control scheme. The three-element control system maintains feedwater flow equal to the m flow, and steam generator water level is used as an input to trim feedwater flow and maintain grammed water level. Refinements on the standard control are made by varying the flow demand e valve based on the actual stem position.
e event of a secondary side pipe rupture inside the containment, the main feedwater control es provide a redundant isolation to the MFIVs to limit the quantity of high energy fluid that enters containment through the broken loop. For emergency closure of the MFCV, a solenoid is nergized to close the valve in sufficient time to limit the mass and energy release to containment sistent with the containment analysis presented in Chapter 6.
dwater Check Valves h main feedwater line includes a check valve installed outside containment. During normal and et conditions, the check valve prevents reverse flow from the steam generator whenever the water pumps are tripped. In addition, the closure of the valves prevents more than one steam erator from blowing down in the event of feedwater pipe rupture. The check valve is designed to blowdown from the steam generator and to prevent slam resulting in potentially severe pressure es due to water hammer. The valves are designed to withstand the closure forces encountered ng the normal, upset and faulted conditions. Rapid closure associated with a feedline rupture s not impose unacceptable loads on the steam generator or the steam generator system. The ure of the valves provides for isolation of the steam generators in the event of a feedwater line 10.4-22 Revision 1
nt Main Condenser a description of main condenser, refer to Subsection 10.4.1.
ndensate Pumps three 50-percent, vertical, multistage, centrifugal condensate pumps are motor-driven and rate in parallel. Valving allows individual pumps to be removed from service. Pump capacity ts normal, full-power requirements with two of the three pumps in operation.
ndensate Regulating Valves main condensate flow to the deaerator is regulated by two parallel, split-ranged, pneumatically rated control valves. Condensate is regulated to maintain the level in the deaerator storage tank.
ing startup and low loads, the smaller valve modulates to control flow while the larger valve ains closed. As load increases, the larger valve modulates to control flow.
-Pressure Feedwater Heaters se heaters are shell and tube heat exchangers with the heated condensate flowing through the side and the extraction steam condensing on the shell side. Parallel strings of low-pressure water heaters No. 1 and 2 are located in each of three condenser necks. Feedwater heaters 3 and 4 are also parallel strings of heaters. The closed low-pressure feedwater heaters use drain lers. The cascaded drains from the heaters are dumped to their respective condenser shell.
ain line from the heater allows direct discharge of the heater drains to the condenser in the event normal drain path is not available or flooding occurs in the heater.
low-pressure feedwater heater shells are carbon steel, and the tubes are stainless steel.
erator deaerator is a tray type, horizontal shell, direct contact heater with a horizontal storage tank.
densate enters the deaerator from the top. The heating steam flows upward and is condensed, raises the temperature of the condensate to near saturation, liberating dissolved gases from the densate. Condensate drains from the deaerator into the storage tank. Noncondensables are ted from the top of the deaerator and flow through an orifice and valve assembly to the main denser.
iliary steam from the auxiliary steam supply system (see Subsection 10.4.10) is supplied to the erator during recirculation conditions and maintains the pressure in the tank above atmospheric.
steam heats the condensate during cleanup and recirculation for liberation of noncondensables.
iliary steam is also automatically supplied to the deaerator following turbine trip to assist in ntaining deaerator pressure above atmospheric.
shell of the deaerator storage tank is carbon steel. Most of the internals of the deaerator, uding the tray assemblies, vent condenser, and spray valves, are stainless steel.
gh level dump line and control valve provide overflow protection to the deaerator storage tank.
ing high level conditions, water from the deaerator storage tank is drained to the main condenser.
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ugh the tubes and extraction steam condenses in the shell. The No. 6 and No. 7 heaters drain low-pressure heater No. 5 (deaerator).
ain line from each heater allows direct discharge of the heater drains to the condenser in the nt the normal drain path is not available or flooding occurs in the heater.
high-pressure feedwater heater shells are carbon steel, and the tubes are stainless steel.
dwater Booster Pumps feedwater booster pumps are horizontal, centrifugal pumps located upstream of the main water pumps. Each feedwater booster pump takes suction from the deaerator storage tank and ps forward to its associated main feedwater pump. An electric motor drives both the booster p and the main feedwater pump. The booster pump is driven by one end of the motor shaft and main pump is driven by the other end through a mechanical speed increaser. The booster pump, rating at a lower speed than the main feedwater pump, boosts the pressure of feedwater from the erator to meet the net positive suction head requirements of the main feedwater pump.
n Feedwater Pumps three main feedwater pumps operate in parallel and take suction from the associated feedwater ster pumps. The combined discharge from the main feedwater pumps is supplied to the No. 6
-pressure feedwater heater, the No. 7 high-pressure feedwater heater, and then to the steam erator system. Each main feedwater pump is a horizontal, centrifugal pump driven, through a hanical speed increaser, by the motor that drives the associated feedwater booster pump.
ation valves allow each of the booster/main feedwater pumps to be individually removed from ice while continuing power operations at reduced capacity.
mp Recirculation Systems imum flow control systems automatically protect the pumps in the condensate and feedwater em from pumping below the minimum flow rate to prevent pump damage. The condensate ps recirculate to the main condenser. The booster/main feedwater pumps recirculate to the erator storage tank.
4.7.2.3 System Operation 4.7.2.3.1 Plant Startup ing plant startup, the condensate and feedwater system operates in several different figurations. These are described in Subsections 10.4.7.2.3.1.1 through 10.4.7.2.3.1.4.
4.7.2.3.1.1 Hotwell Recirculation hotwell recirculation flow path is used to recirculate flow from downstream of the gland steam denser to the main condenser to facilitate cleanup of the condensate inventory in the main denser hotwell. This flow path also provides a minimum flow for operation of the gland steam denser and the condensate pumps. With a condensate pump operating, the setpoint of the rculation valve is manually adjusted to achieve the desired flow rate for cleanup of condensate.
densate polishing equipment is aligned and placed in service to attain the required water quality.
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eeds the required minimum. The recirculation valve remains on standby and opens, as essary, if system flow drops below minimum.
e the hotwell recirculation loop is placed in service and cooling is available to the gland steam denser, sealing steam may be applied to the turbine glands. Condenser vacuum can then be wn using condenser air removal equipment.
4.7.2.3.1.2 Deaerator Recirculation deaerator recirculation flow path is used to recirculate condensate from downstream of the erator storage tank to the main condenser to facilitate cleanup of condensate. Deaerator rculation is initiated by adjusting the recirculation flow control valve from the main control room to ieve the desired flow rate. Condensate is recirculated for cleanup of water quality using the densate polishing equipment. Auxiliary steam can be admitted to the deaerator to heat the densate for liberation of noncondensable gases.
4.7.2.3.1.3 Third Stage Recirculation third stage of condensate/feedwater recirculation during the plant heatup cycle can begin when densate and feedwater has been sufficiently cleaned and deaerated at the feedpump suction.
w is initiated by adjusting the recirculation flow control valve from the main control room to achieve desired flow rate. Feedwater is recirculated from downstream of the No. 7 feedwater heaters to main condenser for cleanup and deaeration of the condensate and feedwater inventory.
4.7.2.3.1.4 Plant Heatup condenser hotwell makeup and overflow valves are enabled and function automatically during plant heatup cycle to maintain condensate inventory. Condensate is returned to the condensate age tank as volume expansion occurs, and makeup occurs as needed for system losses.
ing heatup, the main condenser is available to accept turbine bypass steam from the main steam em, as well as various drains, vents, and condensate/feedwater recirculation flow.
condensable gases are removed in the air removal sections of the main condenser and through deaerator vents. Control and monitoring of water quality and chemistry are accomplished by ration of the condensate polishing equipment, chemical feed system, and secondary sampling ipment as required.
steam generators are filled, as required, either by the startup feedwater pumps using water from condensate storage tank, or alternatively by a booster/main feedwater pump using water from the erator storage tank and supplied through cross connect piping to the startup feedwater control es. The steam generators are drained, as required, through the steam generator blowdown em.
ing the initial stages of plant heatup, one condensate pump operates as necessary to maintain l in the deaerator storage tank. Either one or both startup feedwater pumps, or one booster/main water pump, is in operation when feeding water to the steam generators. The feedwater pumps se operate on minimum flow recirculation as necessary while maintaining the water level of the m generators.
dwater is controlled by the startup feedwater control valves (SFCVs) which are operated either ually from the control room or automatically in accordance with steam generator level demand.
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4.7.2.3.2 Power Operation operating condensate pump supplies sufficient condensate flow to the deaerator during initial er operation and at low-power levels. As power escalates, a second condensate pump is started r to exceeding approximately 50-percent, full-load condensate flow. The third condensate pump standby.
condensate regulating valves to the deaerator automatically maintain the level of the deaerator age tank. If condensate flow to the deaerator drops below the minimum required flow for ration of the gland steam condenser or the condensate pumps, the hotwell recirculation valve to condenser opens to provide the minimum flow.
condensables are removed by the deaerating section of the main condenser and by the erator. Condensate polishing, chemical feed and condensate sampling are performed, as ded, to maintain water quality.
normal operating conditions between 0- and 100-percent load, system operation is primarily matic. Automatic level control systems control the water levels in the feedwater heaters and the denser hotwell. Feedwater heater water levels are controlled by modulating flow control valves.
el control valves in the makeup line to the condenser from the condensate storage tank and in the rn line to the condensate storage tank control the level in the condenser hotwell.
ing reactor startup and at very low power levels, feedwater is supplied to the steam generators ugh the startup feedwater control valves using either the startup feedwater pumps drawing from condensate storage tank, or a booster/main feedwater pump drawing from the deaerator storage
. Refer to Subsection 10.4.9 for a description of the startup feedwater system. If the startup water pumps are initially in use, transfer is made to a booster/main feedwater pump prior to eeding the capacity limit of the startup pumps. As power increases, startup feedwater continues e supplied through the startup feedwater control valves until control of feedwater is automatically sferred from the startup feedwater control valves to the main feedwater control valves. The tup feedwater control valves close, and the main feedwater control valves open to supply main water to the steam generators and maintain steam generator level. Position indication is ilable in the main control room for the main and startup feedwater control valves. As power alates, booster/main feedwater pump minimum flow recirculation automatically decreases as the ard flow to the steam generators increases. The second and third booster/main feedwater pumps brought into operation as required.
densate flow to the steam generator blowdown heat exchangers is normally automatically trolled. In the automatic mode, condensate flow is regulated to control the steam generator down outlet temperature from the blowdown heat exchangers.
-percent step load and 5-percent/minute ramp changes are accommodated without major effect e condensate and feedwater system. The system is capable of providing the necessary water flow to the steam generators with the steam pressure increase resulting from a
-percent load rejection.
4.7.2.3.3 Plant Shutdown ration during power descent is largely the reverse of power ascent. As power is decreased, one e two operating condensate pumps may be stopped; one or two booster/main feedwater pumps 10.4-26 Revision 1
owing reactor trip or other reactor shutdown, feedwater is supplied through the startup feedwater trol valves to maintain steam generator inventories. Decay heat and sensible heat are removed team release via the steam dump system to the condenser to cool the plant and bring it to safe tdown. During this time, startup feedwater is supplied either by an operating booster/main water pump drawing from the deaerator storage tank, or by the startup feedwater pumps drawing the condensate storage tank.
4.7.2.3.4 Emergency Operation e event of a design basis event (with or without normal ac power supplies available), feedwater ation signals are generated as required. The MFIVs and MFCVs automatically close on receipt of isolation signals. The condensate and feedwater system is not required to supply feedwater er accident conditions to effect plant shutdown or to mitigate the consequences of an accident.
ever, the startup feedwater system is expected to be available as a nonsafety-related system to ide a source of feedwater for the steam generators. Also, the condenser may be available to ept turbine bypass steam for secondary side heat removal. Coordinated operation of the startup water system (Refer to Subsection 10.4.9), if available, and the main steam supply system fer to Section 10.3) removes the primary loop sensible heat and reactor decay heat.
4.7.3 Safety Evaluation The safety-related portions of the main feedwater system are located in the containment and auxiliary buildings. These buildings are designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other natural phenomena. Sections 3.3, 3.4, 3.5, 3.7, and 3.8 provide the bases for the adequacy of the structural design of these buildings.
The safety-related portions of the main feedwater system are designed to remain functional after a design basis earthquake. Subsection 3.7.2 and Section 3.9 provide the design loading conditions that are considered. Sections 3.5, 3.6, and Subsection 9.5.1 describe the analyses to provide confidence that a safe shutdown, as outlined in Section 7.4, is achieved and maintained.
The main feedwater system safety-related functions are accomplished by redundant means.
A single, active component failure of the safety-related portion of the system does not compromise the safety function of the system. Table 10.4.7-1 provides a failure analysis of the safety-related active components of the feedwater system. Power is supplied from onsite power systems, as described in Chapter 8.
Preoperational testing of the safety-related portion of the condensate and feedwater system is performed as described in Chapter 14. Periodic inservice functional testing is done in accordance with Subsection 10.4.7.4. Section 6.6 provides the ASME Code,Section XI requirements that are appropriate for the feedwater system.
Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. The controls and power supplies necessary for the safety-related functions of the condensate and feedwater system are Class 1E, and are described in Chapters 7 and 8.
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discussed in Subsection 7.3.1.2.6.
The MFIVs are provided with solenoids supplied by redundant power divisions. Failure of either of the power divisions or solenoids does not prevent closure of the MFIV. Releases of radioactivity from the condensate and feedwater system, resulting from the main feedwater line break, are minimal because of the negligible amount of radioactivity in the system under normal operating conditions. Following a steam generator tube rupture, the main steam isolation system and the passive residual heat removal heat exchanger reduce accidental releases, as discussed in Section 10.3 and Chapter 15. Detection of radioactive leakage into and out of the system is facilitated by area radiation monitoring (described in Subsection 12.3.4), process radiation monitoring (described in Section 11.5), and steam generator blowdown sampling (described in Subsection 10.4.8).
For a steam generator tube rupture event, positive and redundant isolation is provided for the main feedwater (MFIV and MFCV) with isolation signals generated by the protection and safety monitoring system (PMS). Refer to Subsection 7.3.1.2.6.
Prevention and mitigation of feedline-related water hammer is accomplished through operation of the feedwater delivery system as described in Subsection 5.4.2.2. The feedwater piping at the steam generators is sloped so that it does not drain into the steam generators.
These features help avoid the formation of a steam pocket in the feedwater piping which, when collapsed, could create a hydraulic instability.
4.7.4 Tests and Inspections 4.7.4.1 Preoperational Valve Testing MFIVs and feedwater control valves are checked for closing time prior to initial startup.
4.7.4.2 Preoperational Pipe Testing main feedwater lines from the steam generator to the anchor at the interface between the turbine ding and the auxiliary building are classified as ASME Code,Section III, Class 2 and 3 and mic Category I piping. The Class 2 portions of the main feedwater system piping are tested and ected to the requirements of ASME Code,Section III, Class 2 piping. The portion of the piping ween the containment penetration and the anchor, which is considered as the break exclusion e described in Subsection 3.6.2, is subjected to 100-percent volumetric inspection at installation.
4.7.4.3 Preoperational System Testing operational testing of the condensate and feedwater system is performed as described in pter 14. Tests described in Subsection 14.2.9.1.7, under item c) of General Test Method and eptance Criteria satisfy BTP (AS) 10-2. Additional testing of the feedwater system is conducted ng startup testing as described in Subsection 14.2.10.4.18.
4.7.4.4 Inservice Inspections performance, and structural and leaktight integrity of the condensate and feedwater system ponents are demonstrated by continuous operation.
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4.7.5 Instrumentation Applications condensate and feedwater instrumentation, is designed to facilitate automatic operation, remote trol, and indication of system parameters.
itioning of the main feedwater control valve during normal operation is the function of an matic feedwater level control system using a refinement of a standard three element control eme. For each steam generator, the three-element control system maintains feedwater flow equal e steam flow, and steam generator water level is used as an input to trim feedwater flow and ntain programmed water level. Refinements on the standard control are made by varying the e flow demand based on actual stem position (accounting for varying Cv versus lift) dynamic line es and feedwater temperature. A flow venturi is located in each feedwater line to provide signals he three element feedwater control system. Feedwater control is further described in section 7.7.1.8.
main feedwater pumps are tripped by manual actuation or feedwater isolation described in tion 7.3. A flow element in the discharge piping from each main feedwater pump provides a flow al for control of the associated minimum flow recirculation valve.
el transmitters, located at the deaerator storage tank, control deaerator level. Condensate flow to deaerator is regulated by two split ranged control valves upstream of the deaerator. During mal power generation, the valves are regulated by a three element control system; total feedwater is used as a feed forward demand signal, and the control is trimmed by measured feedback of l condensate flow and deaerator storage tank level.
e event a feedwater heater experiences a sizable tube leak or a feedwater heater water level trol valve fails closed, the main turbine is protected from failure resulting from flooding on the shell of a feedwater heater and subsequent water induction into the moving turbine blades. This is omplished by automatic closure of the isolation valve in the steam extraction line to that heater opening the high-level dump control valve that dumps the heater excess drains to the condenser.
heaters that do not have extraction line isolation valves, condensate isolation valves are matically closed to isolate condensate flow to the heater tubes.
total water volume in the condensate and feedwater system is maintained through automatic eup and rejection of condensate to the condensate storage tank. The system makeup and ction are controlled by the condenser hotwell level controller. Level transmitters are provided at condenser hotwell for use by the hotwell level controller. The system water quality requirements automatically maintained through the injection of an oxygen scavenging agent and a pH control nt into the condensate system. The pH control agent and oxygen scavenging agent injection is trolled by pH and the level of oxygen scavenging agent residual in the system which are tinuously monitored by the secondary sampling system.
rumentation, including pressure indication, flow indication, and temperature indication, required monitoring the system, is provided in the control room.
4.8 Steam Generator Blowdown System steam generator blowdown system (BDS) assists in maintaining acceptable secondary coolant er chemistry during normal operation and during anticipated operational occurrences of main denser inleakage or primary to secondary steam generator tube leakage. It does this by removing 10.4-29 Revision 1
4.8.1 Design Basis 4.8.1.1 Safety-Related Design Basis safety-related portion of each blowdown line is part of the steam generator system (SGS).
cts of a blowdown system line break are discussed in Section 3.6. The safety-related design es are as follows:
The system is provided with two isolation valves on each steam generator. These valves isolate the secondary side of the steam generators to preserve the steam generator inventory. This action provides a heat sink for a safe shutdown or design basis accident mitigation. It also provides isolation of nonsafety-related portions of the system.
The steam generator blowdown system safety-related functions can be performed assuming a single, active component failure coincident with the loss-of-offsite or onsite power.
Piping and valves from the steam generator up to and including the containment isolation valve, the first valve on the outboard side of the containment, are designed to ASME Code,Section III, Class 2, and seismic Category I requirements. The blowdown system piping and valves from the outlet of the containment isolation valve up to and including pipe anchors located at the auxiliary building wall are designed in accordance with ASME Code,Section III, Class 3, and seismic Category I requirements.
The safety-related portion of the system is designed to withstand the effects of a safe shutdown earthquake. The safety-related portion of the system is protected from the effects of natural phenomena and is capable of performing its intended function following postulated events such as fire, internal missile, and pipe break.
The safety-related portion of the system is designed so that a single, active failure in the blowdown system will not result in:
- Loss-of-coolant accident
- Loss of integrity of steam lines
- Loss of the capability to effect a safe reactor shutdown
- Transmission of excessive loading to the containment pressure boundary.
The portion of the steam generator system that is constructed in accordance with ASME Code,Section III, Class 2 and 3, requirements is provided with access to welds and removable insulation, as required for inservice inspection in accordance with ASME Code,Section XI. (See Subsection 10.4.8.4.)
The safety-related portion of the blowdown system is designed to function in the normal and accident environments identified in Subsection 3.11.1.
The safety-related portion of the blowdown system is designed as described in Section 3.6 with regard to high-energy pipe break location and evaluation.
4.8.1.2 Power Generation Design Basis steam generator blowdown system draws secondary water from each steam generator via the down line and processes this water as required to:
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Cool down the steam generator for inspection and maintenance purposes Establish and maintain steam generator wet layup conditions during plant shutdown periods Drain the secondary side of the steam generators for maintenance 4.8.2 System Description 4.8.2.1 General Description res 10.4.8-1 and 10.3.2-1 illustrate the steam generator blowdown system piping and rumentation design. Classification of equipment and components for the steam generator down system is given in Section 3.2. The system consists of two blowdown trains, one for each m generator. A crosstie is provided to process blowdown from both steam generators through heat exchangers during high capacity blowdown from one steam generator.
blowdown water is extracted from each steam generator from a location just above the tube et. The blowdown from each steam generator is cooled by a regenerative heat exchanger, and is controlled and pressure reduced by blowdown flow control valves. To recover the thermal rgy, the condensate system provides cooling for the heat exchangers. To recover the blowdown
, each blowdown train has an electrodeionization (EDI) demineralizing unit which removes urities from the blowdown flow. Downstream of the electrodeionization units, both trains combine a common header that contains a relief valve for providing overpressure protection for the low-sure portion of the system. A back-pressure control valve maintains pressure in the system ween the flow control valve and the back-pressure control valve.
ump is provided to drain the secondary side of the steam generator. The pump is also used for rculation during low-pressure steam generator wet layup and cooling operations.
tem isolation from the steam generator under normal operating and transient conditions is omplished by the two isolation valves located in the auxiliary building. The valves close on ation of the passive residual heat removal system, containment isolation, or high blowdown em radiation, temperature, or pressure.
4.8.2.2 System Operation various modes of operation are described in the following subsections.
4.8.2.2.1 Plant Startup le low-pressure conditions exist in the steam generator, the blowdown flow control valves are assed, and the steam generator recirculation/drain pump is used to discharge the blowdown flow e condensate system (CDS) for processing and recovery.
he steam generator pressure increases, the blowdown rate is limited to about 200 gpm or less by tripping and then isolating the recirculation pump. When the steam generator pressure reaches roximately 125 psig, the blowdown flow control valves are throttled to control the blowdown rate.
en the desired operational blowdown rate is achieved, the valves are placed in automatic ration. The condensate control valves, which control the supply of cooling water to the heat hangers, are adjusted during startup. When the condensate outlet temperature increases to a et level, the condensate control valves are placed in automatic operation. The cooling water flow 10.4-31 Revision 1
4.8.2.2.2 Normal Operation effectiveness of the blowdown system in controlling water chemistry depends upon the down rate. The normal blowdown flowrate varies from a minimum of about 0.06 percent to a imum of about 0.6 percent of maximum steaming rate. During normal operation, when the urities are low, the expected blowdown rate is approximately 0.1 percent of maximum steaming (about 30 gpm total, or 15 gpm per steam generator), which maximizes the detection sensitivity ondenser tube leakage. The blowdown flow is cooled by the heat exchanger, and the pressure is uced by the flow control valves. The blowdown fluid is processed through the electrodeionization s and discharged to the condensate system (condenser hotwell) for reuse.
e event of main condenser tube leakage, when the concentration of impurities is high, the down rate is increased to a maximum of approximately 0.6 percent of the maximum steaming (about 186 gpm total, or 93 gpm per steam generator at standard conditions). Normal operation recover the blowdown flow through the condensate system. However, blowdown with high levels mpurities can be discharged to the waste water system.
back-pressure control valve is preset to a pressure which prevents flashing of the blowdown fluid e electrodeionization units.
blowdown flow and the electrodeionization waste stream (brine) flow are both continuously itored for radioactivity from steam generator primary to secondary tube leakage. If such oactivity is detected, the liquid radwaste system (WLS) is aligned to process the blowdown and trodeionization waste effluent. If radioactivity reaches a preset high level, the blowdown flow trol valves and the isolation valves automatically close.
system operates normally under automatic control, except for flow control adjustments or flow changes.
4.8.2.2.3 Steam Generator Cooling blowdown system can be operated to cool the steam generator for inspection and maintenance n the steam generator pressure is less than 125 psig. The blowdown is recirculated to the steam erators by the steam generator recirculation/drain pump, bypassing the blowdown flow control es, and the electrodeionization units. The steam generator recirculation/drain pump is aligned by ning manual valves upstream and downstream of the pump. The pump recirculates the steam erator water through the heat exchangers at a total flowrate of approximately 200 gpm (100 gpm steam generator at standard conditions). The condensate control valves are manually controlled rovide the cooling for the heat exchangers.
4.8.2.2.4 Steam Generator Wet Layup system can be operated to establish and maintain wet layup conditions in the steam generators ng plant shutdown periods. During wet layup operation, water is circulated through the steam erators in the same manner as for steam generator cooling, except that the heat exchangers are required. To maintain the correct pH and oxygen concentration in the secondary water, chemicals added to the recirculation flow via the turbine island chemical feed system (CFS). (See section 10.4.11 for chemical feed system details.)
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rculation/drain pump and bypassing the flow control valves and the electrodeionization units.
l drain flowrate is approximately 200 gpm at standard conditions. During this mode of operation, blowdown discharge maybe sent to the waste water system, the liquid radwaste system or the densate system.
4.8.2.2.6 Steam Generator Tube Sheet Flush system can be operated for a short time at a total flowrate of approximately 1.85 percent of the imum steaming rate (about 280 gpm) from one steam generator. To accommodate the high flow, blowdown from one steam generator is isolated and the flow from the other steam generator is ed through both heat exchanger trains at a rate of approximately 140 gpm per train. The down flow control valves and the blowdown electrodeionization units are bypassed during this ration. The blowdown flow is controlled by throttling the flow control valve bypass isolation valves ch are in series with a flow restricting orifice. The blowdown is discharged to the waste water em (WWS).
4.8.2.2.7 Emergency Operation wdown system isolation is actuated on low steam generator water levels. The isolation of steam erator blowdown provides for a continued availability of the steam generator as a heat sink for ay heat removal in conjunction with operation of the passive residual heat removal system and startup feedwater system.
4.8.2.3 Component Description escription of the major steam generator blowdown system components is provided in this section.
4.8.2.3.1 Blowdown Regenerative Heat Exchangers regenerative heat exchangers are provided, one for each steam generator blowdown train. The t exchangers are located in the turbine building at the base slab elevation.
4.8.2.3.2 Blowdown Flow Control Valves blowdown flow control valves are provided, one for each steam generator blowdown train. The trol valves are capable of controlling the flow and pressure over the range of normal operating ditions.
4.8.2.3.3 Recirculation/Drain Pump centrifugal pump is provided for use during operating modes when steam generator pressure is 4.8.2.3.4 Pressure Control Valve ackpressure control valve is provided to maintain appropriate system backpressure, within the rating range of blowdown flows, and prevent flashing within the low pressure section of the em when the blowdown is discharged to the condenser hotwell.
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matically isolate the blowdown system in the event of abnormal conditions within the blowdown em, the reactor coolant system, or the main steam system. The valves are air-operated globe es that fail close on loss of air or actuating power. See Section 7.3 for a description of the matic control functions on the valves.
first isolation valve provides a containment isolation function in addition to redundant isolation of blowdown system. The valves close on an engineered safeguards actuation signal and provide tainment integrity in conjunction with the steam generator and blowdown line inside containment.
valves are active, ASME Code,Section III, Safety Class 2, seismic Category I.
isolation valves provide for redundant isolation of the blowdown system upon actuation of the sive residual heat removal system, low (narrow range) steam generator level, or abnormal ditions in the blowdown system. Each isolation valve receives an actuation signal from the ection and safety monitoring system (PMS) upon passive residual heat removal actuation to erve steam generator inventory. The valves also close upon receiving a low (narrow range) water l signal to preserve steam generator inventory. Additionally, the valves receive a high radiation al, high temperature signal, and high pressure signal, indicating abnormal conditions in the down system and actuating automatic isolation of the system. The second isolation valves are ve, ASME Code,Section III, Safety Class 3, seismic Category I.
valves are located outside containment within the auxiliary building and are attached to seismic egory I piping.
4.8.2.3.6 Electrodeionization Unit trains of electrodeionization demineralizing units are provided for the steam generator blowdown em electrodeionization. The electrodeionization unit in each train is configured in a stack ngement. The stack normally contains numerous pairs of stacked membranes. One cell pair sists of an ion-diluting flow (product) channel located between a cation and an anion membrane an ion concentrating (brine) flow channel located alternately between the cell pairs. A dc ntial is maintained across the electrode plates which are located on opposite ends of the stacked mbranes. Ion exchange resin is contained within the product flow channel, acting as an ion ctive media in the electrodeionization process. Isolation valves are provided for each stack to w for maintenance of a stack.
ter, upstream of the electrodeionization stack in each train, removes suspended solids and iculate matter from electrodeionization influent. Electrodeionization effluent flows through a resin which collects resin fines and small particulates which pass through the unit.
h electrodeionization unit includes one centrifugal brine pump which maintains a constant flow in closed loop brine system and flushes ionic impurities from the brine channels in the stack. A small entage of blowdown in the brine process is used to control impurity concentration. This trodeionization brine blowdown waste stream is directed to the waste water system (WWS) or liquid radwaste system (WLS).
electrodeionization stacks are located in the turbine building and in a shielded area. The area no drain. Anionic and cationic resins are contained within the electrodeionization stacks. These ns are not consumed or exhausted in the electrodeionization process. Radiation monitors ociated with the steam generator blowdown system, steam generator system (main steam), and condenser air removal system provides the means to determine if the secondary side is oactively contaminated.
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r prolonged use, the electrodeionization units will be replaced. If they are not radioactively taminated, they require no special packaging and may be disposed as clean solid waste. If they radioactively contaminated, they will be dewatered, the nozzles blocked and packaged for sport according to DOT regulations. Packaged electrodeionization units may be stored in the waste Building.
4.8.2.4 Instrumentation Applications w, pressure, temperature, and radioactivity indicators with alarms monitor system operation.
essure, temperature, or radioactivity reach a high level setpoint, an alarm is annunciated and the down flow control valves and upstream isolation valves are automatically closed.
w elements and transmitters measure and control blowdown flow from the steam generators. The elements are located downstream of the blowdown flow control valves.
perature instrumentation monitors the temperature of blowdown fluid upstream and downstream ach heat exchanger. The heat exchanger outlet temperature controls heat exchanger cooling er flow as well as the blowdown flow to limit high temperature blowdown fluid to the trodeionization unit.
ioactivity detection instrumentation detects and monitors the presence of radioactivity in the bined blowdown stream from both trains. A radiation element is located in the common header tream of the recovered blowdown three-way valve. This three-way valve normally directs the vered blowdown flow to the condenser. When recovery of the blowdown fluid is not possible, the is diverted to the waste water system. Upon detection of significant levels of radioactivity via a ation transmitter alarm, the steam generator blowdown flow is diverted to the liquid radwaste em for processing. A second radioactive detection instrument is located on the waste stream of electrodeionization blowdown. Similarly, a three-way valve normally directs this trodeionization brine blowdown to the waste water system. With detection of significant levels of oactivity, the brine blowdown is diverted to the liquid radwaste system.
4.8.3 Safety Evaluation Each blowdown line is provided with redundant safety-related valves that isolate the secondary side of the steam generator to preserve the steam generator inventory. The inventory is maintained as a heat sink for sensible and decay heat removal from the reactor coolant system.
The steam generator blowdown system safety-related functions are accomplished by redundant means. A single, active component failure within the safety-related portion of the system does not compromise the safety-related function of the system. Power is supplied by the Class 1E dc power system as described in Chapter 8.
Section 3.2 delineates the quality group classification. The controls and power supplies necessary for safety-related functions of the steam generator blowdown system are Class 1E, and are described in Chapters 7 and 8.
The safety-related portion of the steam generator blowdown system are located in the containment and auxiliary buildings. These buildings and areas are designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other natural phenomena. Sections 3.3, 3.4, 3.5, 3.7, and 3.8 provide the bases for the adequacy of the 10.4-35 Revision 1
No single failure coincident with loss of offsite power compromises the safety-related functions of the system or will result in:
- Loss-of-coolant accident
- Loss of integrity of steam lines
- Loss of the capability to effect a safe reactor shutdown
- Transmission of excessive loading to the containment pressure boundary.
Component or functional redundancy is provided so that safety-related functions can be performed, assuming a single, active failure coincident with loss of ac power.
The steam generator blowdown system is initially tested in accordance with the program described in Chapter 14. Periodic inservice functional testing is done in accordance with Subsection 10.4.8.4. Section 6.6 provides the ASME Code,Section XI requirements that are appropriate for the safety-related portions of the steam generator blowdown system.
The safety-related components of the steam generator blowdown system are qualified to function in normal, test, and accident environmental conditions. The environmental qualification program is provided in Section 3.11.
Discussions of high energy pipe break locations and evaluation of effects are provided in Subsections 3.6.1 and 3.6.2.
Subsection 6.2.3 delineates the criteria and compliance with applicable requirements and the criteria for the containment isolation provisions.
The failure modes and effects analysis for the steam generator blowdown system is provided in Table 10.3.3-1.
4.8.4 Inspection and Testing Requirements 4.8.4.1 Preservice Testing/Inspection blowdown system components are tested and inspected during plant startup as a part of the ervice test program as discussed in Chapter 14. The steam generator blowdown systems ty-related functions are designed to include the capability for testing. This includes operation of licable portions of the protection system. The safety-related components of the system (valves piping,) are designed and located to permit preservice and inservice inspections to the extent tical.
steam generator blowdown lines within the containment and the auxiliary building are visually volumetrically inspected at installation as required by ASME Code,Section XI preservice ection requirements.
4.8.4.2 Inservice Testing/Inspection performance and structural leaktight integrity of system components are demonstrated by mal operation.
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ruments and controls are calibrated during startup and recalibrated, as necessary, to maintain em operation within its design specifications.
4.9 Startup Feedwater System startup feedwater system supplies feedwater to the steam generators during plant startup, hot dby and shutdown conditions, and during transients in the event of main feedwater system vailability. The startup feedwater system is composed of components from the AP1000 main and tup feedwater system (FWS) and steam generator system (SGS).
4.9.1 Design Basis 4.9.1.1 Safety Design Basis safety functions of the startup feedwater system are to provide for containment isolation, steam erator isolation and feedwater isolation following design basis events requiring these actions.
tainment isolation is provided to limit radioactive releases to the environment following design is events that result in the releases of radioactivity to the containment. Steam generator isolation rovided to limit rapid blowdown to a single steam generator following a feedwater or steam line ak. Feedwater isolation limits excessive feedwater flow to the steam generators to limit mass and rgy releases to containment to limit excessive RCS cooldown and to limit steam generator rfill.
portion of the startup feedwater system from the steam generator inlets outward through the tainment up to and including the startup feedwater isolation valves (SFIVs) is constructed in ordance with the requirements of ASME Code,Section III for Class 2 components and is igned to seismic Category I requirements. The portion of the startup feedwater system from the tup feedwater isolation valve inlets to the piping restraints at the interface between the auxiliary ding and the turbine building is constructed in accordance with the requirements of ASME Code, tion III for Class 3 components and is designed to seismic Category I requirements.
startup feedwater system provides redundant isolation valves, as described below, for the tup feedwater lines routed into containment. The isolation valves close after receipt of an isolation al in sufficient time to limit the mass and energy release to containment consistent with the tainment analysis presented in Section 6.2.
The safety-related portions of the startup feedwater system are designed to remain functional after a safe shutdown earthquake (SSE) and to perform their intended function of isolating startup feedwater flow following postulated events.
The safety-related portions of the startup feedwater system are protected from wind and tornado effects, as described in Section 3.3; flood protection is described in Section 3.4; missile protection is described in Section 3.5; protection against dynamic effects associated with the postulated rupture of piping is described in Section 3.6; seismic protection is described in Section 3.7; environmental design is described in Section 3.11; and fire protection is described in Section 9.5.
The portion of the startup feedwater system to be constructed in accordance with ASME Code,Section III, Class 2 requirements is provided with access to welds and removable insulation for inservice inspection, in accordance with ASME Code,Section XI.
The portion of the startup feedwater system to be constructed in accordance with ASME 10.4-37 Revision 1
operation.
The startup feedwater system quality group classification codes are identified in Section 3.2.
The control functions and power supply are described in Chapters 7 and 8.
Double valve startup feedwater isolation is provided by the startup feedwater control valve and the startup feedwater isolation valve. Both valves are designed to close on a startup feedwater isolation signal, an appropriate engineered safeguards features (ESF) signal as indicated on Figure 7.2-1. The startup feedwater isolation valve also serves as a containment isolation valve. The startup feedwater control valve fails closed on loss of air. See Section 7.3. Backflow in the startup feedwater line results in closure of the startup feedwater check valve.
For a steam generator tube rupture event, positive and redundant isolation is provided for the startup feedwater system (startup feedwater isolation signal and startup feedwater control valve), with isolation signals generated by the protection and safety monitoring system.
4.9.1.2 Power Generation Design Basis During normal plant startup, shutdown or hot standby, feedwater can be supplied through the startup feedwater control valves to the steam generators using either a booster/main feedwater pump drawing water from the deaerator storage tank (refer to Subsection 10.4.7),
or using the startup feedwater pumps drawing water from the condensate storage tank.
In the event of loss of the main feedwater system, the startup feedwater pumps automatically supply feedwater to the steam generators for heat removal from the reactor coolant system.
The heat removal function of the startup feedwater system is nonsafety-related. The startup feedwater system avoids the need for actuation of the safety-related passive core cooling system. Following the transient, the system refills the steam generators and supports reactor coolant system cooldown.
One operating startup feedwater pump delivers sufficient flow to the steam generators to avoid actuation of the passive core cooling system following a reactor trip. The maximum flow available from two operating startup feedwater pumps does not result in overcooling the reactor coolant system, overfilling the steam generators, or inputting excessive mass/energy to containment following a main steam line break.
The startup feedwater pumps use the condensate storage tank as a water supply source. A sufficient volume of feedwater is available from the condensate storage tank (refer to Subsection 9.2.4) to achieve cold shutdown, based on 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 and subsequent cooldown of the reactor coolant system within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to conditions which permit operation of the normal residual heat removal system.
The startup feedwater pumps are headered at the pump discharge, and a separate line runs from the header to each steam generator.
For a main feedwater or main steam line break (MSLB) inside the containment, the startup feedwater lines provide a nonsafety-related path for the addition of feedwater to the remaining intact loop if ac power is available.
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Two startup feedwater pumps are provided with a single pump capable of satisfying the startup feedwater system flow demand for decay heat removal. These pumps automatically start and maintain steam generator water level when the main feedwater system is unavailable.
In the event of loss of normal ac power, the startup feedwater pumps and associated motor operated isolation valves are powered by the onsite standby ac power supply (diesels). Each of the two startup feedwater pumps is powered by its respective standby diesel.
During normal plant startup, feedwater is supplied through the startup feedwater control valves to the steam generators until transition is made to the main feedwater control valves of the main feedwater system. During normal plant shutdown, feedwater is supplied through the startup feedwater control valves after transition is made from the main feedwater control valves, and until the normal residual heat removal system is placed in service.
4.9.2 System Description 4.9.2.1 General Description startup feedwater system is shown schematically in Figure 10.4.7-1 as part of the condensate feedwater system piping and instrument diagram and in Figure 10.3.2-1 as part of the main m system piping and instrument diagram. Classification of equipment and components is given ection 3.2.
tup feedwater is defined to be feedwater that passes through the startup feedwater control es, and can be supplied from either of two sources. Startup feedwater can be supplied by a ster/main feedwater pump drawing from the deaerator storage tank and delivering through cross nect piping to the startup feedwater header; or, startup feedwater can be supplied by one or both tup feedwater pumps drawing from the condensate storage tank and delivering to the startup water header. The startup feedwater header is defined to be the common segment of startup water piping downstream of the startup feedwater pumps. The booster/main feedwater pumps part of the condensate and feedwater system and are described in Subsection 10.4.7. As cribed in Subsection 10.4.7.2.1, the cross connection piping between the main feedwater pump harge header and the startup feedwater header contains a check valve and a nonsafety-related, operated isolation valve. The check valve prevents the startup feedwater pumps from supplying main feedwater header, and the isolation valve automatically closes upon a main feedwater ation signal to isolate the main feedwater system from the startup feedwater system.
parallel startup feedwater pumps are provided and take suction from the condensate storage
. Each startup feedwater pump discharges to the startup feedwater header through a venturi flow ment, an automatic recirculation valve, and a remotely-operated isolation valve. The venturi flow ment provides a flow measurement signal at normal flow rates, and cavitates at a flow rate near p runout to choke the flow and avoid further flow increase. The automatic recirculation valve tions as a check valve to prevent reverse flow through the pump, and also functions as a imum flow control valve for pump protection; during conditions of low forward flow to the system, cient flow from the pump is automatically recirculated back to the condensate storage tank to t pump minimum flow requirements. The discharge isolation valve is closed when the associated p is not operating; when in standby operation, the valve automatically opens when the ociated pump starts.
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trol valve to maintain level in the associated steam generator.
artup feedwater system failure analysis for safety-related components is presented in le 10.4.9-1.
4.9.2.2 Component Description m the connections at the steam generators out through the startup feedwater isolation valves, the tup feedwater system is designed in accordance with the requirements of ASME Code,Section III Class 2 components and seismic Category I requirements. From upstream of the startup water isolation valve to the restraints at the interface between the auxiliary building and turbine ding, the system is designed in accordance with ASME Code,Section III for Class 3 components seismic Category I requirements. The remaining portion of the startup feedwater system is safety-related.
rtup Feedwater Pump h startup feedwater pump is a multistage, centrifugal pump driven by an ac motor. Each pump supply 100 percent of the required flow to the two steam generators to meet the decay heat oval requirements specified in Subsection 10.4.9.1.2. The pumps automatically start as cribed in Subsection 10.4.9.2.3.4. Isolation valves at the pump suction and discharge allow each tup feedwater pump to be individually serviced. The discharge isolation valve for each pump is ered by the same train of the onsite standby ac power supply as the associated pump.
rtup Feedwater Control Valve startup feedwater control valves are air-operated, modulating control valves with the dual pose of controlling startup feedwater flow rate, as well as providing isolation of the startup water system. The valve body is a globe design that provides the required range of startup feed trol, as well as positive isolation. The startup feedwater control valves operator is equipped with uxiliary air accumulator to provide independent operation of the startup feedwater control valves n loss of normal instrument air supply.
startup feedwater control valves automatically maintain water level in the steam generators ng operation of the startup feedwater system, in response to signals generated by the plant trol system.
e event of a secondary side pipe rupture inside the containment, the startup feedwater control e provides a secondary backup to the startup feedwater isolation valve limiting the quantity igh-energy fluid that enters the containment through the broken pipe. For emergency closure of valve, a solenoid is deenergized, resulting in valve closure in sufficient time to limit the mass and rgy release to containment consistent with the containment analysis presented in Section 6.2.
electrical solenoid is energized from a Class 1E source.
rtup Feedwater Isolation Valve startup feedwater isolation valve is installed in each startup feedwater line outside containment downstream of a startup feedwater control valve and a startup feedwater check valve. The wing primary functions are performed by the valve:
The startup feedwater isolation valve is provided to prevent the uncontrolled blowdown from more than one steam generator in the event of startup feedwater line rupture. The startup feedwater control valve provides backup isolation.
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In the event of a secondary pipe rupture inside containment, the startup feedwater isolation valve and startup feedwater control valve provide isolation to limit the quantity of high energy fluid that enters the containment.
In the event of a steam generator tube rupture, the startup feedwater isolation valve and startup feedwater control valve limit overfill of the steam generator by terminating startup feed flow.
startup feedwater isolation valve is a remotely-operated gate valve designed in accordance with ME Code,Section III Class 2 requirements. The valve operator is designed to stroke against m generator pressure or startup feedwater pump shutoff head.
startup feedwater isolation valve and startup feedwater control valve functional diagrams are wn in Figure 7.2-1. To provide the safety function actuation (closure) as well as reliable nment, and redundant and independent actuation, the startup feedwater isolation valve and tup feedwater control valve are powered from separate Class 1E power sources.
4.9.2.3 System Operation startup feedwater system supplies the steam generators with feedwater during conditions of t startup, hot standby and shutdown, and during transients in the event of main feedwater system vailability. The startup feedwater system also supplies feedwater during low power operation er conditions when the startup feedwater control valves regulate the feedwater flow to the steam erators.
4.9.2.3.1 Startup ing reactor startup and at low power levels, feedwater is supplied to the steam generators through startup feedwater control valves using either the startup feedwater pumps drawing from the densate storage tank, or a booster/main feedwater pump drawing from the deaerator storage
. Refer to Subsection 10.4.7 for a description of the operation of the condensate and feedwater em and the booster/main feedwater pumps. The feedwater pumps in use operate on minimum recirculation as necessary while maintaining the water level of the steam generators. Feedwater ontrolled by the startup feedwater control valves, which are operated either manually from the trol room or automatically in accordance with steam generator level demand. If the startup water pumps are initially in use, transfer is made to a booster/main feedwater pump prior to eeding the capacity limit of the startup pumps. As power increases, feedwater continues to be plied through the startup feedwater control valves until control of feedwater is automatically sferred from the startup feedwater control valves to the main feedwater control valves. As the n feedwater control valves open and assume responsibility for maintaining steam generator water l, the startup feedwater control valves close. Position indication is available in the main control m for the main and startup feedwater control valves.
4.9.2.3.2 Hot Standby ing hot standby conditions, feedwater is supplied to the steam generators through the startup water control valves using either one or both startup feedwater pumps drawing from the densate storage tank, or a booster/main feedwater pump drawing from the deaerator storage
. The startup feedwater control valves operate to maintain the steam generator levels, and imum flow recirculation is automatically utilized as required to protect the feedwater pumps that in use.
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power ascent. At low feedwater flows, control of feedwater is automatically transferred from the n feedwater control valves to the startup feedwater control valves. Feedwater is supplied by an rating booster/main feedwater pump drawing from the deaerator storage tank. Feedwater can tinue to be supplied by a booster/main feedwater pump during the shutdown process; rnatively, feedwater supply can be transferred to the startup feedwater pumps when flow demand decreased to within their capacity. Feedwater continues to be supplied until the normal residual t removal system is placed in service.
4.9.2.3.4 Automatic Starts startup feedwater pumps automatically start upon conditions resulting from insufficient main water flow to the steam generators. An automatic pump start signal is generated by the plant trol system (PLS). The signal is generated on low main feedwater flow coincident with low steam erator level. As a backup to this logic, it is also initiated on steam generator level alone, at a oint below the low steam generator level setpoint.
amount of startup feedwater flow delivered to each steam generator is determined by the ociated startup feedwater control circuit, which sends a signal to modulate the startup feedwater trol valve (Figure 10.3.2-1) in response to steam generator water level control signals. The control e is modulated as required to maintain the programmed steam generator water level setpoint.
owing a reactor trip that is not the result of a main feedwater system malfunction and in which the n feedwater system remains available, the startup feedwater pumps do not automatically start. In case, the startup feedwater control valves take control and open to supply the steam generators g feedwater delivered from a booster/main feedwater pump through cross-connect piping. The tup feedwater pumps remain on standby for backup protection, and can be manually started if ired by the plant operator.
4.9.2.3.5 Emergency Operation startup feedwater system is not required to supply feedwater under accident conditions.
ever, the startup feedwater system is expected to be available as a nonsafety-related, first line of nse to provide a source of feedwater for the steam generators. Coordinated operation of the tup feedwater system (which starts automatically, as discussed in Subsection 10.4.9.2.3.4), if ilable, and the main steam supply system (refer to Section 10.3) are employed to remove the ary loop sensible heat and reactor decay heat. A minimum condensate storage tank volume 25,000 gallons is required for defense-in-depth purposes. The condensate storage tank size hown in Subsection 9.2.4.2.2.
4.9.3 Safety Evaluation The safety-related portions of the startup feedwater system are located in the containment and auxiliary buildings. These buildings are designed to withstand the effects of earthquakes, tornadoes, hurricanes, floods, external missiles, and other natural phenomena. Sections 3.3, 3.4, 3.5, 3.7, and 3.8 provide the bases for the adequacy of the structural design of these buildings.
The safety-related portions of the startup feedwater system are designed to remain functional after a design basis earthquake. Subsection 3.7.2 and Section 3.9 provide the design loading conditions that are considered. Sections 3.5, 3.6, and Subsection 9.5.1 provide the analyses 10.4-42 Revision 1
The startup feedwater system safety-related functions are accomplished by redundant means. A single, active component failure of the safety-related portion of the system does not compromise the safety function of the system. Table 10.4.9-1 provides a failure analysis of the safety-related active components of the startup feedwater system. Power is supplied from onsite power systems, as described in Chapter 8.
Preoperational testing of the safety-related portion of the condensate and feedwater system is performed as described in Chapter 14. Periodic inservice functional testing is done in accordance with Subsection 10.4.9.4. Section 6.6 provides the ASME Code,Section XI requirements that are appropriate for the startup feedwater system.
Section 3.2 delineates the quality group classification and seismic category applicable to the safety-related portion of this system and supporting systems. The controls and power supplies necessary for the safety-related functions of the startup feedwater system are Class 1E, as described in Chapters 7 and 8.
The startup feedwater isolation valves and the startup feedwater control valves automatically close upon receipt of a feedwater isolation signal, which occurs on a steam generator high-high water level and other appropriate engineered safeguards signals as shown on the diagrams titled Feedwater Isolation and Steam Line Isolation in Figure 7.2-1.
For a steam generator tube rupture event, positive and redundant isolation is provided for the startup feedwater system (startup feedwater isolation valve and startup feedwater control valve) to prevent steam generator overfill, with engineered safeguards isolation signals generated by the protection and safety monitoring system (PMS).
4.9.4 Tests and Inspections 4.9.4.1 Preoperational Valve Testing startup feedwater isolation valves and startup feedwater control valves are checked for closing prior to initial startup.
4.9.4.2 Preoperational Pipe Testing Class 2 portion of the startup feedwater system piping is tested and inspected to the uirements of ASME Code,Section III, Class 2 piping. In addition, the portion of the piping between containment penetration and the anchor, which is traditionally considered as the break exclusion e described in Subsection 3.6.2, is subjected to 100-percent volumetric inspection at installation t is, 100-percent volumetric examination of shop and field longitudinal and circumferential welds).
4.9.4.3 Preoperational System Testing operational testing of the startup feedwater system is performed as described in Chapter 14.
s described in Subsection 14.2.9.1.7, under item c) of General Test Method and Acceptance eria satisfy BTP (AS) 10-2. Additional testing of the startup feedwater system is conducted during tup testing as described in Subsection 14.2.10.4.18.
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demonstrated by normal operation.
inservice inspection program for ASME Section III Class 2 and 3 components is described in tion 6.6. The inservice testing program, including testing for the startup feedwater isolation valve startup feedwater control valve, is described in Subsection 3.9.6.
4.9.5 Instrumentation Applications startup feedwater system instrumentation is designed to facilitate automatic operation, remote trol, and continuous indication of system parameters.
startup feedwater flow is controlled by a steam generator level demand signal modulating the tup feedwater control valve. The control valve may either be in manual or automatic control. Refer ection 7.7. The startup feedwater flow transmitters also provide redundant indication of startup water and automatic safeguards actuation input on low flow coincident with low, narrow range m generator level. See Section 7.3.
4.10 Auxiliary Steam System auxiliary steam system (ASS) provides the steam required for plant use during startup, tdown, and normal operation. Steam is supplied from either the auxiliary boiler or the main steam em.
4.10.1 Design Basis 4.10.1.1 Safety Design Basis auxiliary steam system serves no safety-related function and therefore has no nuclear safety ign basis.
4.10.1.2 Power Generation Design Basis auxiliary steam system supplies steam required by the unit for a cold start of the main steam em and turbine-generator. Additionally, the auxiliary steam system provides steam for hot water ting. Main steam supplements the auxiliary steam header during startup and supplies the iliary steam header during normal operation. The auxiliary boiler provides steam to the header ng plant shutdown.
4.10.2 System Description 4.10.2.1 General Description auxiliary boiler is located in the turbine building. The system consists of steam generation ipment and distribution headers.
densate from the condensate storage tank is chemically treated and pumped to the auxiliary er deaerator where oxygen and non-condensables are removed using auxiliary steam. The iliary boiler feedwater pumps deliver condensate from the auxiliary boiler deaerator to the iliary boiler. A feedwater control valve, located in the feedwater piping, regulates water level in the iliary boiler. Feedwater flow is proportional to auxiliary boiler steaming rate. Steam generated by auxiliary boiler is supplied to the plant auxiliary steam distribution piping.
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er level in the auxiliary boiler deaerator is maintained by an automatic control valve in the densate supply and deaerator overflow piping. Makeup water is supplied from the demineralized er transfer and storage system.
4.10.2.2 Component Description iliary steam system component classification is as described in Section 3.2.
iliary Steam System and Boiler auxiliary steam boiler is an electric package boiler with a nominal net output capacity of roximately 100,000 pounds per hour of saturated steam at 195 psig. The system is protected overpressure by safety valves located on the boiler, boiler deaerator, and auxiliary steam der.
mps 100-percent capacity auxiliary boiler feedwater pumps are provided to feed the auxiliary steam er.
100-percent capacity auxiliary boiler makeup pumps maintain level in the boiler deaerator.
iliary Boiler Deaerator auxiliary boiler deaerator is a 100-percent-capacity deaerator which uses steam supplied by the iliary steam header. The auxiliary boiler deaerator steam blanket is controlled for preheating and erating boiler makeup water. The auxiliary boiler deaerator removes oxygen and non-densables from auxiliary boiler feedwater.
mical Treatment Components auxiliary boiler makeup water is treated with pH control and oxygen scavenging chemicals.
mical injections maintain proper water chemistry during operational conditions. Batch chemicals leaning and layup are injected into the auxiliary boiler and auxiliary boiler deaerator when they not in operation. Chemical feed equipment for the auxiliary steam system is part of the turbine nd chemical feed system (CFS) and is described in Subsection 10.4.11.
4.10.2.3 System Operation en in operation, the auxiliary steam system provides the following services:
Steam to the plant hot water heating system heat exchangers where water is heated and pumped to the heating system ventilation coils.
Steam for the condensate system deaerator when condensate heating occurs during preoperational cleanup of the condensate and feedwater system.
Sealing steam to the glands of the main turbine prior to the availability of main steam.
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Steam for blanketing of the MSR and feedwater heaters when main steam is not available.
rational safety features are provided within the system for the protection of plant personnel and ipment. The auxiliary steam system does not interface directly with nuclear process systems.
4.10.3 Safety Evaluation auxiliary steam system has no safety-related function and therefore requires no nuclear safety luation. High energy pipe rupture analysis is not required for the auxiliary steam system since e of the lines pass through areas where safety related equipment is located.
4.10.4 Tests and Inspections ing of the auxiliary steam system is performed prior to initial plant operation.
ponents of the system are monitored during operation to verify satisfactory performance.
4.10.5 Instrumentation Applications oiler control system is provided with the auxiliary boiler package for automatic control of the iliary boiler. Features of the control system include automatic shutdown of the auxiliary boiler on bnormal condition.
auxiliary steam system is provided with the necessary controls and indicators for local or remote itoring of the operation of the system.
4.11 Turbine Island Chemical Feed turbine island chemical feed system (CFS) injects required chemicals into the condensate S), feedwater (FWS), auxiliary steam (ASS), service water (SWS), and demineralized water tment (DTS). CFS components are located in the turbine building.
4.11.1 Design Basis 4.11.1.1 Safety Design Basis turbine island chemical feed system serves no safety-related function and therefore has no lear safety design basis.
4.11.1.2 Power Generation Design Basis oncorrosive condition is maintained within the systems serviced by the turbine island chemical system.
secondary sampling system (SSS), as described in Subsection 9.3.4, contains sampling uirements in accordance with water chemistry specifications that are provided in Table 10.3.5-1.
4.11.2 System Description ssification of equipment and components is given in Section 3.2.
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all-volatile chemical feed system (AVT) is used for condensate, feedwater and auxiliary steam er chemistry control. An oxygen scavenger is injected into the condensate system downstream of condensate polishers to control the dissolved oxygen level. Feedwater chemistry is controlled by ntaining a residual level of oxygen scavenger. The injection point for the feedwater oxygen venger is located upstream of the feedwater booster pump suction. A pH adjuster is also injected the condensate system downstream of the condensate polisher for pH control. Injection for pH trol of the feedwater is located upstream of the feedwater booster pump suction. Chemical feed ps and tanks are used to store and inject the chemicals into the piping system.
section 10.4.10.2.2 describes chemical feed for the auxiliary steam system.
vice Water ocide, pH adjuster, and dispersant/corrosion/scale inhibitor are injected into the service water em as required. An algicide can be fed to the service water cooling tower basins.
section 9.2.1.2.2 describes chemical feed for the service water system.
mineralized Water Treatment H adjuster and scale inhibitor are injected into the demineralized water treatment system.
section 9.2.3.2.3 describes chemical feed for the demineralized water treatment system.
4.11.2.2 System Operation ndensate, Feedwater and Auxiliary Steam System Chemistry Control oxygen scavenger is injected upstream of the feedwater booster pump suction to maintain a dual level of oxygen scavenger and a dissolved oxygen level of not more than 5 ppb at the inlet to steam generator.
H adjuster is also injected upstream of the feedwater booster pump suction to maintain the pH at steam generator inlet within the control program for pH.
oxygen scavenger is injected into the condensate system downstream of the condensate polisher aintain a dissolved oxygen level of not more than 10 ppb at the inlet of the deaerator.
H adjuster is injected into the condensate system downstream of the condensate polisher to ntain the pH above 9.0 at the deaerator inlet within the control program for pH.
chemical feed system may be used to place the steam generators in wet layup. This layup ess is accomplished using the chemical feed system in conjunction with the steam generator down system. Refer to Subsection 10.4.8.2 for details of this process.
oxygen scavenger and pH adjuster are injected into the auxiliary steam system downstream of boiler makeup pumps to maintain the dissolved oxygen level and pH within the auxiliary boiler gram levels. The chemical feed rates are manually adjusted.
vice Water System Chemistry Control ocide, pH adjuster and dispersant/corrosion/scale inhibitor are injected downstream of the ice water pumps as required. Chemical feed rates for the biocide and dispersant/corrosion/scale bitor are manually adjusted to maintain proper concentrations. The pH adjuster chemical feed is controlled electronically from instrumentation that measures pH.
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mineralized Water Treatment System Chemistry Control H adjuster and scale inhibitor are injected into the raw water supply to the demineralized water tment system upstream of the cartridge filters. The scale inhibitor feed rate is manually adjusted the pH adjuster chemical feed rate is controlled electronically from instrumentation that sures pH.
4.11.3 Safety Evaluation turbine island chemical feed system has no safety-related function and therefore requires no lear safety evaluation.
c gases, such as chlorine, are not used in the turbine island chemical feed system. The impact of c material on main control room habitability is addressed in Section 6.4.
4.11.4 Tests and Inspections turbine island chemical feed system is operationally checked before initial plant startup to verify per functioning of the feed systems and chemical sensors.
4.11.5 Instrumentation Applications secondary sampling system (SSS), as described in Subsection 9.3.4, provides instrumentation ch measures dissolved oxygen, oxygen scavenger residual, and pH for the condensate, water, and steam generator systems. These analyzers provide an indication of water quality and ts for either manual or automatic control of the condensate and feedwater systems oxygen venging and pH control chemical feed pumps. Grab samples are analyzed to provide input for ual adjustment of feed rates for the auxiliary steam system oxygen scavenging and pH control mical feed pumps. Wet layup operations are manually performed based on the results of the grab ple analysis.
b samples are analyzed to provide input for manual adjustment of feed rates for biocide, adjustment, and/or dispersant/corrosion/scale inhibitor chemicals for service water and ineralized water treatment.
4.12 Combined License Information 4.12.1 Circulating Water System configuration of the plant circulating water system including piping design pressure, the cooling er or other site-specific heat sink is addressed in Subsection 10.4.5.2.
4.12.2 Condensate, Feedwater and Auxiliary Steam System Chemistry Control oxygen scavenging agent and pH adjuster selection for the turbine island chemical feed system ddressed in Subsection 10.4.7.2.1.
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estic and human consumption, as specified in Subsection 9.2.5.2.1. No additional onsite tment is required for this supply of water.
4.13 References ASME Performance Test Code 19.11, 1970.
Heat Exchange Institute Performance Standard for Liquid Ring Vacuum Pumps.
American Water Works Association, Code 504-80, Rubber Seated Butterfly Valves.
. Nuclear Energy Institute, "Steam Generator Program Guidelines," NEI 97-06, Revision 2, May 2005.
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denser Data denser type Multipressure, Single pass well storage capacity 3 min t transfer 7,540 x 106 Btu/hr ign operating pressure (average of all shells) 2.9 in.-Hg ll pressure (design) 0 in.-Hg absolute to 15 psig ulating water flow 600,000 gpm er box pressure (design) 90 psig e-side inlet temperature 91°F roximate Tube-side temperature rise 25.2°F denser outlet temperature 116.2°F erbox material Carbon Steel denser Tube Data e material (main section) Titanium(1) e size 1 O.D. - 23 BWG e material (periphery) Titanium(1) e size 1 O.D. - 23 BWG e sheet material Titanium or Titanium Clad Carbon Steel(2) port plates Modular Design/Carbon Steel e:
For fresh water plants, an equivalent tube material such as 304L, 316L, 904L, or AL-6X may be substituted.
If one of the alternate tube materials is used, the tube sheet shall be carbon steel, clad with the same material as the tubes.
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Circulating Water System Components ulating Water Pump ntity Four per unit (includes one spare) w rate (gal/min) 210,000 hanical Draft Cooling Towers ntity Two per unit roach temperature (°F) 9 t temperature (°F) 113 let temperature (°F) 88 roximate Temperature range (°F) 25 w rate (gal/min) 614,600 t transfer (Btu/hr) 7,624 x 106 d velocity design (mph) 110 smic design criteria per Uniform Building Code 10.4-51 Revision 1
Component Failure Effect on Train Failure Effect on System Failure Effect on RCS SGS PL V057A 1a. Valve fails closed or fails to open on FW Train B available. None. Decay heat removal is maintained via (MFIV) command. Train A is not available for FW SFW Train A available. PRHR actuation on ESF signal. SFW flow to SG A. available to provide flow to SG A.
1b. Valve fails open or fails to close on Valve V250A (MFCV) provides backup None. RCS integrity is maintained by valve command. Trains A and B are available isolation to terminate feedwater flow. V058A/V250A available to prevent SG A for FW flow. Isolation function of V057A is Check valve V058A provides redundant blowdown. Decay heat removal available via not available. Redundant power division feedwater blowdown isolation from SG A; PRHR and SFW actuated by ESF signal. SG closure of MFIV provided for reliability; redundant containment isolation provided overfill protection provided by backup isolation backup isolation provided by V058A and by SG and feedwater line inside of V250A.
V250A. containment.
SGS PL V057B 2a. Same as except for SG B. FW Train A available. Same as 1a except for SG B.
(MFIV) SFW Train B available.
2b. Same as 1B except isolation function Same as 1b except for B train valves and Same as 1b except for B train valves and of V057B is not available. SG B. SG B.
SGS PL V250A 3a. Valve fails closed or fails to open on FW Train B available. None. Decay heat removal is maintained via (MFCV) command. Train A is not available for FW SFW Train A available. PRHR actuation on ESF signal. SFW flow to SG A. available to provide flow to SG A.
3b. Valve fails open or fails to close on Valve V057A (MFIV) provides backup None. RCS integrity is maintained by valve command. Trains A and B are available isolation to terminate feedwater flow. V057A and V058A closure to limit SG for FW flow without flow control to SG A. Check valve V058A and V057A provide blowdown. Decay heat removal available via Backup isolation provided by V058A and redundant feedwater blowdown isolation PRHR and SFW actuated by ESF signal. SG V057A. from SG A. SFW train A and B overfill protection provided by redundant available for decay heat removal. isolation of V057A.
SGS PL V250B 4a. Same as 3a, except for train B and Same as 3a except train B. Same as 3a except for SG B.
4b. Same as 3b, except for SG B and Same as 3b except valves V057B and Same as 3b except for V057B and V058B.
valves V057B and V058B. V058B and SG B.
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Component Failure Effect on Train Failure Effect on System Failure Effect on RCS SGS PL V255A 1a. Valve fails closed or fails to open on System is not available for SFW supply to None. Decay heat removal is maintained via (SFCV) command. SFW Flow is not available to SG A. PRHR actuation on ESF signal.
SG A.
1b. Valve fails open or fails to close on Downstream isolation valve V067A trips None. RCS integrity is maintained by V067A command. SFW flow is uncontrolled. closed on high SG level; system pumps closure and main feedwater isolation. SG are tripped on high SG level. overfill terminated by ESF closure of V067A.
SGS PL V225B 2a. Same as 1a except flow is not System is not available for SFW supply to None. Same as 1a.
(SFCV) available to SG B. SG B.
2b. Same as 1b. Same as 1b except valve V067B trips Same as 1b except RCS integrity is closed on high SG level. maintained by V067B and main feedwater isolation, and overfill terminated by closure of V067B.
SGS PL V067A 3a. Valve fails closed. SFW flow is not System is not available for SFW supply to None. Same as 1a.
(SFIV) available to SG A. SG A.
3b. Valve fails open. Isolation function of None. Valve V255A is automatically closed None. RCS integrity is maintained by V255A V067A is not available; backup isolation and SFW pumps tripped on an ESF signal. closure to limit cooldown; PRHR available for provided by V0255A and V256A. SG overfill protection provided by decay heat removal and SG overfill protection automatic isolation of V255A. provided by redundant isolation of V255A.
SGS PL V067B 4a. Same as 3a except flow not available Same as 3a except SFW supply not Same as 1a.
(SFIV) to SG B. available to SG B.
4b. Same as 3b. Same as 3b except reference valve is Same as 3b except reference valve is V255B.
V255B.
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rtup Feedwater Pump e Multi-stage, centrifugal er Electric Motor ntity 2 acity 520 gpm @ 80°F d 3250 ft or hp 800 10.4-54 Revision 1
10.4-55 Revision 1 Not Used 10.4-56 Revision 1
WLS 1&2 - UFSAR Figure represents system functional arrangement. Details internal to the system may differ as a result of implementation factors such as vendor-specific component requirements.
Figure 10.4.3-1 Gland Seal System Piping and Instrumental Diagram 10.4-57 Revision 1
re represents system functional arrangement.
ils internal to the system may differ result of implementation factors such as dor-specific component requirements.
Inside Turbine Building Figure 10.4.6-1 Condensate Polishing System Piping and Instrumentation Diagram (Typical) 10.4-58 Revision 1
WLS 1&2 - UFSAR Figure represents system functional arrangement. Details internal to the system may differ as a result of implementation factors such as vendor-specific component requirements.
Figure 10.4.7-1 (Sheet 1 of 4)
Condensate and Feedwater System Piping and Instrumentation Diagram 10.4-59 Revision 1
WLS 1&2 - UFSAR Figure represents system functional arrangement. Details internal to the system may differ as a result of implementation factors such as vendor-specific component requirements.
Figure 10.4.7-1 (Sheet 2 of 4)
Condensate and Feedwater System Piping and Instrumentation Diagram 10.4-60 Revision 1
WLS 1&2 - UFSAR Figure represents system functional arrangement. Details internal to the system may differ as a result of implementation factors such as vendor-specific component requirements.
Figure 10.4.7-1 (Sheet 3 of 4)
Condensate and Feedwater System Piping and Instrumentation Diagram 10.4-61 Revision 1
WLS 1&2 - UFSAR Figure represents system functional arrangement. Details internal to the system may differ as a result of implementation factors such as vendor-specific component requirements.
Figure 10.4.7-1 (Sheet 4 of 4)
Condensate and Feedwater System Piping and Instrumentation Diagram 10.4-62 Revision 1
WLS 1&2 - UFSAR Figure represents system functional arrangement. Details internal to the system may differ as a result of implementation factors such as vendor-specific component requirements.
Inside Turbine Building Figure 10.4.8-1 Steam Generator Blowdown System Piping and Instrumentation Diagram 10.4-63 Revision 1
WLS 1&2 - UFSAR Figure 10.4-201 Piping and Instrumentation Drawing, Circulating Water System 10.4-64 Revision 1